UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2006
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Texas 20-3940661
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Dr., Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of Class: Exchanges on Which Registered:
Common Stock, par value $.01 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes x No
--- ---
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes No x
---- ------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days. Yes x No
---- ----
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act).
Large accelerated filer x Accelerated filer Non-accelerated filer
---- ---- ----
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
Yes No X
----- ----
1
The aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of the
last business day of June 2006 was approximately $1,233,453,469.
The number of shares of common stock outstanding as of January 31, 2007 was
29,803,934.
Documents Incorporated by Reference
Document
Incorporated as to
Proxy Statement for the Annual Part II, Item 5
Meeting of Shareholders to be Part III, Items 10, 11, 12, 13 and 14
held May 8, 2007
2
Form 10-K
Swift Energy Company and Subsidiaries
10-K Part and Item No.
Page
Part I
Item 1. Business 4
Item 1A. Risk Factors 21
Item 1B. Unresolved Staff Comments 26
Item 2. Properties 7
Item 3. Legal Proceedings 29
Item 4. Submission of Matters to a Vote of
Security Holders 29
Part II
Item 5. Market for Registrant's Common
Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities (1) 29
Item 6. Selected Financial Data 30
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 33
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 46
Item 8. Financial Statements and
Supplementary Data 48
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 89
Item 9A. Controls and Procedures 89
Item 9B. Other Information 89
Part III
Item 10. Directors, Executive Officers and Corporate Governance (1) 90
Item 11. Executive Compensation (1) 90
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management and
Related Stockholders Matters (1) 90
Item 13. Certain Relationships and Related
Transactions, and Director Independence (1) 90
Item 14 Principal Accountant Fees and Services (1) 90
Part IV
Item 15 Exhibits and Financial Statement Schedules 91
(1) Incorporated by reference from Proxy Statement for the Annual Meeting.
of Shareholders to be held May 8, 2007.
3
PART I
Item 1. Business
See pages 25 and 26 for explanations of abbreviations and terms used
herein.
General
Swift Energy Company is engaged in developing, exploring, acquiring, and
operating oil and gas properties, with a focus on oil and natural gas reserves
onshore and in the inland waters of Louisiana and Texas and onshore in New
Zealand. Swift Energy was founded in 1979 and is headquartered in Houston,
Texas. At year-end 2006, we had estimated proved reserves of 816.8 Bcfe with a
PV-10 Value of $2.7 billion (PV-10 is a non-GAAP measure, see the section titled
"Oil and Natural Gas Reserves" in our Property section for a reconciliation of
this non-GAAP measure to the closest GAAP measure, the standardized measure).
Our proved reserves at year-end 2006 were comprised of approximately 50% crude
oil, 40% natural gas, and 10% NGLs; and 44% of our total proved reserves were
proved developed. Our proved reserves are concentrated 64% in Louisiana, 22% in
Texas, 13% in New Zealand, and 1% in other states.
We currently focus primarily on development and exploration of fields in
three domestic regions and in New Zealand:
o South Louisiana Region
Bay de Chene Area
Bayou Penchant Area
Bayou Sale Area
Cote Blanche Island Area
High Island Area
Horseshoe Bayou Area
Jeanerette Area
Lake Washington Area
o South Texas Region
AWP Olmos Area
o Toledo Bend Region
Brookeland Area
Masters Creek Area
South Bearhead Creek Area
o New Zealand Region
Rimu/Kauri Area
TAWN Area
Competitive Strengths and Business Strategy
Our competitive strengths, together with a balanced and comprehensive
business strategy, provide us with the flexibility and capability to achieve our
goals. Our primary goals for the next five years are to increase proved oil and
natural gas reserves at an average rate of 5% to 10% per year and to increase
production at an average rate of 7% to 12% per year.
Demonstrated Ability to Grow Reserves and Production
We have grown our proved reserves from 645.8 Bcfe to 816.8 Bcfe over the
five-year period ended December 31, 2006. Over the same period, our annual
production has grown from 44.8 Bcfe to 70.2 Bcfe and our annual net cash
provided by operations has increased from $139.9 million to $424.9 million. Our
4
growth in reserves and production over this five-year period has resulted
primarily from drilling activities and acquisitions in our four core regions.
More recently, we increased our production by 18% during 2006 as compared to our
hurricane affected 2005 production. During 2006, our total proved reserves
increased by 7%, primarily due to acquisitions of properties in our South
Louisiana region. Based on our long-term historical performance and our business
strategy going forward, we believe that we have the opportunities, experience,
and knowledge to grow both our reserves and production.
Balanced Approach to Growth
Our strategy is to increase our reserves and production through both
drilling and acquisitions, shifting the balance between the two activities in
response to market conditions and strategic opportunities. In general, we focus
on drilling in our anchor assets and diversity properties in each of our four
regions when oil and natural gas prices are strong. When prices weaken and the
per unit cost of acquisitions becomes more attractive, or a strategic
opportunity exists, we also focus on acquisitions. We believe this balanced
approach has resulted in our ability to grow in a strategically cost effective
manner. Over the five-year period ended December 31, 2006, we replaced 159% of
our production at an average cost of $2.76 per Mcfe. More recently, we replaced
178% of our 2006 production at an average cost of $4.29 per Mcfe. For 2007, we
are targeting total production to increase 7% to 10% and proved reserves to
increase 4% to 6% over 2006 levels.
Our 2007 capital expenditures are currently budgeted at $350 million to
$400 million, net of minor non-core dispositions and excluding any property
acquisitions.
Reserves Replacement Ratio and Reserves Replacement Cost
Historically we have added proved reserves through both our drilling and
acquisition activities. We believe that this strategy will continue to add
reserves for us over the long-term; however, external factors beyond our
control, such as adverse weather conditions, commodity market factors, and
governmental regulations, could limit our ability to drill wells and acquire
proved properties in the future. We calculate and analyze reserves replacement
ratios and costs to use as benchmarks against certain of our competitors. These
ratios and costs are limited in use by the inherent uncertainties in the
reserves estimation process, and other factors discussed below. We have included
below a listing of the vintages of our proved undeveloped reserves in the table
titled "Proved Undeveloped Reserves" and believe this table will provide an
understanding of the time horizon required to convert proved undeveloped
reserves to oil and gas production. Our reserves additions for each year are
estimates. Reserve volumes can change over time and therefore cannot be
absolutely known or verified until all volumes have been produced and a
cumulative production total for a well or field can be calculated. Many factors
will impact our ability to access these reserves, such as availability of
capital, commodity prices, new and existing government regulations, adverse
weather conditions, competition within our industry, the requirement of new or
upgraded infrastructure at the production site, and technological advances.
The reserves replacement ratio is calculated using reserves replacement
volumes divided by production volumes during a specific period. The reserves
replacement volumes used in this calculation are listed in the "Supplemental
Information (Unaudited)" section of this report, specifically in a table titled
"Supplemental Reserves Information." Within this table there are categories
titled "Revisions of previous estimates," "Purchases of minerals in place" and
"Extensions, discoveries, and other additions" which when added, total the
reserves replacement volumes. Production volumes are also listed in the same
table, and these production volumes are also used in the reserves replacement
ratio calculation.
The reserves replacement cost is calculated using reserves replacement
volumes divided into acquisition, exploration, and development costs incurred
during a specific period. Our acquisition, exploration, and development costs
are listed in the "Supplemental Information (Unaudited)" section of this report,
specifically in a table titled "Costs Incurred." Development costs as defined by
Securities and Exchange Commission rules include costs incurred to obtain access
to proved reserves and provide facilities for extracting, treating, gathering
and storing the oil and gas. Development costs thus include well drilling costs
for our development wells and facility costs, such as those facility and
platform costs we have incurred in our Lake Washington area over the past
several years. Costs incurred to explore and develop reserves may extend over
several years. We believe a reserves replacement cost estimate is more
meaningful when calculated over several periods. Future development costs from
prior years are included in this calculation to the extent that they have been
included in our actual costs incurred.
5
Concentrated Focus on Regions with Operational Control
The concentration of our operations in four regions allows us to leverage
our drilling unit and workforce synergies while minimizing the continued
escalation of drilling and completion costs. Our average lease operating costs,
excluding taxes, were $0.89, $0.79, and $0.71 per Mcfe in 2006, 2005, and 2004,
respectively. Each of our four regions includes at least one anchor asset,
previously termed a core area, and several diversity properties that are
targeted for future growth. This concentration allows us to utilize the
experience and knowledge we gain in these areas to continually improve our
operations and guide us in developing our future activities and in operating
similar type assets. For example, in our South Louisiana region, we will apply
the experience we have gained in Lake Washington to our Bay de Chene and Cote
Blanche Island properties acquired at the end of 2004, which are also situated
around salt domes. The value of this concentration is enhanced by our
operational control of 94% of our proved oil and natural gas reserves base as of
December 31, 2006. Retaining operational control allows us to more effectively
manage production, control operating costs, allocate capital, and time field
development.
Develop Under-Exploited Properties
We are focused on applying advanced technologies and recovery methods to
areas with known hydrocarbon resources to optimize our exploration and
exploitation of such properties as illustrated in our four regions. For
instance, the Lake Washington field was discovered in the 1930s. We acquired our
properties in this area for $30.5 million in 2001. Since that time, we have
increased our average daily net production from less than 700 BOE to 18,700 BOE
for the quarter ended December 31, 2006. We have also increased our proved
reserves in the area from 7.7 million BOE, or 46.2 Bcfe, to approximately 40.3
million BOE or 241.9 Bcfe, as of December 31, 2006. Additionally, on our
original 100,000 acre New Zealand permit, only two wells had been drilled at the
time that we acquired our interest in 1999 and since that time we have drilled
50 wells in New Zealand. When we first acquired our interests in AWP Olmos,
Brookeland, and Masters Creek, these areas also had significant additional
development potential. Our properties in the Bay de Chene and Cote Blanche
Island fields hold mainly proved undeveloped reserves and we began our initial
development activities of these properties in 2006. We intend to continue
acquiring large acreage positions where we can grow production by applying
advanced technologies and recovery methods using our experience and knowledge
developed in our four regions.
Maintain Financial Flexibility and Disciplined Capital Structure
We practice a disciplined approach to financial management and have
historically maintained a disciplined capital structure to provide us with the
ability to execute our business plan. As of December 31, 2006, our debt to
capitalization was approximately 32%, while our debt to proved reserves ratio
was $0.47 per Mcfe, and our debt to PV-10 ratio was 14%. We plan to maintain a
capital structure that provides financial flexibility through the prudent use of
capital, aligning our capital expenditures to our cash flows, and maintaining a
strategic hedging program. The combination of hedging with collars, floors,
forward sales, and the sale of our New Zealand natural gas production under
long-term, fixed-price contracts will provide for a more stable cash flow for
the periods covered as described in the "Commodity Risk" section of this report.
Experienced Technical Team
We employ 61 oil and gas professionals, including geophysicists,
petrophysicists, geologists, petroleum engineers, and production and reservoir
engineers, who have an average of approximately 24 years of experience in their
technical fields and have been employed by us for an average of over five years.
In addition, we engage experienced and qualified consultants to perform various
comprehensive seismic acquisitions, processing, reprocessing, interpretation,
and other related services. We continually apply our extensive in-house
experience and current technologies to benefit our drilling and production
operations.
6
We increasingly use seismic technology to enhance the results of our
drilling and production efforts, including two and three-dimensional seismic
acquisition, pre-stack image enhancement reprocessing, amplitude versus offset
datasets, coherency cubes, and detailed field reservoir depletion planning. In
2004, we completed our 3-D seismic survey covering our Lake Washington area. In
2006 we utilized this seismic data to drill all of our exploratory and
development wells. In 2005, we began a seismic program that encompasses 77
square miles in our Cote Blanche Island area, which was completed in 2006 and
analysis of this data will continue into 2007. We now have seismic data covering
4,000 square miles in South Louisiana that has been merged into two data sets,
inclusive of data covering five newly acquired fields that will form the base
dataset for our regional exploration and development program. This data will be
analyzed over the next several years feeding our acquisition and organic growth
led strategies. In New Zealand, we also acquired seismic on our offshore Kaheru
exploration permit in 2006.
We use various recovery techniques, including gas lift, water flooding, and
acid treatments to enhance crude oil and natural gas production. We also
fracture reservoir rock through the injection of high-pressure fluid, install
gravel packs, and insert coiled-tubing velocity strings to enhance and maintain
production. We believe that the application of fracturing and coiled-tubing
technology has resulted in significant increases in production and decreases in
completion and operating costs, particularly in our AWP Olmos area.
We also employ measurement-while-drilling techniques extensively in our
South Louisiana region, which allows us to guide the drill bit during the
drilling process. This technology allows the well bore path to be steered
parallel to the salt face and to intersect multiple targeted sands in a single
well bore.
Item 2. Properties
Operating Areas
The following table sets forth information regarding our 2006 year-end
proved reserves of 816.8 Bcfe and production of 70.2 Bcfe by field:
% of Year-End
2006 Proved % of 2006
Area Reserves Production
---- -------------- ----------
New Zealand................. 13% 19%
South Louisiana............. 53% 61%
South Texas................. 18% 12%
Toledo Bend................. 14% 6%
-------------- ----------
% of Total............ 98% 98%
7
Domestic Regional Focus Areas
Our domestic regions consist of three main regions located in South
Louisiana, South Texas and Toledo Bend, which straddles the Texas and Louisiana
border. South Texas is the oldest of our core regions, with our operations being
established in the AWP Olmos area in 1989. In mid-1998, we acquired the Masters
Creek and Brookeland areas in the Toledo Bend region, with South Bearhead Creek
being our most recent acquisition in this region during late 2005. In South
Louisiana, we established our operations when we acquired majority interests in
producing properties in the Lake Washington field in early 2001, adding Bay de
Chene and Cote Blanche Island in December 2004, and adding five fields in 2006:
Bayou Sale, Bayou Penchant, High Island, Horseshoe Bayou, and Jeanerette.
South Louisiana
Lake Washington Area. As of December 31, 2006, we owned drilling and
production rights in 21,690 net acres in the Lake Washington area located in
Plaquemines Parish in South Louisiana. Approximately 93% of our proved reserves
of 40.3 million BOE in this area at December 31, 2006, were oil and NGLs. To
date, we have primarily produced from multiple Miocene sands ranging in depth
from greater than 2,000 feet to 13,000 feet. The field is located on a salt dome
and has produced over 300 million BOE since its discovery in the 1930s. The area
around the dome is heavily faulted, thereby creating a large number of potential
traps. Oil and gas from approximately 146 producing wells is gathered to three
platforms located in water depths from two to 12 feet, with drilling and
workover operations performed with rigs on barges.
In 2006, we drilled 21 development wells, of which 18 wells were completed.
At year-end 2006, we had 109 proved undeveloped locations in this field. Our
planned 2007 capital expenditures in this area will focus on drilling from 24 to
26 wells, along with the construction of a facility on the west side of the
field to further improve the deliverability and efficiency in this area.
Bay de Chene and Cote Blanche Island Areas. Bay de Chene is located in
Jefferson Parish and Lafourche Parish, while Cote Blanche Island is located in
St. Mary Parish, both of which are in South Louisiana in close proximity to Lake
Washington. These fields hold predominantly undeveloped reserves. As of December
31, 2006, we owned drilling and production rights in 16,138 net acres in the Bay
de Chene field and 7,030 net acres in the Cote Blanche Island field, along with
options covering another 16,650 acres in the Cote Blanche Island field. At
year-end 2006, we had five proved undeveloped locations in the Bay de Chene
field and 26 in the Cote Blanche Island field. We drilled six development wells
in Bay de Chene in 2006, of which three were completed, and we drilled three
successful development wells in Cote Blanche Island. During 2007, we plan to
drill six to eight wells in Bay de Chene and up to two wells in Cote Blanche
Island, along with processing the 3-D seismic data that was shot in Cote Blanche
Island in 2006.
Newly Acquired South Louisiana Areas. In October 2006, we acquired
interests in five fields located in five primarily onshore South Louisiana
fields: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all located in St.
Mary Parish), High Island Field in Cameron Parish and Bayou Penchant Field in
Terrebonne Parish. Bayou Sale and Horseshoe Bayou fields are adjacent to each
other and located 13 miles southeast of our Cote Blanche Island field.
Production in these fields is from formations at depths ranging from 10,000 to
14,000 feet. The Bayou Penchant field was discovered in the 1930s and produces
from a number of Middle Miocene sands at depths of 7,000 to 10,000 feet. Bayou
Penchant is located approximately 44 miles southeast of Cote Blanche Island and
is a non-operated field with Swift holding a 50% working interest. The High
Island field is located 65 miles west of Cote Blanche Island and was discovered
in 1983. The Jeanerette field is positioned on the flank of a large salt dome
and approximately 12 miles north of Cote Blanche Island. Jeanerette Field
produces from the Planulina sands in the 10,000 feet to 15,000 feet depth range.
We plan to initiate an exploration and development program in 2007 to drill
proved undeveloped and probable locations, recomplete several wells, enhance
facilities and improve per unit operating costs in these five fields.
South Texas
AWP Olmos Area. As of December 31, 2006, we owned drilling and production
rights in 29,278 net acres in the AWP Olmos Area in South Texas. We have
extensive experience with low-permeability, tight-sand formations typical of
this area, having acquired our first acreage there in 1988. These reserves are
approximately 70% natural gas. At year-end 2006, we owned interests in and
operated 540 wells in this area producing oil and natural gas from the Olmos
sand formation at depths of approximately 9,000 to 11,500 feet. We own nearly
100% of the working interests in all these operated wells.
8
In 2006, we completed 14 development wells in this area, performed 26
fracture enhancements, but were unsuccessful on five very shallow exploration
wells which cost $0.5 million in the aggregate. At year-end 2006, we had 110
proved undeveloped locations. Our planned 2007 capital expenditures will focus
on drilling 10 to 12 wells in this area.
Toledo Bend
Brookeland Area. As of December 31, 2006, we owned drilling and production
rights in 79,593 net acres and 3,500 fee mineral acres in the Brookeland area.
This area is located in East Texas near the border of Louisiana in Jasper and
Newton counties. We primarily drill horizontal wells and produce from the Austin
Chalk formation in this area. The reserves are approximately 57% oil and natural
gas liquids. During 2006, we drilled one development well, which was successful.
At year-end 2006, we had ten proved undeveloped locations. Our planned 2007
capital expenditures in the Brookeland area include drilling one to two
development wells.
Masters Creek Area. As of December 31, 2006, we owned drilling and
production rights in 41,988 net acres and 91,594 fee mineral acres in the
Masters Creek area. This area is located in Central Louisiana near the
Texas-Louisiana border in the two parishes of Vernon and Rapides. It contains
horizontal wells producing both oil and gas from the Austin Chalk formation. The
reserves are approximately 69% oil and NGLs. At year-end 2006, we had nine
proved undeveloped locations. We do not plan on drilling any wells in this area
in 2007.
South Bearhead Creek Area. In November and December 2005, and then in
December 2006, we acquired interests in the South Bearhead Creek field, which is
located in the Toledo Bend region approximately 50 miles south of our Masters
Creek field and 30 miles north of Lake Charles, Louisiana. Oil and gas are
produced in this area predominantly from the upper and lower Wilcox sands at
depths ranging from approximately 10,600 to 14,100 feet. The field also has
production in the Cockfield sands at approximately 8,000 to 8,500 feet. South
Bearhead Creek field was discovered in 1958 by a major oil company. It is a
large east-west trending anticlinal closure and has had cumulative production of
over 4 million BOE.
In 2006, we drilled three development wells in the area, all of which were
successful. As of December 31, 2006, we owned drilling and production rights in
6,258 net acres in the South Bearhead Creek area. At year-end 2006, we had 19
proved undeveloped locations in this field. Our 2007 plans for this area include
two to four development wells and several recompletions.
Dispositions. In April 2006, we sold our minority interest in the natural
gas processing plant and related infrastructure that serves the Brookeland and
the Masters Creek areas within our Toledo Bend region. In December 2006, we sold
our interest in wells in the Garcia Ranch area within the South Texas region.
New Zealand Regional Focus Areas
Our New Zealand region contains two anchor assets, the Rimu/Kauri area and
the TAWN area. Our activity in New Zealand began in 1995. As of December 31,
2006, our exploration and production permits, all of which we operate, total
314,360 acres (182,381 net acres). Our 2007 planned activity in New Zealand
includes conducting a major 3-D seismic survey and possibly drilling two
development wells. Our infrastructure in New Zealand includes two
hydrocarbon-processing plants with significant excess capacity. We also own the
pipelines connecting the fields and facilities to export terminals and interior
markets.
Rimu/Kauri Area. Since 2002, we have held a 100% working interest in
petroleum mining permit 38151 covering approximately 4,552 acres in the Rimu
area for a primary term of 30 years. We were awarded a 30-year primary term
mining permit (PMP 38155) covering approximately 8,708 acres in the Kauri area
in April 2005. During 2006, we completed two out of three development wells in
the Kauri area and were unsuccessful with one exploratory well. One of the
development wells successfully targeted the Kauri and Tariki sands, and the
other was completed in the Manutahi sand. Our natural gas production from this
area is sold to Genesis Power Ltd. under a long-term contract for use at its
Huntly Power Station, New Zealand's largest thermal power station.
9
TAWN Area. Our interest in TAWN consists of a 100% working interest in four
petroleum mining permits, 38138 through 38141, covering producing oil and gas
fields and extensive associated hydrocarbon-processing facilities and pipelines.
The properties are collectively identified as the TAWN properties, an acronym
derived from the first letters of the field names - the Tariki field, the Ahuroa
field, the Waihapa field, and the Ngaere field. The four fields include 18 wells
where the purchaser of gas is Contact Energy. In 2006, we completed the Waihapa
H-1 development well in the Tikorangi sand in this area and were unsuccessful
with two exploratory wells, the Trapper and Goss. The TAWN assets are located
approximately 17 miles north of the Rimu/Kauri area.
Diversity Areas. A 152 square kilometer (59 square miles) marine 3-D
seismic survey was recorded in production exploration permit 38495 over the
Kaheru prospect, which is situated on the southern, offshore extension of the
productive Rimu-Kauri structural trend, as a precursor to the possible drilling
of an exploratory well on this prospect in 2008. We own 50% of this prospect.
In December 2004, we entered into a farm-in agreement with Ballance
Agri-Nutrients Limited of New Zealand for their exploration permit 38742. The
approximately 16,800 gross acre permit is located onshore in the north-central
Taranaki Basin. Under the terms of the contract, we became the operator of the
permit, and now have an 80% working interest. The Kowhai A-1 exploratory well
was drilled in this area in the second half of 2006 but was unsuccessful.
Summary of New Zealand Government Licenses and Permits
Our acreage in New Zealand is licensed from the New Zealand government
under production exploration permits (PEP), production mining licenses (PML),
and production mining permits (PMP). These licenses and permits as of December
31, 2006 are summarized in the following table:
Date of
Initial Interest Swift's
Permit Acquired Interest
PEP 38495 2005 50%
PEP 38742 2004 80%
PML 38138 2002 100%
PML 38139 2002 100%
PML 38140 2002 100%
PML 38141 2002 100%
PMP 38151 2002 100%
PMP 38155 2005 100%
Details of these licenses can be found on the New Zealand government's
Crown Minerals website at http://crownminerals.med.govt.nz/index.asp.
Oil and Natural Gas Reserves
The following tables present information regarding proved reserves of oil
and natural gas attributable to our interests in producing properties as of
December 31, 2006, 2005, and 2004. The information set forth in the tables
regarding reserves is based on proved reserves reports prepared by us and
audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent
petroleum engineers. Gruy has audited 100% of our proved reserves. Gruy's audit
was conducted according to standards approved by the Board of Directors of the
Society of Petroleum Engineers, Inc. and included examination, on a test basis,
of the evidence supporting our reserves. Gruy's audit was based upon review of
all available production histories and other geological, economic, and
engineering data, all of which were provided by us.
Estimates of future net revenues from our proved reserves and their PV-10
Value are made using oil and gas sales prices in effect as of the dates of such
estimates adjusted for the effects of hedging and are held constant, for that
year's reserves calculation, throughout the life of the properties, except where
such guidelines permit alternate treatment, including, in the case of gas
contracts, the use of fixed and determinable contractual price escalations. We
10
have interests in certain tracts that are estimated to have additional
hydrocarbon reserves that cannot be classified as proved and are not reflected
in the following tables. Our hedges at year-end 2006 consisted of natural gas
price floors with strike prices higher than the period-end price but did not
materially affect prices used in these calculations. The weighted averages of
such year-end 2006 prices domestically were $5.84 per Mcf of natural gas, $60.07
per barrel of oil, and $31.54 per barrel of NGL, compared to $10.36, $60.00, and
$33.28 at year-end 2005 and $5.87, $42.21, and $26.49 at year-end 2004,
respectively. The weighted averages of such year-end 2006 prices for New Zealand
were $3.59 per Mcf of natural gas, $63.51 per barrel of oil, and $26.84 per
barrel of NGL, compared to $3.79, $60.98, and $19.20 in 2005 and $3.07, $33.60,
and $20.48 in 2004, respectively. The weighted averages of such year-end 2006
prices for all our reserves, both domestically and in New Zealand, were $5.46
per Mcf of natural gas, $60.41 per barrel of oil, and $30.93 per barrel of NGL,
compared to $8.94, $60.12, and $31.40 in 2005 and $5.16, $41.07, and $25.48 in
2004, respectively.
The following tables set forth estimates of future net revenues presented
on the basis of unescalated prices and costs in accordance with criteria
prescribed by the Securities and Exchange Commission and their PV-10 Value as of
December 31, 2006, 2005, and 2004. Operating costs, development costs, asset
retirement obligation costs, and certain production-related taxes were deducted
in arriving at the estimated future net revenues. No provision was made for
income taxes. The estimates of future net revenues and their present value
differ in this respect from the standardized measure of discounted future net
cash flows set forth in supplemental information to our consolidated financial
statements, which is calculated after provision for future income taxes. We
combine NGLs with oil for reserves reporting purposes. PV-10 is a non-GAAP
measure; see the reconciliation of this non-GAAP measure to the closest GAAP
measure, the standardized measure, in the section below this table.
As of December 31, 2006
-------------------------------------------
Total Domestic New Zealand
------------- ------------- -----------
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed........................................................... 151,276 133,815 17,462
Proved undeveloped......................................................... 172,855 135,846 37,009
------------- ------------- -----------
Total..................................................................... 324,131 269,661 54,471
============= ============= ===========
Oil reserves (MBbl):
Proved developed........................................................... 34,956 33,346 1,611
Proved undeveloped......................................................... 47,163 40,119 7,044
------------- ------------- -----------
Total..................................................................... 82,119 73,465 8,655
============= ============= ===========
Total Estimated Reserves (Bcfe) 817 710 107
Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed........................................................... $ 1,382 $ 1,307 $ 75
Proved undeveloped......................................................... 1,326 1,137 189
------------- ------------- -----------
PV-10 Value............................................................... $ 2,708 $ 2,444 $ 264
============= ============= ===========
11
As of December 31, 2005
-------------------------------------------
Total Domestic New Zealand
------------- ------------- -----------
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed........................................................... 152,001 125,368 26,633
Proved undeveloped......................................................... 135,472 99,907 35,565
------------- ------------- -----------
Total..................................................................... 287,473 225,275 62,198
============= ============= ===========
Oil reserves (MBbl):
Proved developed........................................................... 37,990 35,298 2,691
Proved undeveloped......................................................... 41,063 34,485 6,579
------------- ------------- -----------
Total..................................................................... 79,053 69,783 9,270
============= ============= ===========
Total Estimated Reserves (Bcfe) 762 644 118
Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed........................................................... $ 1,721 $ 1,612 $ 109
Proved undeveloped......................................................... 1,450 1,248 202
------------- ------------- -----------
PV-10 Value............................................................... $ 3,171 $ 2,860 $ 311
============= ============= ===========
As of December 31, 2004
-------------------------------------------
Total Domestic New Zealand
------------- ------------- -----------
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed........................................................... 193,311 140,549 52,762
Proved undeveloped......................................................... 124,935 97,343 27,593
------------- ------------- -----------
Total..................................................................... 318,246 237,892 80,355
============= ============= ===========
Oil reserves (MBbl):
Proved developed........................................................... 42,038 36,629 5,409
Proved undeveloped......................................................... 38,229 32,510 5,719
------------- ------------- -----------
Total..................................................................... 80,267 69,139 11,128
============= ============= ===========
Total Estimated Reserves (Bcfe) 800 653 147
Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed........................................................... $ 1,182 $ 1,038 $ 144
Proved undeveloped......................................................... 839 760 79
------------- ------------- -----------
PV-10 Value............................................................... $ 2,021 $ 1,797 $ 224
============= ============= ===========
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserves reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimates. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserves estimates are often different
from the quantities of oil and gas that are ultimately recovered. There can be
no assurance that these estimates are accurate predictions of the present value
of future net cash flows from oil and gas reserves.
No other reports on our reserves have been required to be filed, nor have
any been filed with any federal agency.
12
The closest GAAP measure to PV-10, a non-GAAP measure, is the standardized
measure of discounted future net cash flows. We believe PV-10 is a helpful
measure in evaluating the value of our oil and gas reserves and many securities
analysts and investors use PV-10. We use PV-10 in our ceiling test computations,
and we also compare PV-10 against our debt balances. The following table is a
reconciliation between PV-10 and the standardized measure of discounted future
net cash flows:
As of December 31, 2006
------------------------------------------
Total Domestic New Zealand
------------- ------------- -----------
(In millions)
PV-10 Value $ 2,708 $ 2,444 $ 264
============= ============= ===========
Future income taxes (discounted at 10%).............................................. (800) (778) (22)
Asset retirement obligations (discounted at 10%)..................................... (39) (34) (5)
------------- ------------- -----------
Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas
reserves $ 1,869 $ 1,632 $ 237
============= ============= ===========
As of December 31, 2005
------------------------------------------
Total Domestic New Zealand
------------- ------------- -----------
(In millions)
PV-10 Value $ 3,171 $ 2,860 $ 311
============= ============= ===========
Future income taxes (discounted at 10%).............................................. (984) (942) (42)
Asset retirement obligations (discounted at 10%)..................................... (27) (23) (4)
------------- ------------- -----------
Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas
reserves $ 2,159 $ 1,895 $ 265
============= ============= ===========
As of December 31, 2004
------------------------------------------
Total Domestic New Zealand
------------- ------------- -----------
(In millions)
PV-10 Value $ 2,021 $ 1,797 $ 224
============= ============= ===========
Future income taxes (discounted at 10%).............................................. (533) (521) (12)
Asset retirement obligations (discounted at 10%)..................................... (23) (19) (4)
------------- ------------- -----------
Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas
reserves $ 1,465 $ 1,257 $ 208
============= ============= ===========
Proved Undeveloped Reserves
The following table sets forth the aging and PV-10 value of our proved
undeveloped reserves as of December 31, 2006:
PV-10
Volume % of PUD Value % of PUD
Year Added (Bcfe) Volumes (in millions) PV-10 Value
2006 111.9 25% $ 315.9 24%
2005 110.6 24% 406.5 31%
2004 58.4 13% 189.9 14%
2003 51.4 11% 171.4 13%
2002 40.3 9% 91.6 7%
Prior to 2002 83.2 18% 151.2 11%
-------------- ------------- ----------------- -------------------
Total 455.8 100% $ 1,326.5 100%
============== ============= ================= ===================
13
Sensitivity of Reserves to Pricing
As of December 31, 2006, a 5% increase in crude oil and NGL pricing would
increase our total estimated proved reserves of 816.8 Bcfe by approximately 0.6
Bcfe, and increase the total PV-10 Value of $2.7 billion by approximately $139
million. Similarly, a 5% decrease in crude oil and NGL pricing would decrease
our total estimated proved reserves by approximately 0.6 Bcfe and decrease the
total PV-10 Value by approximately $138 million.
As of December 31, 2006 a 5% increase in natural gas pricing (exclusive of
fixed contract volumes) would increase our total estimated proved reserves by
approximately 0.7 Bcfe and increase the total PV-10 Value by approximately $42
million. Similarly, a 5% decrease in natural gas pricing (exclusive of fixed
contract volumes) would decrease our total estimated proved reserves by
approximately 0.6 Bcfe and decrease the total PV-10 Value by approximately $42
million.
Oil and Gas Wells
The following table sets forth the gross and net wells in which we owned an
interest at the following dates:
Oil Wells Gas Wells Total Wells(1)
--------- --------- -------------
December 31, 2006:
Gross................................ 423 662 1,085
Net.................................. 353.4 562.4 915.8
December 31, 2005:
Gross................................ 402 565 967
Net.................................. 324.8 497.5 822.3
December 31, 2004:
Gross................................ 358 574 932
Net.................................. 308.8 525.9 834.7
(1) Excludes 51 service wells in 2006, 49 service wells in 2005, and 40
service wells in 2004.
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold
acreage held by us at December 31, 2006:
Developed(1) Undeveloped(1)
--------------------------- --------------------------
Gross Net Gross Net
------------ ------------ ------------ -----------
Alabama...................................... 9,045 2,588 124 80
Alaska....................................... --- --- 45,301 15,994
Louisiana.................................... 126,472 106,133 48,376 43,464
Texas........................................ 129,997 90,165 18,271 13,239
SWyoming..................................... 640 151 35,771 33,975
All other states............................. 320 266 400 258
Offshore Louisiana........................... 4,609 277 5,000 258
------------ ------------ ------------ -----------
Total Domestic............................. 271,083 199,580 153,243 107,268
New Zealand.................................. 9,960 9,912 304,400 172,469
------------ ------------ ----------- -----------
Total..................................... 281,043 209,492 457,643 279,737
============ ============ ============ ===========
(1) Fee mineral acres acquired in the Brookeland and Masters Creek areas
acquisition are not included in the above leasehold acreage table. We have
26,345 developed fee mineral acres and 68,689 undeveloped fee mineral acres
for a total of 95,034 fee mineral acres.
Drilling Activities
The following table sets forth the results of our drilling activities during
the three years ended December 31, 2006:
14
for a total of 95,034 fee mineral areas
Gross Wells Net Wells
---------------------------- -----------------------------
Year Type of Well Total Producing Dry Total Producing Dry
---- -------------------- ----- --------- ------- ------ --------- --------
2006 Exploratory -- Domestic 6 -- 6 5.5 -- 5.5
Development -- Domestic 49 42 7 47.6 40.6 7.0
Exploratory -- New Zealand 4 -- 4 4.0 -- 4.0
Development -- New Zealand 4 3 1 4.0 3.0 1.0
2005 Exploratory -- Domestic 9 5 4 9.0 5.0 4.0
Development -- Domestic 45 37 8 44.3 36.3 8.0
Exploratory -- New Zealand 5 1 4 3.7 1.0 2.7
Development -- New Zealand 5 2 3 5.0 2.0 3.0
2004 Exploratory -- Domestic 10 4 6 7.5 2.3 5.2
Development -- Domestic 44 37 7 41.7 35.0 6.7
Exploratory -- New Zealand 1 -- 1 1.0 -- 1.0
Development -- New Zealand 11 10 1 11.0 10.0 1.0
Operations
We generally seek to be the operator of the wells in which we have a
significant economic interest. As operator, we design and manage the development
of a well and supervise operation and maintenance activities on a day-to-day
basis. We do not own drilling rigs or other oil field services equipment used
for drilling or maintaining wells on properties we operate. Independent
contractors supervised by us provide this equipment and personnel. We employ
drilling, production, and reservoir engineers, geologists, and other specialists
who work to improve production rates, increase reserves, and lower the cost of
operating our oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement. These agreements usually provide for reimbursement of the
operator's direct expenses and for payment of monthly per-well supervision fees.
Supervision fees vary widely depending on the geographic location and depth of
the well and whether the well produces oil or natural gas. The fees for these
activities in 2006 totaled $8.8 million and ranged from $529 to $2,345 per well
per month.
Marketing of Production
Domestically, we typically sell our oil and natural gas production at
market prices near the wellhead or at a central point after gathering and/or
processing. We usually sell our natural gas in the spot market on a monthly
basis, while we sell our oil at prevailing market prices. We do not refine any
oil we produce. In 2005 and 2006, several companies accounted for 10% or more of
our total revenues. Shell Oil Company and its affiliates, both domestically and
in New Zealand, accounted for approximately 30% and 42% of our total oil and gas
sales in 2006 and 2005, respectively. In 2006, Chevron and its domestic
affiliates accounted for 32% of our total oil and gas sales. However, due to the
demand for oil and gas and availability of other purchasers, we do not believe
that the loss of any single oil or gas purchaser or contract would materially
affect our revenues.
Our oil production from the Lake Washington area is delivered into
ExxonMobil's crude oil pipeline system or transported on barges for sales to
various purchasers at prevailing market prices or at fixed prices tied to the
then current NYMEX crude oil contract for the applicable month(s). Our natural
gas production from this area is either consumed on the lease or is delivered
into El Paso's Tennessee Gas Pipeline system and then sold in the spot market at
prevailing prices.
15
In 1998, we entered into gas processing and gas transportation agreements
for our natural gas production in the AWP Olmos area with PG&E Energy Trading
Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and
El Paso Industrial, LP, and then assumed by Enterprise Hydrocarbons L.P. in
September 2004, for up to 75,000 Mcf per day, which provided for a ten-year term
with automatic one-year extensions unless terminated earlier. We believe that
these arrangements adequately provide for our gas transportation and processing
needs in the AWP Olmos area for the foreseeable future.
In the Toledo Bend area, our oil production from the Brookeland, Masters
Creek and South Bearhead Creek areas is sold to various purchasers at prevailing
market prices. Our natural gas production from the Brookeland and Masters Creek
areas is processed under long term gas processing contracts with Eagle Rock
Operating, LLC. The processed liquids and residue gas production are sold in the
spot market at prevailing prices. South Bearhead Creek gas production is sold
into the interstate market on Trunkline Gas Company's pipeline at prevailing
market prices.
Our oil production from the Bay de Chene and Cote Blanche Island fields is
transported on barges for sales to various purchasers at prevailing market
prices. Gas production from both fields is sold into intrastate pipelines with
prices tied to monthly and daily gas price indices.
In the newly acquired fields of Bayou Sale, Horseshoe Bayou, High Island
and Jeanerette in south Louisiana, we market our own production and sell the oil
production to various purchasers at prevailing market prices. Bayou Sale and
Horseshoe Bayou oil production is delivered into Plains All-American pipeline.
Oil production from High Island and Jeanerette fields is transported to market
by truck. Gas production for each of these fields is sold into one or more
interstate pipelines at prevailing market prices.
Through 2006, our oil production in New Zealand was sold to BP with prices
tied to the Asia Petroleum Price Index (APPI) Tapis posting.
Our natural gas production from our TAWN fields is sold under a long-term
fixed price contract with Contact Energy. Our natural gas production from the
Rimu field is sold to Genesis Power Ltd. under a long-term fixed price contract
that was modified in 2006 and covers approximately 7.2 Bcfe per year for a
three-year period. During 2006, additional production volumes from our fields,
over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at
prevailing market rates.
Production of NGLs in New Zealand is sold to Rockgas Ltd. under long-term
contracts tied to New Zealand's domestic natural gas liquids market.
The following table summarizes sales volumes, sales prices, and production
cost information for our net oil and natural gas production for the three-year
period ended December 31, 2006:
Year Ended December 31,
-----------------------------------
2006 2005 2004
---- ---- ----
Net Sales Volume:
Oil (MBbls)(1)...................................... 7,190 5,159 4,722
Natural Gas Liquids (MBbls)(2)...................... 713 838 1,040
Natural gas (MMcf)(3)............................... 22,788 23,609 23,742
Total (MMcfe)...................................... 70,205 59,590 58,319
Average Sales Price:
Oil (Per Bbl)(1)....................................$ 64.47 $ 53.63 $ 40.24
Natural Gas Liquids (Per Bbl)(2)....................$ 32.15 $ 28.04 $ 22.52
Natural gas (Per Mcf)(3)............................$ 5.05 $ 5.23 $ 4.12
Average Production Cost (Per Mcfe)....................$ 1.82 $ 1.50 $ 1.23
------------
16
(1) Oil production for 2006, 2005, and 2004 includes New Zealand production of
468,813 barrels at an average price per barrel of $67.06, 449,994 barrels at
an average price per barrel of $55.57, and 452,753 barrels at an average
price per barrel of $42.15, respectively.
(2) Natural gas liquids production for 2006, 2005 and 2004 includes New Zealand
production of 252,666 barrels at an average price of $20.22 per barrel,
329,377 barrels with an average price of $18.84 per barrel, and 350,303
barrels with an average price of $17.96 per barrel.
(3) Natural gas production for 2006, 2005 and 2004 includes New Zealand
production of 9,184,359 Mcf with an average price of $2.99 per Mcf,
11,869,757 Mcf with an average price of $3.09 per Mcf, and 11,441,954 Mcf
with an average price of $2.38 per Mcf.
17
Risk Management
Our operations are subject to all of the risks normally incident to the
exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, fires, and adverse weather conditions,
each of which could result in severe damage to or destruction of oil and gas
wells, production facilities or other property, or individual injuries. The oil
and gas exploration business is also subject to environmental hazards, such as
oil spills, gas leaks, and ruptures and discharges of toxic substances or gases
that could expose us to substantial liability due to pollution and other
environmental damage. See "1A. Risk Factors" of this report for more details and
for discussion of other risks. We maintain comprehensive insurance coverage,
including general liability insurance, officer and director liability insurance,
and property damage insurance. Prior to and at the time of Hurricanes Katrina
and Rita, we maintained business interruption insurance as well. Since such
time, the cost of such business interruption insurance coverage increased to a
level that we believe makes it uneconomical to maintain at this time. We believe
that our insurance is adequate and customary for companies of a similar size
engaged in comparable operations, but if a significant accident or other event
occurs that is uninsured or not fully covered by insurance, it could adversely
affect us.
Commodity Risk
The oil and gas industry is affected by the volatility of commodity prices.
Realized commodity prices received for such production are primarily driven by
the prevailing worldwide price for crude oil and spot prices applicable to
natural gas. We have a price-risk management policy to use derivative
instruments to protect against declines in oil and gas prices, mainly through
the purchase of price floors and collars. At December 31, 2006, we had price
floors in place through the March 2007 contract month for natural gas; these
cover a portion of our domestic natural gas production for February 2007 to
March 2007. The natural gas price floors cover notional volumes of 800,000
MMBtu, with a weighted average floor price of $7.00 per MMBtu. Our natural gas
price floors in place at December 31, 2006 are expected to cover approximately
25% to 30% of our domestic natural gas production from February 2007 to March
2007.
Competition
We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for equipment, labor, and materials required to develop
and operate such properties. Many of these competitors have financial and
technological resources substantially greater than ours. The market for oil and
gas properties is highly competitive and we may lack technological information
or expertise available to other bidders. We may incur higher costs or be unable
to acquire and develop desirable properties at costs we consider reasonable
because of this competition. Our ability to replace and expand our reserves base
depends on our continued ability to attract and retain quality personnel and
identify and acquire suitable producing properties and prospects for future
drilling and acquisition.
Regulations
Environmental Regulations
Our domestic exploration, production, and marketing operations are subject
to complex and stringent federal, state, and local laws and regulations
governing the discharge of substances into the environment or otherwise relating
to environmental protection. These laws and regulations may require the
acquisition of a permit by operators before drilling commences, prohibit
drilling activities on certain lands lying within wilderness areas, wetlands,
and other ecologically sensitive and protected areas, and impose substantial
remedial liabilities for pollution resulting from drilling operations. Failure
to comply with these laws and regulations may result in the assessment of
administrative, civil, and criminal penalties, the imposition of significant
investigatory or remedial obligations, and the imposition of injunctive relief
that limits or prohibits our operations. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent and
costly waste handling, storage, transport, disposal, or cleanup requirements
could materially adversely affect our operations and financial position, as well
as those of the oil and gas industry in general. While we believe that we are in
substantial compliance with current environmental laws and regulations and have
not experienced any material adverse effect from such compliance, there is no
assurance that this trend will continue in the future.
18
We currently own or lease, and have in the past owned or leased, numerous
properties in connection with our domestic operations that have been used for
the exploration and production of oil and gas for many years. Although we have
used operation and disposal practices that were standard in the industry at the
time, petroleum hydrocarbons or other wastes may have been disposed or released
on or under the properties owned or leased by us or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of petroleum hydrocarbons or other wastes was not under our control.
These properties and the wastes disposed thereon or away from could be subject
to stringent and costly investigatory or remedial requirements under applicable
laws, some of which are strict liability laws without regard to fault or the
legality of the original conduct, including the federal Comprehensive
Environmental Response, Compensation, and Liability Act, also known as "CERCLA"
or the "Superfund" law, the federal Resource Conservation and Recovery Act or
"RCRA," the federal Clean Water Act, the federal Clean Air Act, the federal Oil
Pollution Act or "OPA," and analogous state laws. Under such laws and any
implementing regulations, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or
operators) or property contamination (including groundwater contamination), to
perform natural resource mitigation or restoration practices, or to perform
remedial plugging or closure operations to prevent future contamination. In
addition, it is not uncommon for neighboring landowners and other third parties
to file claims for personal injury or property damages allegedly caused by the
release of petroleum hydrocarbons or other wastes into the environment.
Our domestic operations offshore in the Gulf of Mexico are subject to OPA,
which imposes a variety of requirements related to the prevention of oil spills,
and liability for damages resulting from such spills in United States waters.
The OPA imposes strict, joint and several liability on responsible parties for
oil removal costs and a variety of public and private damages, including natural
resource damages. Liability limits for offshore facilities require a responsible
party to pay all removal costs, plus up to $75 million in other damages. These
liability limits do not apply, however, if the spill was caused by gross
negligence or willful misconduct of the party, if the spill resulted from
violation of a federal safety, construction or operation regulation, or if the
party fails to report the spill or cooperate fully in any resulting cleanup. The
OPA also requires a responsible party at an offshore facility to submit proof of
its financial ability to cover environmental cleanup and restoration costs that
could be incurred in connection with an oil spill. We believe our operations are
in substantial compliance with OPA requirements.
Our operations in New Zealand could also potentially be subject to similar
foreign governmental controls and restrictions pertaining to protection of human
health and the environment. These controls and restrictions may include the need
to acquire permits, prohibitions on drilling in certain environmentally
sensitive areas, performance of investigatory or remedial actions for any
releases of petroleum hydrocarbons or other wastes caused by us or prior
operators, closure and restoration of facility sites, and payment of penalties
for violations of applicable laws and regulations. While we believe that we are
in substantial compliance with current environmental laws and regulations in New
Zealand, and have not experienced any material adverse effect from such
compliance, there is no assurance that this trend will continue in the future.
United States Federal, State and New Zealand Regulation of Oil and Natural Gas
The transportation and certain sales of natural gas in interstate commerce
are heavily regulated by agencies of the federal government and are affected by
the availability, terms and cost of transportation. The price and terms of
access to pipeline transportation are subject to extensive federal and state
regulation. The Federal Energy Regulatory Commission ("FERC") is continually
proposing and implementing new rules and regulations affecting the natural gas
industry, most notably interstate natural gas transmission companies that remain
subject to the FERC's jurisdiction. The stated purpose of many of these
regulatory changes is to promote competition among the various sectors of the
natural gas industry. Some recent FERC proposals may, however, adversely affect
the availability and reliability of interruptible transportation service on
interstate pipelines.
Our sales of crude oil, condensate and NGLs are not currently subject to
FERC regulation. However, the ability to transport and sell such products is
dependent on certain pipelines whose rates, terms and conditions of service are
subject to FERC regulation.
Production of any oil and gas by us will be affected to some degree by
state regulations. Many states in which we operate have statutory provisions
regulating the production and sale of oil and gas, including provisions
regarding deliverability. Such statutes, and the regulations promulgated in
19
connection therewith, are generally intended to prevent waste of oil and gas and
to protect correlative rights to produce oil and gas between owners of a common
reservoir. Certain state regulatory authorities also regulate the amount of oil
and gas produced by assigning allowable rates of production to each well or
proration unit, which could restrict the rate of production below the rate that
a well would otherwise produce in the absence of such regulation. In addition,
certain state regulatory authorities can limit the number of wells or the
locations where wells may be drilled. Any of these actions could negatively
affect the amount or timing of revenues. Likewise, the government of New Zealand
regulates the exploration, production, sales, and transportation of oil and
natural gas.
Federal Leases
Some of our domestic properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and administrative orders affect the terms of
leases, and in turn may affect our exploration and development plans, methods of
operation, and related matters.
Litigation
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and gas
wells. In our opinion, the outcome of any such currently pending legal actions
will not have a material adverse effect on our financial position or results of
operations.
Employees
At December 31, 2006, we employed 345 persons. Of these employees, 73 were
in New Zealand, including two expatriate employees. Eight of our New Zealand
employees are members of a union. None of our other employees are represented by
a union. Relations with employees are considered to be good.
Facilities
At December 31, 2006, we occupied approximately 124,000 square feet of
office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease
expiring in 2015. The lease requires payments of approximately $240,000 per
month. In New Zealand we leased approximately 18,400 square feet of office
space, under leases expiring in 2008 and 2009. These New Zealand leases require
payments of approximately $20,000 per month. We also have field offices in
various locations from which our employees supervise local oil and gas
operations.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, amendments to those reports, changes in and stock ownership
of our directors and executive officers, together with other documents filed
with the Securities and Exchange Commission under the Securities Exchange Act
can be accessed free of charge on our web site at www.swiftenergy.com as soon as
reasonably practicable after we electronically file these reports with the SEC.
All exhibits and supplemental schedules to these reports are available free of
charge through the SEC web site at www.sec.gov. In addition, we have adopted a
Code of Ethics for Senior Financial Officers and Principal Executive Officer. We
have posted this Code of Ethics on our website, where we also intend to post any
waivers from or amendments to this Code of Ethics.
20
Item 1A. Risk Factors
The nature of the business activities conducted by Swift Energy subjects it
to certain hazards and risks. The following is a summary of some of the material
risks relating to our business activities. Other risks are described in Items 1
and 2 Business and Properties "Competition" and "Regulations" and "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk."
Our oil and gas exploration and production business involves high risks and
we may suffer uninsured losses.
These risks include blowouts, explosions, adverse weather effects and
pollution and other environmental damage, any of which could result in
substantial losses to the Company due to injury or loss of life, damage to or
destruction of wells, production facilities or other property, clean-up
responsibilities, regulatory investigations and penalties and suspension of
operations. Increased hurricane activity over the past two years has resulted in
production curtailments and physical damage to the Company's Gulf Coast
operations. Although the Company currently maintains insurance coverage that it
considers reasonable and that is similar to that maintained by comparable
companies in the oil and gas industry, it is not fully insured against certain
of these risks, either because such insurance is not available or because of the
high premium costs and deductibles associated with obtaining such insurance.
Oil and natural gas prices are volatile. A substantial decrease in oil and
natural gas prices would adversely affect our financial results.
Our future revenues, net income, cash flow, and the value of our oil and
natural gas properties depend primarily upon market prices for oil and natural
gas. Oil and natural gas prices historically have been volatile and will likely
continue to be volatile in the future. The recent record high oil and natural
gas prices may not continue and could drop precipitously in a short period of
time. The prices for oil and natural gas are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty, worldwide economic conditions, weather
conditions, currency exchange rates, and political conditions in major oil
producing regions, especially the Middle East. A significant decrease in price
levels for an extended period would negatively affect us in several ways:
o our cash flow would be reduced, decreasing funds available for capital
expenditures employed to increase production or replace reserves;
o certain reserves would no longer be economic to produce, leading to both
lower cash flow and proved reserves;
o our lenders could reduce the borrowing base under our bank credit facility
because of lower oil and natural gas reserves values, reducing our
liquidity and possibly requiring mandatory loan repayments; and
o access to other sources of capital, such as equity or long term debt
markets, could be severely limited or unavailable in a low price
environment.
Consequently, our revenues and profitability would suffer.
Our level of debt could reduce our financial flexibility, and we currently
have the ability to incur substantially more debt, including secured debt.
As of December 31, 2006, our total debt comprised approximately 32% of our
total capitalization. Although our bank credit facility and indentures limit our
ability and the ability of our restricted subsidiaries to incur additional
indebtedness, we will be permitted to incur significant additional indebtedness,
including secured indebtedness, in the future if specified conditions are
satisfied. All borrowings under our bank credit facility are effectively senior
to our outstanding 7-5/8% senior notes and 9-3/8% senior subordinated notes to
the extent of the value of the collateral securing those borrowings. Our level
of indebtedness could negatively affect us in several ways:
21
o require us to dedicate a substantial portion of our cash flow to the
payment of interest;
o subject us to a higher financial risk in an economic downturn due to
substantial debt service costs;
o limit our ability to obtain financing or raise equity capital in the
future; and
o place us at a competitive disadvantage to the extent that we are more
highly leveraged than some of our peers.
Higher levels of indebtedness would increase these risks.
Estimates of poved reserves are uncertain, and revenues from production may
vary significantly from expectations.
The quantities and values of our proved reserves included in this report
are only estimates and subject to numerous uncertainties. Estimates by other
engineers might differ materially. The accuracy of any reserves estimate is a
function of the quality of available data and of engineering and geological
interpretation. These estimates depend on assumptions regarding quantities and
production rates of recoverable oil and natural gas reserves, future prices for
oil and natural gas, timing and amounts of development expenditures and
operating expenses, all of which will vary from those assumed in our estimates.
These variances may be significant.
Any significant variance from the assumptions used could result in the
actual amounts of oil and natural gas ultimately recovered and future net cash
flows being materially different from the estimates in our reserves reports. In
addition, results of drilling, testing, production, and changes in prices after
the date of the estimates of our reserves may result in substantial downward
revisions. These estimates may not accurately predict the present value of net
cash flows from our oil and natural gas reserves.
At December 31, 2006, approximately 56% of our estimated proved reserves
were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling operations. The
reserves data assumes that we can and will make these expenditures and conduct
these operations successfully, which may not occur.
If we cannot replace our reserves, our revenues and financial condition
will suffer.
Unless we successfully replace our reserves, our long- term production will
decline, which could result in lower revenues and cash flow. When oil and
natural gas prices decrease, our cash flow decreases, resulting in less
available cash to drill and replace our reserves and an increased need to draw
on our bank credit facility. Even if we have the capital to drill, unsuccessful
wells can hurt our efforts to replace reserves. Additionally, lower oil and
natural gas prices can have the effect of lowering our reserves estimates and
the number of economically viable prospects that we have to drill.
Drilling wells is speculative and capital intensive.
Developing and exploring properties for oil and natural gas requires
significant capital expenditures and involves a high degree of financial risk,
including the risk that no commercially productive oil or gas reservoirs will be
encountered. The budgeted costs of drilling, completing, and operating wells are
often exceeded and can increse significantly when drilling costs rise. Drilling
may be unsuccessful for many reasons, including title problems, weather, cost
overruns, equipment shortages, and mechanical difficulties. Moreover, the
successful drilling or completion of an oil or gas well does not ensure a profit
on investment. Exploratory wells bear a much greater risk of loss than
development wells.
We may incur substantial losses and be subject to substantial liability
claims as a result of our oil and natural gas operations.
22
We are not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition, or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the
possibility of:
o hurricanes or tropical storms;
o environmental hazards, such as uncontrollable flows of oil, natural gas,
brine, well fluids, toxic gas, or other pollution into the environment,
including groundwater and shoreline contamination;
o abnormally pressured formations;
o mechanical difficulties, such as stuck oil field drilling and service.
tools and casing collapse;
o fires and explosions;
o personal injuries and death; and
o natural disasters.
Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses. We may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect our financial condition.
We have incurred a write-down of the carrying values of our properties in
the past and could incur additional write-downs in the future.
Under the full cost method of accounting, SEC accounting rules require that
on a quarterly basis we review the carrying value of our oil and gas properties
on a country-by-country basis for possible write-down or impairment. Under these
rules, capitalized costs of proved reserves may not exceed a ceiling calculated
as the present value of estimated future net revenues from those proved
reserves, determined using a 10% per year discount and unescalated prices in
effect as of the end of each fiscal quarter. Capital costs in excess of the
ceiling must be permanently written down.
Substantial acquisitions or other transactions could require significant
external capital and could change our risk and property profile.
To finance acquisitions, we may need to substantially alter or increase our
capitalization through the use of our bank credit facility, the issuance of debt
or equity securities, the sale of production payments, or by other means. These
changes in capitalization may significantly affect our risk profile.
Additionally, significant acquisitions or other transactions can change the
character of our operations and business. The character of the new properties
may be substantially different in operating or geological characteristics or
geographic location than our existing properties. Furthermore, we may not be
able to obtain external funding for any such acquisitions or other transactions
or to obtain external funding on terms acceptable to us.
Reserves on acquired properties may not meet our expectations, and we may
be unable to identify liabilities associated with acquired properties or
obtain protection from sellers against associated liabilities.
23
Property acquisition decisions are based on various assumptions and
subjective judgments that are speculative. Although available geological and
geophysical information can provide information about the potential of a
property, it is impossible to predict accurately a property's production and
profitability. In addition, we may have difficulty integrating future
acquisitions into our operations, and they may not achieve our desired
profitability objectives. Likewise, as is customary in the industry, we
generally acquire oil and gas acreage without any warranty of title except
through the transferor. In many instances, title opinions are not obtained if,
in our judgment, it would be uneconomical or impractical to do so. Losses may
result from title defects or from defects in the assignment of leasehold rights.
While our current operations are primarily in Louisiana, Texas, and New Zealand,
we may pursue acquisitions of properties located in other geographic areas,
which would decrease our geographical concentration, and could also be in areas
in which we have no or limited experience.
In addition, our assessment of acquired properties may not reveal all
existing or potential problems or liabilities, nor will it permit us to become
familiar enough with the properties to assess fully their capabilities and
deficiencies. In the course of our due diligence, we may not inspect every well,
platform, or pipeline. Inspections may not reveal structural and environmental
problems, such as pipeline corrosion or groundwater contamination. We may not be
able to obtain contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical condition of
acquired properties in addition to the risk that the properties may not perform
in accordance with our expectations.
Prospects that we decide to drill may not yield oil or natural gas in
commercially viable quantities.
There is no way to predict in advance of drilling and testing whether any
particular prospect will yield oil or natural gas in sufficient quantities, if
at all, to recover drilling or completion costs or to be economically viable.
The use of seismic data and other technologies and the study of producing fields
in the same area will not enable us to know conclusively prior to drilling
whether oil or natural gas will be present. We cannot assure you that the
analogies we draw from available data from other wells, more fully explored
prospects, or producing fields will be applicable to our drilling prospects. In
addition, a variety of factors, including geological and market-related, can
cause a well to become uneconomical or only marginally economical. For example,
if oil and natural gas prices are much lower after we complete a well than when
we identified it as a prospect, the completed well may not yield commercially
viable quantities.
In many instances, title opinions on our oil and gas acreage are not
obtained if in our judgment it would be uneconomical or impractical to do
so.
As is customary in the industry, we generally acquire oil and gas acreage
without any warranty of title except as to claims made by, through, or under the
transferor. Although we have title to developed acreage examined prior to
acquisition in those cases in which the economic significance of the acreage
justifies the cost, there can be no assurance that losses will not result from
title defects or from defects in the assignment of leasehold rights.
Our use of oil and natural gas price hedging contracts involves credit risk
and may limit future revenues from price increases and expose us to risk of
financial loss.
We enter into hedging transactions for our oil and natural gas production
to reduce exposure to fluctuations in the price of oil and natural gas,
primarily to protect against declines in prices. Our hedges at year-end 2006
consisted of natural gas price floors with strike prices higher than the period
end prices. Our hedging transactions have also historically consisted of
financially settled crude oil and natural gas forward sales contracts with major
financial institutions as well as crude oil price floors. We intend to continue
to enter into these types of hedging transactions in the foreseeable future.
Hedging transactions expose us to risk of financial loss in some circumstances,
including if production is less than expected, the other party to the contract
defaults on its obligations, or there is a change in the expected differential
between the underlying price in the hedging agreement and actual prices
received. Hedging transactions other than floors may limit the benefit we would
have otherwise received from increases in the price for oil and natural gas.
Additionally, hedging transactions other than floors may expose us to cash
margin requirements.
24
We may have difficulty competing for oil and gas properties or supplies.
We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for the equipment, labor, and materials required to
develop and operate such properties. Many of these competitors have financial
and technological resources substantially greater than ours. The market for oil
and gas properties is highly competitive and we may lack technological
information or expertise available to other bidders. We may incur higher costs
or be unable to acquire and develop desirable properties at costs we consider
reasonable because of this competition.
Our business depends on oil and natural gas transportation facilities, some
of which are owned by others.
The marketability of our oil and natural gas production depends in part on
the availability, proximity, and capacity of pipeline systems owned by
third parties. The unavailability of or lack of available capacity on these
systems and facilities could result in the shut-in of producing wells or
the delay or discontinuance of development plans for properties. Although
we have some contractual control over the transportation of our product,
material changes in these business relationships could materially affect
our operations. Federal and state regulation of oil and natural gas
production and transportation, tax and energy policies, changes in supply
and demand, pipeline pressures, damage to or destruction of pipelines and
general economic conditions could adversely affect our ability to produce,
gather and transport oil and natural gas.
Governmental laws and egulations are costly and stringent, especially those
relating to environmental protection.
Our domestic exploration, production, and marketing operations are subject
to complex and stringent federal, state, and local laws and regulations
governing the discharge of substances into the environment or otherwise relating
to environmental protection. These laws and regulations affect the costs,
manner, and feasibility of our operations and require us to make significant
expenditures in our efforts to comply. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil, and criminal
penalties, the imposition of investigatory and remedial obligations, and the
issuance of injunctions that could limit or prohibit our operations. In
addition, some of these laws and regulations may impose joint and several,
strict liability for contamination resulting from spills, discharges, and
releases of substances, including petroleum hydrocarbons and other wastes,
without regard to fault or the legality of the original conduct. Under such laws
and regulations, we could be required to remove or remediate previously disposed
substances and property contamination, including wastes disposed or released by
prior owners or operations. Changes in or additions to environmental laws and
regulations occur frequently, and any changes or additions that result in more
stringent and costly waste handling, storage, transport, disposal, or cleanup
requirements could have a material adverse effect our operations and financial
position.
Our operations outside of the United States could also be subject to
similar foreign governmental controls and restrictions pertaining to protection
of human health and the environment. These controls and restrictions may include
the need to acquire permits, prohibitions on drilling in certain environmentally
sensitive areas, performance of investigatory or remedial actions for any
releases of petroleum hydrocarbons or other wastes caused by us or prior owners
or operators, closure, and restoration of facility sites, and payment of
penalties for violations of applicable laws and regulations.
We are exposed to the risk of fluctuations in foreign currencies, primarily
the New Zealand dollar.
Fluctuations in rates between the New Zealand dollar and U.S. dollar impact
our financial results from our New Zealand subsidiaries since we have
receivables, liabilities, and natural gas and NGL sales contracts denominated in
New Zealand dollars. New Zealand income taxes are also computed in New Zealand
dollars. We do not hedge against the risks associated with fluctuations in
exchange rates. Although we may use hedging techniques in the future, we may not
be able to eliminate or reduce the effects of currency fluctuations. As a
result, exchange rate fluctuations could have an adverse impact on our operating
results.
25
Item 1B. Unresolved Staff Comments
None.
26
Glossary of Abbreviations and Terms
The following abbreviations and terms have the indicated meanings when used in
this report:
Bbl -- Barrel or barrels of oil.
Bcf -- Billion cubic feet of natural gas.
Bcfe -- Billion cubic feet of natural gas equivalent (see Mcfe).
BOE -- Barrels of oil equivalent.
Development Well -- A well drilled within the presently proved productive area
of an oil or natural gas reservoir, as indicated by reasonable interpretation
of available data, with the objective of completing in that reservoir.
Discovery Cost -- With respect to proved reserves, a three-year average (unless
otherwise indicated) calculated by dividing total incurred exploration and
development costs (exclusive of future development costs) by net reserves
added during the period through extensions, discoveries, and other additions.
Dry Well -- An exploratory or development well that is not a producing well.
EBITDA -- Earnings before interest, taxes, depreciation, depletion and
amortization.
EBITDAX -- Earnings before interest, taxes, depreciation, depletion and
amortization, and exploration expenses. Since Swift uses full-cost accounting
for oil and property expenditures, as noted in footnote one of the
accompanying consolidated financial statements, exploration expenses are not
applicable to Swift.
Exploratory Well -- A well drilled either in search of a new, as yet
undiscovered oil or natural gas reservoir or to greatly extend the known
limits of a previously discovered reservoir.
FASB -- The Financial Accounting Standards Board.
Gross Acre -- An acre in which a working interest is owned. The number of gross
acres is the total number of acres in which a working interest is owned.
Gross Well -- A well in which a working interest is owned. The number of gross
wells is the total number of wells in which a working interest is owned.
MBbl -- Thousand barrels of oil.
Mcf -- Thousand cubic feet of natural gas.
Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf
of natural gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes.
Typically, prices quoted for natural gas are designated as price per MMBtu,
the same basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
27
Net Acre -- A net acre is deemed to exist when the sum of fractional working
interests owned in gross acres equals one. The number of net acres is the sum
of fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
Net Well -- A net well is deemed to exist when the sum of fractional working
interests owned in gross wells equals one. The number of net wells is the sum
of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
NGL-- Natural gas liquid.
Producing Well -- An exploratory or development well found to be capable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
* Proved Developed Oil and Gas Reserves -- Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
* Proved Oil and Gas Reserves -- The estimated quantities of crude oil, natural
gas, and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, that is, prices
and costs as of the date the estimate is made.
* Proved Undeveloped Oil and Gas Reserves -- Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Proved Undeveloped (PUD) Locations -- A location containing proved undeveloped
reserves.
PV-10 Value -- The estimated future net revenues to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated
production costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without giving effect to
non-property related expenses, such as general and administrative expenses,
debt service, future income tax expense, or depreciation, depletion, and
amortization.
Reserves Replacement Cost -- With respect to proved reserves, a three-year
average (unless otherwise indicated) calculated by dividing total incurred
acquisition, exploration, and development costs (exclusive of future
development costs) by net reserves added during the period.
SFAS -- Statement of Financial Accounting Standards.
TAWN -- New Zealand producing properties acquired by Swift in January 2002. TAWN
is comprised of the Tariki, Ahuroa, Waihapa, and Ngaere fields.
* These definitions regarding various types of proved reserves are only
abbreviated versions of the Securities and Exchange Commission's definitions
of these terms contained in Rule 4-10(a) of Regulation S-X. See
www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the full text of the
SEC's definitions of these terms.
28
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation and claims incidental to our business.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 2006 to a vote of
security holders.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
Common Stock, 2005 and 2006
Our common stock is traded on the New York Stock Exchange under the symbol
"SFY." The high and low quarterly closing sales prices for the common stock for
2005 and 2006 were as follows:
2005 2006
------------------------------------- -------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
------------------------------------- -------------------------------------
Low $24.77 $26.22 $37.31 $39.82 $35.48 $35.61 $40.06 $39.10
High $30.64 $36.75 $48.86 $50.01 $49.50 $45.22 $48.00 $51.84
Since inception, no cash dividends have been declared on our common stock.
Cash dividends are restricted under the terms of our credit agreements, as
discussed in Note 4 to the consolidated financial statements, and we presently
intend to continue a policy of using retained earnings for expansion of our
business.
We had approximately 252 stockholders of record as of December 31, 2006.
Equity Compensation Plan Information
Information regarding our equity compensation plans, including both
shareholder approved plans and plans not approved by shareholders, is set forth
in the Proxy Statement for our annual meeting to be held May 8, 2007 ("Proxy
Statement"), which Proxy Statement is to be filed within 120 days after
Registrant's fiscal year end of December 31, 2006, and which information is
incorporated herein by reference.
Share Performance Graph
The following Share Performance Graph shall not be deemed to be "soliciting
material" or to be "filed" with the Securities and Exchange Commission, nor
shall such information be incorporated by reference into any future filings
under the Securities Act of 1933 or Securities Exchange Act of 1934, each as
amended, except to the extent that the Company specifically incorporates it by
reference into such filing.
29
Beginning
Transaction Closing No. Of Dividend Dividend Shares Ending Cum. Tot.
Date* Type Price** Shares*** per Share Paid Reinvested Shares Return
31-Dec-01 Begin 20.200 4.95 4.950 100.00
31-Dec-02 Year End 9.670 4.95 4.950 47.87
31-Dec-03 Year End 16.850 4.95 4.950 83.42
31-Dec-04 Year End 28.940 4.95 4.950 143.27
31-Dec-05 Year End 45.070 4.95 4.950 223.12
31-Dec-06 End 44.810 4.95 4.950 221.83
* Specified ending dates or ex-dividends dates.
** All Closing Prices and Dividends are adjusted for stock splits and stock
dividends.
***'Begin Shares' based on $100 investment.
[GRAPHIC OMITTED]
30
Item 6. Selected Financial Data
2006 2005 2004 2003 2002
Total Revenues $615,441,230 $423,226,489 $310,276,774 $208,900,983 $149,969,811
Income (Loss) Before Income Taxes and
Change in Accounting Principle (1) $262,286,165 $178,439,551 $101,440,242 $50,739,178 $18,408,289
Net Income (Loss) $161,565,340 $115,778,456 $68,450,917 $29,893,812 $11,923,227
Net Cash Provided by Operating Activities $424,921,046 $285,333,484 $182,582,887 $110,827,279 $71,626,314
Per Share Data
Weighted Average Shares Outstanding(1) 29,265,366 28,496,275 27,822,413 27,357,579 26,382,906
Earnings (Loss) per Share--Basic(1) $5.52 $4.06 $2.46 $1.09 $0.45
Earnings (Loss) per Share--Diluted(1) $5.38 $3.95 $2.41 $1.08 $0.45
Shares Outstanding at Year-End 29,742,918 29,009,530 28,089,764 27,484,091 27,201,509
Book Value per Share at Year-End $26.83 $20.94 $16.88 $14.46 $13.42
Market Price(1)
High $51.84 $50.01 $30.34 $18.00 $20.58
Low $35.48 $24.77 $15.90 $7.60 $6.80
Year-End Close $44.81 $45.07 $28.94 $16.85 $9.67
Effect on Net Income and Earnings Per Share
From Changes in Accounting Principles (2)
Cumulative Effect of Change in Accounting
Principle (Net of Taxes) --- --- --- ($4,376,852) ---
Effect per Share--Basic --- --- --- ($0.16) ---
Effect per Share--Diluted --- --- --- ($0.16) ---
Assets
Current Assets $92,573,041 $115,055,135 $54,385,996 $33,460,957 $29,768,199
Property & Equipment, Net of Accumulated
Depreciation, Depletion, and Amortization $1,483,312,165 $1,079,033,739 $923,438,160 $815,807,003 $721,617,941
Total Assets $1,585,681,758 $1,204,412,622 $990,573,147 $859,838,544 $767,005,859
Liabilities
Current Liabilities $145,975,288 $98,421,014 $68,618,291 $69,353,342 $46,884,184
Long-Term Debt $381,400,000 $350,000,000 $357,500,000 $340,254,783 $324,271,973
Total Liabilities $787,764,786 $597,094,455 $516,401,007 $462,447,280 $401,932,675
Stockholders' Equity $797,916,972 $607,318,167 $474,172,140 $397,391,264 $365,073,184
Number of Employees 345 311 272 241 234
Producing Wells
Swift Operated 973 898 835 870 820
Outside Operated 112 69 97 128 112
Total Producing Wells 1,085 967 932 998 932
Wells Drilled (Gross) 63 64 66 75 36
Proved Reserves
Natural Gas (Mcf) 324,131,417 287,473,150 318,246,294 335,804,862 326,731,672
Oil, NGL, & Condensate (barrels) 82,119,084 79,053,056 80,267,208 80,759,903 70,438,963
Total Proved Reserves (Mcf equivalent) 816,845,916 761,791,482 799,849,539 820,364,284 749,365,449
Production (Mcf equivalent)(3) 70,204,544 59,589,526 58,318,502 53,158,384 49,752,346
Average Sales Price
Natural Gas (per Mcf) $5.05 $5.23 $4.12 $3.42 $2.30
Natural Gas Liquids (per barrel)(4) $32.15 $28.04 $22.52 $17.60 $12.82
Oil (per barrel)(4) $64.47 $53.63 $40.24 $29.89 $24.52
Mcf Equivalent $8.57 $7.11 $5.34 $3.97 $2.84
(1)Amounts have been retroactively restated in all periods presented to give
recognition to: (a) the adoption in 1998 of Statement of Financial Accounting
Standards No. 128, "Earnings per Share," and (b) the adoption in 2003 of
Statement of Financial Accounting Standards No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections," which affected our presentation of 1999 results by reclassifying
the loss on early extinguishment of debt from an extraordinary item to an
operating item.
(2)We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003. We adopted SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Transactions" on January 1, 2001.
(3)Natural gas production from 1996 to 2000 includes volumes under a production
payment agreement ranging from 1.2 Bcfe in 1996 to 0.4 Bcfe in 2000.
(4)Prior to 2002, we combined NGLs with natural gas for reporting purposes.
31
2001 2000 1999 1998 1997 1996
$183,807,490 $191,624,946 $110,671,007 $82,469,221 $74,712,180 $56,298,026
($34,192,333) 92,449,488 $29,736,151 ($73,391,581) $33,129,606 $28,785,783
($22,347,765) $59,184,008 $19,286,574 ($48,225,204) $22,310,189 $19,025,450
$139,884,255 $128,197,227 $73,603,426 $54,249,017 $55,255,965 $37,102,578
24,732,099 21,244,684 18,050,106 16,436,972 16,492,856 15,000,901
($0.90) $2.79 $1.07 ($2.93) $1.35 $1.27
($0.90) $2.51 $1.07 ($2.93) $1.26 $1.25
24,795,564 24,608,344 20,823,729 16,291,242 16,459,156 15,176,417
$12.61 $13.50 $8.18 $6.71 $9.69 $9.41
$37.70 $43.50 $13.31 $21.00 $34.20 $28.86
$16.66 $9.75 $5.69 $6.94 $16.93 $9.89
$20.20 $37.63 $11.50 $7.38 $21.06 $27.16
($392,868) --- --- --- --- ---
($0.01) --- --- --- --- ---
($0.01) --- --- --- --- ---
$36,752,980 $41,872,879 $50,605,488 $35,246,431 $29,981,786 $101,619,478
$628,304,060 $524,052,828 $392,986,589 $356,711,711 $301,312,847 $200,010,375
$671,684,833 $572,387,001 $454,299,414 $403,645,267 $339,115,390 $310,375,264
$73,245,335 $64,324,771 $34,070,085 $31,415,054 $28,517,664 $32,915,616
$258,197,128 $134,729,485 $239,068,423 $261,200,000 $122,915,000 $115,000,000
$359,032,113 $240,232,846 $283,895,297 $294,282,628 $179,714,470 $167,613,654
$312,652,720 $332,154,155 $170,404,117 $109,362,639 $159,400,920 $142,761,610
209 181 173 203 194 191
854 817 769 836 650 842
381 711 788 917 917 986
1,235 1,528 1,557 1,753 1,567 1,828
53 70 27 75 182 153
324,912,125 418,613,976 329,959,750 352,400,835 314,305,669 225,758,201
53,482,636 35,133,596 20,806,263 13,957,925 7,858,918 5,484,309
645,807,939 629,415,552 454,797,327 436,148,385 361,459,177 258,664,055
44,791,202 42,356,705 42,874,303 39,030,030 25,393,744 19,437,114
$4.23 $4.24 $2.40 $2.08 $2.68 $2.57
--- --- --- --- --- ---
$22.64 $29.35 $16.75 $11.86 $17.59 $19.82
$4.05 $4.47 $2.54 $2.05 $2.72 $2.71
32
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with
our financial information and our audited consolidated financial statements and
accompanying notes for the years ended December 31, 2006, 2005, and 2004
included with this report. The following information contains forward-looking
statement;, see "Forward-Looking Statements" on page 45 of this report.
Overview
Swift Energy had record net income, cash flow, and production for 2006. Net
income increased 40% to $161.6 million and cash flow from operations increased
49% to $425 million, in each case compared to 2005 amounts. Production increased
18% to 70.2 Bcfe over hurricane affected production a year earlier, principally
attributable to our continued success in Lake Washington, with our 2006
production increase matching in one year our cumulative production increase over
the prior three years. We ended 2006 with total proved reserves of 817 Bcfe, an
increase of 7% over year-end 2005 reserves. We also had record revenues of
$615.4 million for 2006, an increase of 45% over 2005 levels. Our weighted
average sales price increased 20% to $8.57 per Mcfe for 2006 from $7.11 in 2005.
Of our $177.8 million increase in oil and gas sales revenues, 60% came from a
2.0 million barrel increase in oil volumes produced, with the remainder
attributable to higher oil prices during 2006.
Our capital expenditures more than doubled from 2005 to 2006, principally
due to our acquisition of five substantial onshore properties in South Louisiana
from BP America Production Company for $167.9 million in cash and the increase
in our spending on drilling and development, predominantly in our South
Louisiana region. Although the acquisition did not appreciably add to our 2006
production volumes, it added 58 Bcfe of proved reserves, about one-third of
which were proved undeveloped, resulting in our proved undeveloped reserves
increasing to 56% of total reserves at year-end 2006, compared to 50% the
previous year.
Our overall costs and expenses increased in 2006 by 44%. In 2007, we will
focus upon our capital efficiency by managing our costs and expenses, always a
difficult task in the inflationary cost environment prevalent in the industry
over the last several years, and especially over the last year when recent
declines in commodity prices have not been matched by comparable declines in
prices of oilfield equipment and services. The largest increase in these costs
and expenses is due to increased depreciation, depletion and amortization
expense, not only due to our larger depletable property base and higher
production, but also due to increases in future development costs to reflect
industry inflation. We expect cost pressures to continue to affect the industry
throughout 2007, with tightening availability of crews as well as increasing
costs of services and basic equipment.
Our year-end 2006 proved reserves were 50% crude oil, 40% natural gas, and
10% NGLs, almost identical to the percentage splits a year earlier. Our 2006
production, however, was 61% crude oil, up from 52% in 2005, which allowed us to
take advantage of the over 20% increase in oil prices, while natural gas prices
fell during the year. Domestic proved reserves increased at year-end 2006 to
710.4 Bcfe (87% of our total proved reserves), while proved reserves in New
Zealand decreased to 106.4 Bcfe at year-end 2006, primarily attributable to 2006
production. For 2007, we are considering conducting an expanded 3-D seismic
survey in New Zealand prior to continuing drilling activities.
Our financial position remains strong. Our debt to capitalization ratio was
32% at December 31, 2006, compared to 37% at year-end 2005, as debt levels
increased in 2006 and retained earnings increased as a result of the current
period profit, with net debt per Mcfe of $0.47 per Mcfe at year-end 2006. Our
debt to PV-10 ratio increased to 14% at December 31, 2006 compared to 11% at
December 31, 2005, primarily due to lower natural gas prices at year-end 2006
and an increase in our total debt, partially offset by higher oil and natural
gas reserves volumes. Lower year-end commodity prices, principally natural gas,
decreased our PV-10 value and standardized measure at the end of 2006 compared
to the prior year-end.
Our current 2007 capital expenditure budget is $350 million to $400
million, net of minor non-core dispositions and excluding any property
acquisitions. Approximately 95% of the budget is targeted for domestic
activities, predominantly in our South Louisiana region, with about 5% planned
for activities in the New Zealand region. For 2007, we are targeting total
production to increase 7% to 10% and proved reserves to increase 4% to 6% over
2006 levels. We may also increase our capital expenditure budget if commodity
33
prices rise during the year or if strategic opportunities warrant. If 2007
capital expenditures exceed our cash flow from operating activities, we can fund
these expenditures with our credit facility to fund these expenditures.
During 2007, we plan to further develop our inventory of properties in
South Louisiana using our expertise and experience gained in expanding and
producing in Lake Washington, together with significant 3-D seismic information,
to exploit our other prospect areas covered by similar geological features. This
broad prospect inventory will allow us to be selective in choosing drilling
opportunities so we can create long-life reserves while at the same time raising
our production significantly, which we did during 2006 mainly through organic
production growth.
Results of Operations -- Years Ended 2006, 2005, and 2004
Revenues. Our revenues in 2006 increased by 45% compared to revenues in
2005 primarily due to increases in oil production from our Lake Washington area
and increases in oil prices, and our revenues in 2005 increased by 36% compared
to 2004 revenues due primarily to increases in oil and natural gas prices and in
production from our Lake Washington and Rimu/Kauri areas. Revenues from our oil
and gas sales comprised substantially all of total revenues for 2006, 2005, and
2004. Crude oil production was 61% of our production volumes in 2006, 52% in
2005, and 49% in 2004. Natural gas production was 32% of our production volumes
in 2006, 40% in 2005, and 41% in 2004. Domestic production was 81% of our total
production volumes in 2006, and 72% in both 2005 and 2004.
The following table provides information regarding the changes in the
sources of our oil and gas sales and volumes for the years ended December 31,
2006, 2005, and 2004:
Oil and Gas
Oil and Gas Sales Sales Volume
----------------------------- -------------------------
(In millions) (Bcfe)
Area 2006 2005 2004 2006 2005 2004
---- -------- -------- -------- ------- ------- ------
AWP Olmos....................................................$ 53.7 $ 61.7 $ 49.9 7.5 7.7 9.0
Brookeland................................................... 15.6 20.4 18.0 2.1 2.9 3.4
Lake Washington.............................................. 397.2 229.2 152.3 38.7 26.7 23.2
Masters Creek................................................ 13.3 17.9 21.0 1.7 2.4 3.7
Cote Blanche Island/Bay de Chene............................. 29.3 7.4 0.0 3.1 0.9 0.0
Other........................................................ 28.4 19.3 17.5 3.6 2.4 2.8
-------- ---- -------- ------- ------- ------
Total Domestic............................................$ 537.5 $ 355.9 $ 258.7 56.7 43.0 42.1
Rimu/Kauri................................................... 36.8 41.6 24.5 6.3 8.2 5.3
TAWN......................................................... 27.2 26.3 28.1 7.2 8.3 11.0
-------- -------- -------- ------- ------- ------
Total New Zealand.........................................$ 64.0 $ 67.9 $ 52.6 13.5 16.5 16.3
-------- ------- -------- ------- ------- ------
Total.......................................................$ 601.6 $ 423.8 $ 311.3 70.2 59.6 58.3
======== ======== ======== ======= ======= ======
Oil and gas sales in 2006 increased by 42%, or $177.8 million, from the
level of those revenues for 2005, and our net sales volumes in 2006 increased by
18%, or 10.6 Bcfe, over net sales volumes in 2005. Average prices for oil
increased to $64.47 per Bbl in 2006 from $53.63 per Bbl in 2005. Average natural
gas prices decreased to $5.05 per Mcf in 2006 from $5.23 per Mcf in 2005.
Average NGL prices increased to $32.15 per Bbl in 2006 from $28.04 per Bbl in
2005.
In 2006, our $177.8 million increase in oil, NGL, and natural gas sales
resulted from:
o Volume variances that had a $101.1 million favorable impact on sales,
with $108.9 million of increases attributable to the 2.0 million Bbl
increase in oil sales volumes, offset by a decrease of $3.5 million due
to the 0.1 million Bbl decrease in NGL sales volumes, and a decrease of
$4.3 million due to the 0.8 Bcf decrease in natural gas sales volumes;
and
o Price variances that had a $76.7 million favorable impact on sales, of
which $78.0 million was attributable to the 20% increase in average oil
prices received, and $2.9 million was attributable to the 15% increase
in NGL prices, offset by a decrease of $4.2 million attributable to the
3% decrease in natural gas prices.
34
Oil and gas sales in 2005 increased by 36%, or $112.5 million, from the
level of those revenues for 2004, and our net sales volumes in 2005 increased by
2%, or 1.3 Bcfe, over net sales volumes in 2004. Average prices for oil
increased to $53.63 per Bbl in 2005 from $40.24 per Bbl in 2004. Average natural
gas prices increased to $5.23 per Mcf in 2005 from $4.12 per Mcf in 2004.
Average NGL prices increased to $28.04 per Bbl in 2005 from $22.52 per Bbl in
2004.
In 2005, our $112.5 million increase in oil, NGL, and natural gas sales
resulted from:
o Price variances that had a $100.0 million favorable impact on sales, of
which $69.1 million was attributable to the 33% increase in average oil
prices received, $26.3 million was attributable to the 27% increase in
natural gas prices and $4.6 million was attributable to the 24% increase
in NGL prices; and
o Volume variances that had a $12.5 million favorable impact on sales,
with $17.6 million of increases attributable to the 0.4 million Bbl
increase in oil sales volumes, offset by a decrease of $4.6 million due
to the 0.2 million Bbl decrease in NGL sales volumes, and a decrease of
$0.5 million due to the 0.1 Bcf decrease in natural gas sales volumes.
The following table provides additional information regarding our quarterly oil
and gas sales:
Sales Volume Average Sales Price
------------ -------------------
Natural
Oil NGL Gas Combined Oil NGL Gas
------- ------- ------- --------- --------- --------- ---------
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
2004:
First.................... 1,124 277 5.9 14.3 $ 34.14 $ 22.30 $ 3.64
Second................... 1,142 269 5.8 14.3 $ 37.24 $ 18.84 $ 4.19
Third.................... 1,076 251 6.0 13.9 $ 41.99 $ 23.33 $ 3.97
Fourth................... 1,380 243 6.1 15.9 $ 46.33 $ 26.01 $ 4.67
----- ----- ---- ---
Total................. 4,722 1,040 23.7 58.3 $ 40.24 $ 22.52 $ 4.12
===== ===== ==== ===
2005:
First.................... 1,321 223 6.3 15.5 $ 47.66 $ 26.79 $ 4.25
Second................... 1,426 209 6.1 15.9 $ 50.24 $ 22.95 $ 4.67
Third.................... 1,059 204 5.9 13.5 $ 59.66 $ 31.84 $ 5.29
Fourth................... 1,353 202 5.3 14.7 $ 58.31 $ 30.83 $ 6.97
----- ---- ---- ---
Total................. 5,159 838 23.6 59.6 $ 53.63 $ 28.04 $ 5.23
===== ==== ==== ===
2006:
First.................... 1,611 152 6.0 16.5 $ 60.83 $ 30.34 $ 5.38
Second................... 1,636 138 5.6 16.3 $ 69.63 $ 29.72 $ 4.79
Third.................... 1,992 220 5.5 18.8 $ 69.62 $ 36.18 $ 4.87
Fourth................... 1,951 203 5.7 18.6 $ 57.88 $ 30.79 $ 5.14
----- ---- ---- ---
Total................. 7,190 713 22.8 70.2 $ 64.47 $ 32.15 $ 5.05
===== ==== ==== ===
In 2006, we settled all insurance claims with our insurers relating to
hurricanes Katrina and Rita for approximately $30.5 million and entered into a
confidential final settlement agreement. The receipt of these amounts resulted
in a benefit of $7.7 million in 2006 recorded in "Price-risk management and
other, net," for the portion of the above referenced settlement, which we have
determined to be non-property damage related claims. Approximately $22.8 million
of the above referenced settlement was determined to be property damage related
claims. We recorded $14.1 million of the property related settlement as a
reduction to "Proved properties" on the accompanying consolidated balance sheet,
as this related to reimbursement of capital costs we incurred. We also recorded
$8.7 million of the property related settlement as a reduction to "Lease
operating cost" on the accompanying consolidated statement of income, as this
related to reimbursement of repair costs which had been expensed as incurred. In
the accompanying consolidated statement of cash flows, we have recorded the
reimbursement which reduced "Proved properties" as a reduction of "Net Cash Used
in Investing Activities" and the remainder of the insurance settlement was
recorded as an increase to "Net Cash Provided by Operating Activities."
Costs and Expenses. Our expenses in 2006 increased $108.4 million, or 44%,
compared to 2005 expenses. The majority of the increase was due to a $61.8
million increase in DD&A, a $23.3 million increase in severance and other taxes,
and a $15.2 million increase in lease operating costs, all of which are
primarily due to increased production volumes in 2006. Increased commodity
prices also increased severance and other taxes, and higher full cost pool
35
balances increased DD&A, offset somewhat by increased reserves volumes in 2006.
Our expenses in 2005 increased $36.0 million, or 17%, compared to 2004 expenses.
The majority of the increase was due to a $25.9 million increase in DD&A, an
$11.8 million increase in severance and other taxes, and a $6.1 million increase
in lease operating costs, all of which are primarily due to increased commodity
prices and production volumes in 2005. This increase was partially offset by the
absence of $9.5 million of debt retirement costs incurred in 2004.
Our 2006 general and administrative expenses, net, increased $9.1 million,
or 41%, from the level of such expenses in 2005, while 2005 general and
administrative expenses, net, increased $4.4 million, or 25%, over 2004 levels.
The increase in both 2006 and 2005 were primarily due to increased salaries and
burdens associated with our expanded workforce. Costs also increased in 2006 as
a result of expensing stock options and increased restricted stock grants, and
increased in 2005 due to restricted stock compensation. For the years 2006,
2005, and 2004, our capitalized general and administrative costs totaled $28.3
million, $18.8 million, and $13.1 million, respectively. Our net general and
administrative expenses per Mcfe produced increased to $0.45 per Mcfe in 2006
from $0.37 per Mcfe in 2005 and $0.30 per Mcfe in 2004. The portion of
supervision fees recorded as a reduction to general and administrative expenses
was $8.8 million for 2006, $7.8 million for 2005, and 5.8 million for 2004.
DD&A increased $61.8 million, or 58%, in 2006 from 2005 levels, while 2005
DD&A increased $25.9 million, or 32%, from 2004 levels. Domestically, DD&A
increased $58.1 million in 2006 due to increases in the depletable oil and gas
property base and higher production, partially offset by higher reserves
volumes. In New Zealand, DD&A increased by $3.7 million in 2006 due to an
increase in the depletable oil and gas property base and lower reserves. In
2005, our domestic DD&A increased $18.8 million due to increases in the
depletable oil and gas property base, slightly higher production in the 2005
period and lower reserves volumes. In New Zealand, DD&A increased by $7.1
million in 2005 due to the same reasons. Our DD&A rate per Mcfe of production
was $2.41 in 2006, $1.80 in 2005, and $1.40 in 2004, resulting from increases in
per unit cost of reserves additions.
We recorded $1.0 million, $0.8 million, and $0.7 million of accretions to
our asset retirement obligation in 2006, 2005, and 2004, respectively.
Our lease operating costs per Mcfe produced were $0.89 in 2006, $0.79 in
2005 and $0.71 in 2004. Our lease operating costs in 2006 increased $15.2
million, or 32%, over the level of such expenses in 2005, while 2005 costs
increased $6.1 million, or 15% over 2004 levels. Approximately $15.0 million of
the increase in lease operating costs during 2006 was related to our domestic
operations, which increased primarily due to increased production and was also
impacted by increased well insurance premiums. Our lease operating cost in New
Zealand increased in 2006 by $0.1 million due to increases in well operating
costs and storage and handling costs.
Severance and other taxes increased $23.3 million, or 55%, over 2005
levels, while in 2005 these taxes increased $11.8 million, or 39% over 2004
levels. The increases were due primarily to higher commodity prices and
increased Lake Washington production in each of the periods. Severance taxes on
oil in Louisiana are 12.5% of oil sales, which is higher than in the other
states where we have production. As our percentage of oil production in
Louisiana increases, the overall percentage of severance costs to sales also
increases. Severance and other taxes, as a percentage of oil and gas sales, were
approximately 10.9%, 10.0% and 9.8% in 2006, 2005 and 2004, respectively.
Our total interest cost in 2006 was $32.8 million, of which $9.2 million
was capitalized. Our total interest cost in 2005 was $32.1 million, of which
$7.2 million was capitalized. Our total interest cost in 2004 was $34.2 million,
of which $6.5 million was capitalized. Interest expense on our 7-5/8% senior
notes due 2011 issued in June 2004, including amortization of debt issuance
costs, totaled $11.9 million in both 2006 and 2005 and $6.2 million in 2004.
Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in
April 2002, including amortization of debt issuance costs, totaled the same
$19.2 million in 2006, 2005, and 2004. Interest expense on our 10-1/4% senior
subordinated notes issued in August 1999 and repurchased and retired in 2004,
including amortization of debt issuance costs, totaled $7.4 million in 2004.
Interest expense on our bank credit facility, including commitment fees and
amortization of debt issuance costs, totaled $1.5 million in 2006, $1.0 million
in 2005, and $1.5 million in 2004. Other interest cost was $0.1 million in 2006.
We capitalize a portion of interest related to unproved properties. The decrease
of interest expense in 2006 was primarily due to an increase in capitalized
interest costs, partially offset by an increase in credit facility interest. The
decrease of interest expense in 2005 was primarily due to the lower interest
rate applicable to the 7-5/8% notes issued in June 2004 versus the 10-1/4% notes
retired at that time.
In 2004, we incurred $9.5 million of debt retirement costs related to the
repurchase and redemption of our 10-1/4% senior subordinated notes due 2009. The
36
costs were comprised of approximately $6.5 million of premiums paid to
repurchase the notes, $2.2 million to write-off unamortized debt issuance costs,
$0.6 million to write-off unamortized debt discount and approximately $0.2
million of other costs.
Our overall effective tax rate was 38.4% for 2006, 35.1% for 2005 and 32.5%
for 2004. The effective tax rate for 2006 was higher than the statutory rate
primarily because of state income taxes and a valuation allowance, partially
offset by favorable adjustments for the currency effect on the New Zealand
deferred tax calculation. For 2005, the effective rate was about the same as the
statutory rate as state income taxes and the currency effect adjustments
essentially offset. For 2004, the effective rate was less than the statutory
rate due to favorable adjustments for currency effect and corrections to tax
basis amounts, partially offset by deferred state income taxes.
Net Income. Our net income in 2006 of $161.6 million was 40% higher than
our 2005 net income of $115.8 million due to higher oil prices and increased
production.
Our net income in 2005 of $115.8 million was 69% higher than our 2004 net
income of $68.5 million due to higher commodity prices and increased production.
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter as of
December 31, 2006 are as follows:
2007 2008 2009 2010 2011 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
(In thousands)
Non-cancelable operating leases(1)................$ 5,345 $ 5,321 $ 3,334 $ 3,293 $ 3,225 $ 10,109 $ 30,627
Asset retirement obligation(2).................... 1,650 2,313 2,019 2,110 2,205 24,163 34,460
Computer System Implementation.................... 3,261 -- -- -- -- -- 3,261
Construction costs................................ 5,223 -- -- -- -- -- 5,223
Drilling rigs, seismic and pipe inventory......... 28,873 -- -- -- -- -- 28,873
7-5/8% senior notes due 2011(3)................... -- -- -- -- 150,000 -- 150,000
9-3/8% senior subordinated notes due 2012(3)...... -- -- -- -- -- 200,000 200,000
Credit facility(4)................................ -- -- -- -- 31,400 -- 31,400
-------- -- -------- -------- --------- --------- ---------
Total...........................................$ 44,352 $ 7,634 $ 5,353 $ 5,403 $ 186,830 $ 234,272 $ 483,844
======== ======= ======== ======== ========= ========= =========
(1) Our most significant office lease is in Houston, Texas and it extends until
2015.
(2) Amounts shown by year are the fair values at December 31, 2006.
(3) Amounts do not include the interest obligation, which is paid semiannually.
(4) The credit facility expires in October 2011 and these amounts exclude a $0.8
million standby letter of credit outstanding under this facility.
Commodity Price Trends and Uncertainties
Oil and natural gas prices historically have been volatile and are expected
to continue to be volatile in the future. The price of oil has increased over
the last two years and is at historical highs when compared to longer-term
historical prices. Factors such as worldwide supply disruptions, worldwide
economic conditions, weather conditions, fluctuating currency exchange rates,
and political conditions in major oil producing regions, especially the Middle
East, can cause fluctuations in the price of oil. Domestic natural gas prices
continue to remain high when compared to longer-term historical prices. North
American weather conditions, the industrial and consumer demand for natural gas,
storage levels of natural gas, and the availability and accessibility of natural
gas deposits in North America can cause significant fluctuations in the price of
natural gas.
37
Income Tax Regulations
The tax laws in the jurisdictions we operate in are continuously changing
and professional judgments regarding such tax laws can differ.
Liquidity and Capital Resources
During 2006, we relied upon our net cash provided by operating activities
of $424.9 million, credit facility borrowings of $31.4 million, property sales
proceeds of $24.7 million, and cash balances to fund capital expenditures of
$557.5 million including $194.3 million of acquisitions. During 2005, we largely
relied upon our net cash provided by operating activities of $285.3 million to
fund capital expenditures of $264.5 million including $28.9 million of
acquisitions.
Net Cash Provided by Operating Activities. For 2006, our net cash provided
by operating activities was $424.9 million, representing a 49% increase as
compared to $285.3 million generated during 2005. The $139.6 million increase in
2006 was primarily due to an increase of $177.8 million in oil and gas sales,
attributable to higher oil prices and production, offset in part by higher lease
operating costs and severance taxes due to higher oil prices and higher domestic
production. In 2005, our net cash provided by operating activities was $285.3
million, representing a 56% increase as compared to $182.6 million generated
during 2004. The $102.8 million increase in 2005 was primarily due to an
increase of $112.5 million in oil and gas sales, attributable to higher
commodity prices and production, offset in part by higher lease operating costs
due to higher domestic production and severance taxes as a result of higher
commodity prices.
Accounts Receivable. We assess the collectibility of accounts receivable,
and, based on our judgment, we accrue a reserve when we believe a receivable may
not be collected. At both December 31, 2006 and 2005, we had an allowance for
doubtful accounts of less than $0.1 million. The allowance for doubtful accounts
has been deducted from the total "Accounts receivable" balances on the
accompanying balance sheets.
Existing Credit Facility. We had borrowings of $31.4 million under our bank
credit facility at December 31, 2006, and no outstanding borrowings at December
31, 2005. Our bank credit facility at December 31, 2006 consisted of a $500.0
million revolving line of credit with a $250.0 million borrowing base. The
borrowing base is re-determined at least every six months and was reaffirmed by
our bank group at $250.0 million, effective November 1, 2006. Under the terms of
our bank credit facility, we can increase this commitment amount to the total
amount of the borrowing base at our discretion, subject to the terms of the
credit agreement. Our revolving credit facility includes requirements to
maintain certain minimum financial ratios (principally pertaining to adjusted
working capital ratios and EBITDAX), and limitations on incurring other debt. We
are in compliance with the provisions of this agreement.
Our access to funds from our credit facility is not restricted under any
"material adverse condition" clause, a clause that is common for credit
agreements to include. A "material adverse condition" clause can remove the
obligation of the banks to fund the credit line if any condition or event would
reasonably be expected to have an adverse or material effect on operations,
financial condition, prospects or properties, and would impair the ability to
make timely debt repayments. Our credit facility includes covenants that require
us to report events or conditions having a material adverse effect on our
financial condition. The obligation of the banks to fund the credit facility is
not conditioned on the absence of a material adverse effect.
Working Capital. Our working capital declined from a surplus of $16.6
million at December 31, 2005, to a deficit of $53.4 million at December 31,
2006. The decrease primarily resulted from a decrease in cash and cash
equivalents due to property acquisitions during the fourth quarter of 2006.
Debt Maturities. Our credit facility, with a balance of $31.4 million at
December 31, 2006, extends until October 3, 2011. Our $150.0 million of 7-5/8%
senior notes mature July 15, 2011, and our $200.0 million of 9-3/8% senior
subordinated notes mature May 1, 2012.
On or after May 1, 2007, we are entitled to redeem our $200.0 million of
9-3/8% senior subordinated notes at a redemption price, plus accrued and unpaid
interest, of 104.688% of principal. If these notes were redeemed, we would most
likely use a combination of drawings upon our credit facility, cash flows from
operations, and the use of debt and/or equity offerings to fund any such
redemption.
38
Capital Expenditures. In 2006 we relied upon our net cash provided by
operating activities of $424.9, credit facility borrowings of $31.4 million,
property sales proceeds of $24.7 million, and cash balances to fund capital
expenditures of $557.5 million including $194.3 million of acquisitions. Our
total capital expenditures of approximately $557.5 million in 2006 included:
Domestic expenditures of $502.3 million as follows:
o $214.9 million for drilling and developmental activity costs,
predominantly in our South Louisiana area;
o $200.5 million for acquisitions of properties, primarily in our South
Louisiana area;
o $20.5 million on exploratory drilling;
o $51.1 million of domestic prospect costs, principally prospect
leasehold, 3-D seismic activity, and geological costs of unproved
prospects;
o $15.3 million primarily for leasehold improvements, computer equipment,
software, furniture, and fixtures;
New Zealand expenditures of $55.2 million as follows:
o $28.8 million for drilling costs and developmental activity costs,
predominantly in our Rimu/Kauri area;
o $15.7 million on exploratory drilling;
o $10.4 million on prospect costs, principally prospect leasehold, seismic
and geological costs of unproved properties;
o $0.3 million for computer equipment, software, furniture, and fixtures.
We continue to spend considerable time and capital on facility capacity
upgrades in the Lake Washington field, and increased facility capacity at
year-end 2006 to approximately 28,000 barrels per day for crude oil, up from
9,000 barrels per day capacity in the first quarter of 2003. We have upgraded
three production platforms, added new compression for the gas lift system, and
installed a new oil delivery system and permanent barge loading facility. During
2006, we began planning for the addition of a fourth production platform which
will increase our processing capacity another 10,000 barrels per day by
mid-2008.
We completed 45 of 63 wells in 2006, for a success rate of 71%.
Domestically, we completed 42 of 49 development wells for a success rate of 86%
and were unsuccessful on six exploratory wells, including five very shallow
exploration wells in the AWP Olmos area which cost $0.5 million in the
aggregate, and one non-operated well in Alaska. A total of 21 development wells
were drilled in the Lake Washington area, of which 18 were completed, and 15
development wells were drilled in the AWP Olmos area, of which 14 were
completed. We also drilled six development wells in the Bay de Chene area, of
which three were completed, drilled three successful development wells in each
of the Cote Blanche Island and South Bearhead Creek areas, and drilled one
successful development well in the Brookeland area. In New Zealand, we completed
three of four development wells but were unsuccessful on four exploratory wells.
Our capital expenditures were approximately $264.5 million in 2005 and
$171.1 million in 2004. In 2005, we relied upon our net cash provided by
operating activities of $285.3 million to fund capital expenditures of $264.5
million, including acquisitions of $28.9 million. During 2004, we relied upon
our net cash provided by operating activities of $182.6 million, the issuance of
our 7-5/8% senior notes due 2011, proceeds from the sale of non-core properties
and equipment of $5.1 million, less the repayment of our 10-1/4% senior
subordinated notes due 2009 to fund capital expenditures of $198.3 million,
including acquisitions of $27.2 million. Our total capital expenditures in 2005
of approximately $264.5 million included:
Domestic expenditures of $215.8 million as follows:
o $111.0 million for drilling and developmental activity costs,
predominantly in our Lake Washington area;
39
o $29.6 million on property acquisitions, including $28.9 million to
acquire properties in the South Bearhead Creek field;
o $36.8 million on exploratory drilling, mainly in our Lake Washington
area;
o $34.4 million of prospect costs, principally prospect leasehold, 3-D
seismic activity, and geological costs of unproved prospects;
o $3.6 million primarily for a field office building, computer equipment,
software, furniture, and fixtures;
o $0.3 million on gas processing plants in the Brookeland and Masters
Creek areas; and
o less than $0.1 million on field compression facilities.
New Zealand expenditures of $48.7 million as follows:
o $27.2 million for drilling costs and developmental activity costs,
predominantly in our Rimu/Kauri area;
o $13.6 million on exploratory drilling;
o $6.9 million on prospect costs, principally prospect leasehold, seismic
and geological costs of unproved properties;
o $0.8 million on gas processing plants; and
o $0.2 million for computer equipment, software, furniture, and fixtures.
In 2005, we participated in drilling 45 domestic development wells and nine
domestic exploratory wells, of which 37 development wells and five exploratory
wells were completed. In New Zealand we drilled five development wells, of which
two were completed, and five exploratory wells, of which one was completed.
New Accounting Pronouncements
Effective January 1, 2006, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 123 (R), "Share-Based Payment" (SFAS No. 123R)
utilizing the modified prospective approach. Prior to the adoption of SFAS No.
123R, we accounted for stock option grants in accordance with Accounting
Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to
Employees" (the intrinsic value method), and accordingly, recognized no
compensation expense for employee stock option grants. Under the modified
prospective approach, SFAS No. 123R applies to new awards and to awards that
were outstanding on January 1, 2006 as well as those that are subsequently
modified, repurchased or cancelled. Under the modified prospective approach,
compensation cost recognized for the year ended December 31, 2006 includes
compensation cost for all share-based awards granted prior to, but not yet
vested as of January 1, 2006, based on the grant-date fair value estimated in
accordance with the original provisions of SFAS No. 123, and compensation cost
for all share-based awards granted subsequent to January 1, 2006, based on the
grant-date fair value estimated in accordance with the provisions of SFAS No.
123R. Prior periods were not restated to reflect the impact of adopting the new
standard. As a result of adopting SFAS No. 123R on January 1, 2006, our income
before taxes, net income and basic and diluted earnings per share for the year
ended December 31, 2006, were $3.4 million, $2.8 million, $0.09, and $0.09
lower, respectively. Upon adoption of SFAS 123R, we recorded an immaterial
cumulative effect of a change in accounting principle as a result of our change
in policy from recognizing forfeitures as they occur to one recognizing expense
based on our expectation of the amount of awards that will vest over the
requisite service period for our restricted stock awards. This amount was
recorded in "General and Administrative, net" in the accompanying consolidated
statements of income.
In September 2006, the SEC released SAB 108, "Considering the Effects of
Prior Year Misstatements when Quantifying Misstatements in Current Year
Financial Statements" ( SAB 108). SAB 108 addresses the process of quantifying
financial statement misstatements, such as assessing both the carryover and
reversing effects of prior year misstatements on the current year financial
statements. SAB 108 became effective for our fiscal year ended December 31,
2006. The adoption of this statement had no impact on our financial position or
results of operations.
40
In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting
for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109."
This Interpretation provides guidance for recognizing and measuring uncertain
tax positions, as defined in SFAS No. 109, "Accounting for Income Taxes." FIN
No. 48 prescribes a threshold condition that a tax position must meet for any of
the benefit of the uncertain tax position to be recognized in the financial
statements. Guidance is also provided regarding derecognition, classification
and disclosure of these uncertain tax positions. FIN No. 48 is effective for
fiscal years beginning after December 15, 2006. The adoption of this
Interpretation is not expected to have a material impact on its financial
position or results of operations.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements.
SFAS No. 157 addresses how companies should approach measuring fair value when
required by GAAP; it does not create or modify any current GAAP requirements to
apply fair value accounting. SFAS No. 157 provides a single definition for fair
value that is to be applied consistently for all accounting applications, and
also generally describes and prioritizes, according to reliability, the methods
and inputs used in valuations. SFAS No. 157 prescribes various disclosures about
financial statement categories and amounts which are measured at fair value, if
such disclosures are not already specified elsewhere in GAAP. The new
measurement and disclosure requirements of SFAS No. 157 are effective for us in
the first quarter 2008. The Company has not yet determined what impact, if any,
this statement will have on its financial position or results of operations.
41
Proved Oil and Gas Reserves
At year-end 2006, our total proved reserves were 816.8 Bcfe with a PV-10
Value of $2.7 billion (PV-10 is a non-GAAP measure, see the section titled "Oil
and Natural Gas Reserves" in our Property section for a reconciliation of this
non-GAAP measure to the closest GAAP measure, the standardized measure). In
2006, our proved natural gas reserves increased 36.7 Bcf, or 13%, while our
proved oil reserves increased 4.0 MMBbl, or 6%, and our NGL reserves decreased
0.9 MMBbl, or 6%, for a total equivalent increase of 55.1 Bcfe, or 7%. In 2005,
our proved natural gas reserves decreased by 30.8 Bcf, or 10%, while our proved
oil reserves decreased by 0.7 MMBbl, or 1%, and our NGL reserves decreased by
0.5 MMBbl, or 3%, for a total equivalent decrease of 38.1 Bcfe, or 5%. We added
reserves over the past three years through both our drilling activity and
purchases of minerals in place. Through drilling we added 72.8 Bcfe (1.2 Bcfe of
which came from New Zealand) of proved reserves in 2006, 31.6 Bcfe (2.0 Bcfe of
which came from New Zealand) in 2005, and 7.2 Bcfe (all of which was domestic)
in 2004. Through acquisitions we added 77.8 Bcfe of proved reserves in 2006,
28.9 Bcfe in 2005, and 43.4 Bcfe in 2004. At year-end 2006, 44% of our total
proved reserves were proved developed, compared with 50% at year-end 2005 and
56% at year-end 2004.
Despite increased reserves volumes, the PV-10 Value of our total proved
reserves at year-end 2006 decreased 15% from the PV-10 Value at year-end 2005.
Gas prices decreased in 2006 to $5.46 per Mcf from $8.94 per Mcf at year-end
2005, compared to $5.16 per Mcf at year-end 2004. Oil prices increased in 2006
to $60.41 per Bbl from $60.12 per Bbl at year-end 2005, compared to $41.07 in
2004. Under SEC guidelines, estimates of proved reserves must be made using
year-end oil and gas sales prices and are held constant for that year's reserves
calculation throughout the life of the properties. Subsequent changes to such
year-end oil and gas prices could have a significant impact on the calculated
PV-10 Value.
Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 1 to the consolidated
financial statements.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States ("GAAP")
requires us to make estimates and assumptions that affect the reported amount of
certain assets and liabilities and the reported amounts of certain revenues and
expenses during each reporting period. We believe our estimates and assumptions
are reasonable; however, such estimates and assumptions are subject to a number
of risks and uncertainties that may cause actual results to differ materially
from such estimates. Significant estimates and assumptions underlying these
financial statements include:
o the estimated quantities of proved oil and natural gas reserves
used to compute depletion of oil and natural gas properties and
the related present value of estimated future net cash flows
there-from,
o accruals related to oil and gas revenues, capital expenditures
and lease operating expenses,
o estimates of insurance recoveries related to property damage,
42
o estimates in the calculation of stock compensation expense,
o estimates of our ownership in properties prior to final division
of interest determination,
o the estimated future cost and timing of asset retirement
obligations, and
o estimates made in our income tax calculations.
While we are not aware of any material revisions to any of our estimates,
there will likely be future revisions to our estimates resulting from matters
such as changes in new accounting pronouncements, ownership interests, payouts,
joint venture audits, re-allocations by purchasers or pipelines, or other
corrections and adjustments common in the oil and gas industry, many of which
require retroactive application. These types of adjustments cannot be currently
estimated and will be recorded in the period during which the adjustment occurs.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Such costs may be incurred
both prior to and after the acquisition of a property and include lease
acquisitions, geological and geophysical services, drilling, completion, and
equipment. Internal costs incurred that are directly identified with
exploration, development, and acquisition activities undertaken by us for our
own account, and which are not related to production, general corporate
overhead, or similar activities, are also capitalized. For the years 2006, 2005,
and 2004, such internal costs capitalized totaled $28.3 million, $18.8 million,
and $13.1 million, respectively. Interest costs are also capitalized to unproved
oil and gas properties. For the years 2006, 2005, and 2004, capitalized interest
on unproved properties totaled $9.2 million, $7.2 million, and $6.5 million,
respectively. Interest not capitalized and general and administrative costs
related to production and general overhead are expensed as incurred.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties (including gas processing facilities,
capitalized asset retirement obligations, net of related salvage values and
deferred income taxes, and excluding the recognized asset retirement obligation
liability) is limited to the sum of the estimated future net revenues from
proved properties (excluding cash outflows from recognized asset retirement
obligations, including future development and abandonment costs of wells to be
drilled, using period-end prices, adjusted for the effects of hedging,
discounted at 10%, and the lower of cost or fair value of unproved properties)
adjusted for related income tax effects ("Ceiling Test"). Our hedges at December
31, 2006 consisted of natural gas price floors with strike prices higher than
the period-end price and did not materially affect prices used in this
calculation. This calculation is done on a country-by-country basis.
The calculation of the Ceiling Test and provision for DD&A is based on
estimates of proved reserves. There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting the future rates of
production, timing, and plan of development. The accuracy of any reserves
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify revision of such
estimates. Accordingly, reserves estimates are often different from the
quantities of oil and gas that are ultimately recovered. Our reserves estimates
are prepared in accordance with Securities and Exchange Commission guidelines;
and, are audited on an annual basis at year-end by a firm of independent
petroleum engineers in accordance with standards approved by the Board of
Directors of the Society of Petroleum Engineers.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from our
period-end prices used in the Ceiling Test, even if only for a short period, it
is possible that non-cash write-downs of oil and gas properties could occur in
the future. If we have declines in our oil and gas reserves volumes, which also
reduce our estimate of discounted future net cash flows from proved oil and gas
reserves, a non-cash write-down of our oil and gas properties could occur in the
future.
Price-Risk Management Activities. The Company follows SFAS No. 133, which
requires that changes in the derivative's fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) is recorded in the balance sheet as either an asset or a liability
measured at its fair value. Hedge accounting for a qualifying hedge allows the
gains and losses on derivatives to offset related results on the hedged item in
the income statements and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
Changes in the fair value of derivatives that do not meet the criteria for hedge
accounting, and the ineffective portion of the hedge, are recognized currently
in income.
43
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
price floors and collars. During 2006, 2005 and 2004, we recognized net gains of
$4.0 million, and net losses of $1.1 million and $1.3 million, respectively,
relating to our derivative activities. This activity is recorded in "Price-risk
management and other, net" on the accompanying statements of income. At December
31, 2006, the Company had recorded $0.3 million, net of taxes of less than $0.2
million, of derivative gains in "Accumulated other comprehensive income (loss),
net of income tax" on the accompanying balance sheet. This amount represents the
change in fair value for the effective portion of our hedging transactions that
qualified as cash flow hedges. The ineffectiveness reported in "Price-risk
management and other, net" for 2006, 2005, and 2004 was not material. We expect
to reclassify all amounts currently held in "Accumulated other comprehensive
income (loss), net of income tax" into the statement of income within the next
three months when the forecasted sale of hedged production occurs.
At December 31, 2006, we had in place price floors in effect for February
2007 through the March 2007 contract month for natural gas, that cover a portion
of our domestic natural gas production for February 2007 to March 2007. The
natural gas price floors cover notional volumes of 800,000 MMBtu, with a
weighted average floor price of $7.00 per MMBtu. Our natural gas price floors in
place at December 31, 2006 are expected to cover approximately 25% to 30% of our
estimated domestic natural gas production from February 2007 to March 2007.
When we entered into these transactions discussed above, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of natural gas production. Changes in the fair value of a hedge
that is highly effective and is designated and documented and qualifies as a
cash flow hedge, to the extent that the hedge is effective, are recorded in
"Accumulated other comprehensive income (loss), net of income tax." When the
hedged transactions are recorded upon the actual sale of the natural gas, these
gains or losses are reclassified from "Accumulated other comprehensive income
(loss), net of income tax" and recorded in "Price-risk management and other,
net" on the accompanying statement of income. The fair value of our derivatives
is computed using the Black-Scholes-Merton option pricing model and is
periodically verified against quotes from brokers. The fair value of these
instruments at December 31, 2006, was $0.7 million and is recognized on the
accompanying balance sheet in "Other current assets."
Revenue Recognition. Oil and gas revenues are recognized when production is
sold to a purchaser at a fixed or determinable price, when delivery has occurred
and title has transferred, and if collectibility of the revenue is probable.
Processing costs for natural gas and natural gas liquids ("NGLs") that are paid
in-kind are deducted from revenues. The Company uses the entitlement method of
accounting in which the Company recognizes its ownership interest in production
as revenue. If our sales exceed our ownership share of production, the natural
gas balancing payables are reported in "Accounts payable and accrued
liabilities" on the accompanying balance sheet. Natural gas balancing
receivables are reported in "Other current assets" on the accompanying balance
sheet when our ownership share of production exceeds sales. As of December 31,
2006, we did not have any material natural gas imbalances.
Asset Retirement Obligation. In June 2001, the Financial Accounting
Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the carrying amount of the related long-lived
asset is increased. The liability is discounted from the year the well is
expected to deplete. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depreciated on a unit-of-production basis
over the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss which increases or decreases the full cost pool. This standard requires us
to record a liability for the fair value of our dismantlement and abandonment
costs, excluding salvage values. Based on our experience and analysis of the oil
and gas services industry, we have not factored a market risk premium into our
asset retirement obligation. SFAS No. 143 was adopted by us effective January 1,
2003.
See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"
for additional discussion of commodity risk.
Stock Based Compensation. We have three stock-based compensation plans,
which are described more fully in Note 6 to our accompanying consolidated
financial statements. We account for those plans under the recognition and
measurement principles of SFAS 123R, "Share-Based Compensation," and related
interpretations.
Foreign Currency. We use the U.S. Dollar as our functional currency in New
Zealand. The functional currency is determined by examining the entities' cash
flows, commodity pricing, environment and financing arrangements. We have both
assets and liabilities denominated in New Zealand Dollars, the New Zealand
44
"Deferred income taxes" and a portion of our "Asset Retirement Obligation" on
the accompanying balance sheet. For accounts other than "Deferred income taxes,"
as the currency rate changes between the U.S. Dollar and the New Zealand Dollar,
we recognize transaction gains and losses in "Price-risk management and other,
net" on the accompanying statements of income. We recognize transaction gains
and losses on "Deferred income taxes" in "Provision for Income Taxes" on the
accompanying statement of income.
Related-Party Transactions
We were the operator of a number of properties owned by affiliated limited
partnerships and, accordingly, charge these entities operating fees. The
operating fees charged to the partnerships totaled the same $0.2 million in
2006, 2005 and 2004, and are recorded as reductions of general and
administrative, net. We also have been reimbursed for administrative, and
overhead costs incurred in conducting the business of the limited partnerships,
which totaled $0.1 million per year in 2006 and 2005, and $0.2 million in 2004,
and are recorded as reductions in general and administrative, net. As of
December 31, 2006, the remaining two partnerships have been dissolved.
We receive research, technical writing, publishing, and website-related
services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and
controlled and majority owned by the aunt of the Company's Chairman of the Board
and Chief Executive Officer. We paid approximately $0.5 million to Tec-Com for
such services pursuant to the terms of the contract between the parties in 2006,
and $0.4 million per year in 2005 and 2004. The contract was renewed June 30,
2004, on substantially the same terms and expires June 30, 2007. We believe that
the terms of this contract are consistent with third party arrangements that
provide similar services.
As a matter of corporate governance policy and practice, related party
transactions are annually presented and considered by the Corporate Governance
Committee of our Board of Directors in accordance with the Committee's charter.
45
Forward-Looking Statements
The statements contained in this report that are not historical facts are
forward-looking statements as that term is defined in Section 21E of the
Securities Exchange Act of 1934, as amended. Such forward-looking statements may
pertain to, among other things, financial results, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory
matters, and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "future," "estimate," "expect," "budget,"
"predict," "anticipate," "projected," "should," "believe," or other words that
convey the uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations, estimates,
and assumptions, upon current market conditions, and upon engineering and
geologic information available at this time, and is subject to change and to a
number of risks and uncertainties, and, therefore, actual results may differ
materially. Among the factors that could cause actual results to differ
materially are: volatility in oil and natural gas prices, internationally or in
the United States; availability of services and supplies; disruption of
operations and damages due to hurricanes or tropical storms; fluctuations of the
prices received or demand for our oil and natural gas; the uncertainty of
drilling results and reserve estimates; operating hazards; requirements for
capital; general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed in this report and
set forth from time to time in our other public reports, filings, and public
statements.
46
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
such pricing volatility are expected to continue.
Our price-risk management policy permits the utilization of agreements and
financial instruments (such as futures, forward contracts, swaps and options
contracts) to mitigate price risk associated with fluctuations in oil and
natural gas prices. Below is a description of the financial instruments we have
utilized to hedge our exposure to price risk.
oPrice Floors - At December 31, 2006, we had in place price floors in
effect through the March 2007 contract month for natural gas. The natural
gas price floors cover notional volumes of 800,000 MMBtu, with a weighted
average floor price of $7.00 per MMBtu. Our natural gas price floors in
place at December 31, 2006 are expected to cover approximately 25% to 30%
of our domestic natural gas production in February 2007 and March 2007.
The fair value of these instruments at December 31, 2006, was $0.7 million
and is recognized on the accompanying balance sheet in "Other current
assets." There are no additional cash outflows for these price floors, as
the cash premium was paid at inception of the hedge. The maximum loss that
could be sustained from these price floors in 2007 would be their fair
value at December 31, 2006 of $0.7 million.
oNew Zealand Gas Contracts - All of our gas production in New Zealand is
sold under long-term, fixed-price contracts denominated in New Zealand
Dollars. These contracts protect against price volatility, and our revenue
from these contracts will vary only due to production fluctuations and
foreign exchange rates.
Interest Rate Risk. Our senior notes and senior subordinated notes both
have fixed interest rates, so consequently we are not exposed to cash flow risk
from market interest rate changes on these notes. At December 31, 2006, we had
borrowings of $31.4 million under our credit facility, which bears a floating
rate of interest and therefore is susceptible to interest rate fluctuations. The
result of a 10% fluctuation in the bank's base rate would constitute 83 basis
points and would not have a material adverse effect on our 2007 cash flows based
on this same level or a modest level of borrowing.
Income Tax Carryforwards. We had significant foreign net operating loss
carryforwards at December 31, 2006. The foreign net operating losses have no
expiration period, but would be cancelled if a change in control occurred at
either the subsidiary or ultimate parent company level. Other loss carryforwards
consist of state net operating losses and capital losses. The Company has not
recorded a valuation allowance against the deferred tax assets attributable to
the net operating carryovers at December 31, 2006, as management estimates that
it is more likely than not that these assets will be fully utilized before they
expire. The foreign net operating loss has no expiration period, but it would be
cancelled if a change in control occurred at either the subsidiary or ultimate
parent company level. A valuation allowance has been applied against the capital
loss carryforward, as detailed in Note 3 of the accompanying consolidated
financial statements. Significant changes in estimates caused by changes in oil
and gas prices, production levels, capital expenditures, and other variables
could impact the Company's ability to utilize the carryover amounts. If we are
not able to use our carryforwards, our results of operations and cash flows will
be negatively impacted.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and senior notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid or short-term nature of these instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2006 and
2005, and were determined based upon variable interest rates currently available
to us for borrowings with similar terms. Based upon quoted market prices as of
December 31, 2006 and 2005, the fair values of our senior subordinated notes due
2012 were $211.0 million, or 105.5% of face value, and $214.5 million, or
107.25% of face value, respectively. Based upon quoted market prices as of
December 31, 2006 and 2005, the fair values of our senior notes due 2011 were
$152.6 million, or 101.75% of face value, and $153.8 million, or 102.5% of face
value. The carrying value of our senior subordinated notes due 2012 was $200.0
million at December 31 for both 2006 and 2005. The carrying value of our senior
notes due 2011 was $150.0 million at December 31 for both 2006 and 2005.
Foreign Currency Risk. We are exposed to the risk of fluctuations in
foreign currencies, most notably the New Zealand Dollar. Fluctuations in rates
between the New Zealand Dollar and U.S. Dollar may impact our financial results
from our New Zealand subsidiaries since we have receivables, liabilities,
47
natural gas and NGL sales contracts, and New Zealand income tax calculations,
all denominated in New Zealand Dollars. We use the U.S. Dollar as our functional
currency in New Zealand and because of this, our results of operations, cash
flows and effective tax rate are impacted from fluctuations between the U.S.
Dollar and the New Zealand Dollar.
Customer Credit Risk. We are exposed to the risk of financial
non-performance by customers. Our ability to collect on sales to our customers
is dependent on the liquidity of our customer base. To manage customer credit
risk, we monitor credit ratings of customers and seek to minimize exposure to
any one customer where other customers are readily available. Due to
availability of other purchasers, we do not believe the loss of any single oil
or gas customer would have a material adverse effect on our results of
operations.
48
Item 8. Financial Statements and Supplementary Data Page
Management's Report on Internal Control
Over Financial Reporting.............................................49
Reports of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting.....................................50
Reports of Independent Registered Public Accounting Firm on
Consolidated Financial Statements....................................51
Consolidated Balance Sheets.................................................52
Consolidated Statements of Income...........................................53
Consolidated Statements of Stockholders' Equity.............................54
Consolidated Statements of Cash Flows.......................................55
Notes to Consolidated Financial Statements..................................56
1. Summary of Significant Accounting Policies............................56
2. Earnings Per Share....................................................63
3. Provision for Income Taxes............................................65
4. Long-Term Debt .......................................................67
5. Commitments and Contingencies.........................................69
6. Stockholders' Equity..................................................69
7. Related-Party Transactions............................................73
8. Foreign Activities....................................................73
9. Acquisitions and Dispositions.........................................73
10. Condensed Consolidating Financial Information.........................74
11. Segment Information...................................................80
Supplementary Information...................................................82
Oil and Gas Operations (Unaudited)..........................................82
Selected Quarterly Financial Data (Unaudited)...............................88
49
Management's Report on Internal Control Over Financial Reporting
Management of Swift Energy Company is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The
Company's internal control over financial reporting is a process designed by, or
under the supervision of, the Company's Chief Executive Officer and Chief
Financial Officer to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of the Company's financial statements
for external purposes in accordance with U. S. generally accepted accounting
principles.
Management of the Company assessed the effectiveness of the Company's
internal control over financial reporting as of December 31, 2006. In making
this assessment, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control--Integrated Framework. Based on our assessment and those criteria,
management determined that the Company maintained effective internal control
over financial reporting as of December 31, 2006.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
Ernst & Young LLP, the independent registered public accounting firm that
audited the consolidated financial statements of the Company included in this
Annual Report on Form 10-K, has issued an attestation report on management's
assessment of the Company's internal control over financial reporting as of
December 31, 2006. That report, which expresses unqualified opinions on
management's assessment and on the effectiveness of the Company's internal
control over financial reporting as of December 31, 2006 appears on the
following page.
50
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of Swift Energy Company
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting that Swift
Energy Company and subsidiaries maintained effective internal control over
financial reporting as of December 31, 2006, based on criteria established in
Internal Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Swift Energy
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the company's
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.
A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that Swift Energy Company and
subsidiaries maintained effective internal control over financial reporting as
of December 31, 2006, is fairly stated, in all material respects, based on the
COSO criteria. Also, in our opinion, Swift Energy Company and subsidiaries
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Swift Energy Company and subsidiaries as of December 31, 2006 and
2005, and the related consolidated statements of income, stockholders' equity,
and cash flows for each of the three years in the period ended December 31, 2006
and our report dated February 27, 2007 expressed an unqualified opinion thereon.
ERNST & YOUNG. LLP
Houston, Texas
February 27, 2007
51
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of Swift Energy Company
We have audited the accompanying consolidated balance sheets of Swift Energy
Company and subsidiaries as of December 31, 2006 and 2005, and the related
consolidated statements of income, stockholders' equity, and cash flows for each
of the three years in the period ended December 31, 2006. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Swift Energy
Company and subsidiaries at December 31, 2006 and 2005, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2006, in conformity with U.S. generally accepted
accounting principles.
As discussed in Note 1 to the consolidated financial statements, in 2006 the
Company changed its method of accounting for stock-based compensation.
We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of Swift
Energy Company and subsidiaries internal control over financial reporting as of
December 31, 2006, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 27, 2007 expressed an unqualified
opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
February 27, 2007
52
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
December 31, 2006 December 31, 2005
--------------------- -------------------
ASSETS
Current Assets:
Cash and cash equivalents $ 1,058,051 $ 53,004,562
Accounts receivable-
Oil and gas sales 63,935,441 45,518,260
Joint interest owners 1,843,824 1,082,187
Other Receivables 1,231,384 3,795,080
Deferred Tax Asset 2,383,176 ---
Other current assets 22,121,165 11,655,046
--------------------- -------------------
Total Current Assets 92,573,041 115,055,135
--------------------- -------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties 2,264,831,638 1,731,866,298
Unproved properties 112,136,836 87,553,220
--------------------- -------------------
2,376,968,474 1,819,419,518
Furniture, fixtures, and other equipment 28,040,405 15,313,277
--------------------- -------------------
2,405,008,879 1,834,732,795
Less - Accumulated depreciation, depletion, and amortization (921,696,714) (755,699,056)
--------------------- -------------------
1,483,312,165 1,079,033,739
--------------------- -------------------
Other Assets:
Debt issuance costs 7,382,265 8,026,780
Restricted assets 2,414,287 2,296,968
--------------------- -------------------
9,796,552 10,323,748
--------------------- -------------------
$ 1,585,681,758 $ 1,204,412,622
===================== ===================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 74,425,082 $ 51,973,004
Accrued capital costs 55,282,001 30,073,728
Accrued interest 8,764,278 8,508,196
Undistributed oil and gas revenues 7,503,927 7,866,086
--------------------- -------------------
Total Current Liabilities 145,975,288 98,421,014
--------------------- -------------------
Long-Term Debt 381,400,000 350,000,000
Deferred Income Taxes 224,966,598 129,306,891
Asset Retirement Obligation 33,694,603 19,095,368
Lease Incentive Obligation 1,728,297 271,182
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none
outstanding --- ---
Common stock, $.01 par value, 85,000,000 shares authorized, 30,170,004
and 29,458,974 shares issued, and 29,742,918 and 29,009,530 shares
outstanding, respectively 301,700 294,590
Additional paid-in capital 387,555,797 365,085,695
Treasury stock held, at cost, 427,086 and 449,444 shares, respectively (6,124,944) (6,445,586)
Unearned compensation --- (5,849,820)
Retained earnings 415,868,097 254,302,757
Accumulated other comprehensive income (loss), net of income tax 316,322 (69,469)
--------------------- -------------------
797,916,972 607,318,167
--------------------- -------------------
$ 1,585,681,758 $ 1,204,412,622
===================== ===================
See accompanying Notes to Consolidated Financial Statements.
53
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
Year Ended December 31,
2006 2005 2004
---------------- ---------------- ---------------
Revenues:
Oil and gas sales $ 601,551,368 $ 423,766,245 $ 311,285,172
Price-risk management and other, net 13,889,862 (539,756) (1,008,398)
---------------- ---------------- ---------------
615,441,230 423,226,489 310,276,774
---------------- ---------------- ---------------
Costs and Expenses:
General and administrative, net 31,316,644 22,176,362 17,787,125
Depreciation, depletion, and amortization 169,295,774 107,477,787 81,580,828
Accretion of asset retirement obligation 1,034,322 761,042 673,654
Lease operating cost 62,474,619 47,321,841 41,214,256
Severance and other taxes 65,452,043 42,176,505 30,401,293
Interest expense, net 23,581,663 24,873,401 27,643,108
Debt retirement cost --- --- 9,536,268
---------------- ---------------- ---------------
353,155,065 244,786,938 208,836,532
---------------- ---------------- ---------------
Income Before Income Taxes 262,286,165 178,439,551 101,440,242
Provision for Income Taxes 100,720,825 62,661,095 32,989,325
---------------- ---------------- ---------------
Net Income $ 161,565,340 $ 115,778,456 $ 68,450,917
================ ================ ===============
Per Share Amounts-
Basic: Net Income $ 5.52 $ 4.06 $ 2.46
================ ================ ===============
Diluted: Net Income $ 5.38 $ 3.95 $ 2.41
================ ================ ===============
Weighted Average Shares Outstanding 29,265,366 28,496,275 27,822,413
================ ================= ===============
See accompanying Notes to Consolidated Financial Statements.
54
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
Accumulated
Additional Other
Common Paid-in Treasury Unearned Retained Comprehensive
Stock (1) Capital Stock Compensation Earnings Income (Loss) Total
--------- ------------- ------------- ------------ ------------- -------------- -------------
Balance, December 31, 2003 $ 280,111 $ 334,865,204 $ (7,558,093) $ - $ 70,073,384 $ (269,342) $ 397,391,264
Stock issued for benefit
plans (46,150 shares) - 166,298 661,848 - - - 828,146
Stock options exercised
(509,105 shares) 5,091 4,260,882 - - - - 4,265,973
Tax benefits from exercise
of stock Options - 1,956,555 - - - - 1,956,555
Employee stock purchase
plan (50,418 shares) 504 502,097 - - - - 502,601
Grants of restricted
stock (100,900 shares) - 1,785,262 - (1,785,262) - - -
Amortization of restricted
stock compensation - - - 56,677 - - 56,677
Comprehensive income:
Net income - - - - 68,450,917 - 68,450,917
Change in fair value of
other comprehensive
income - - - - - 720,007 720,007
-------------
Total comprehensive
income - - - - - - 69,170,924
--------- ------------- ------------- ------------ ------------- -------------- -------------
Balance, December 31, 2004 $ 285,706 $ 343,536,298 $ (6,896,245) $ (1,728,585) $ 138,524,301 $ 450,665 $ 474,172,140
========= ============= ============= ============ ============= ============== =============
Stock issued for benefit
plans (31,424 shares) - 435,134 450,659 - - - 885,793
Stock options exercised
(840,847 shares) 8,409 9,804,555 - - - - 9,812,964
Tax benefits from
exercise of stock options - 4,366,236 - - - - 4,366,236
Employee stock purchase
plan (32,495 shares) 325 642,354 - - - - 642,679
Issuance of restricted
stock (15,000 shares) 150 - - - - - 150
Grants of restricted
stock (158,500 shares) - 6,668,608 - (6,072,008) - - 596,600
Forfeitures of restricted
stock - (367,490) - 367,490 - - -
Amortization of
restricted stock
compensation - - - 1,583,283 - - 1,583,283
Comprehensive income:
Net income - - - - 115,778,456 - 115,778,456
Change in fair value of
other comprehensive loss - - - - - (520,134) (520,134)
-------------
Total comprehensive
income - - - - - - 115,258,322
--------- ------------- ------------- ------------ ------------- -------------- -------------
Balance, December 31, 2005 $ 294,590 $ 365,085,695 $ (6,445,586) $ (5,849,820) $ 254,302,757 $ (69,469) $ 607,318,167
========= ============= ============= ============ ============= ============== =============
Stock issued for benefit
plans (22,358 shares) - 714,049 320,642 - - - 1,034,691
Stock options exercised
(652,829 shares) 6,528 11,830,763 - - - - 11,837,291
Adoption of SFAS No.123R - (5,875,280) - 5,849,820 - - (25,460)
Excess tax benefits from
stock-based awards - 4,811,362 - - - - 4,811,362
Employee stock purchase
plan (22,425 shares) 224 671,106 - - - - 671,330
Issuance of restricted
stock (35,776 shares) 358 (358) - - - - -
Amortization of stock
compensation - 10,318,460 - - - - 10,318,460
Comprehensive Income:
Net income - - - - 161,565,340 - 161,565,340
Other comprehensive
income - - - - - 385,791 385,791
-------------
Total comprehensive
income - - - - - - 161,951,131
--------- ------------- ------------- ------------ ------------- -------------- -------------
Balance, December 31, 2006 $ 301,700 $ 387,555,797 $ (6,124,944) $ - $ 415,868,097 $ 316,322 $ 797,916,972
========= ============= ============= ============ ============= ============== =============
(1)$.01 par value.
See accompanying Notes to Consolidated Financial Statements.
55
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
Year Ended December 31,
------------------------------------------------------
2006 2005 2004
----------------- ----------------- ----------------
Cash Flows from Operating Activities:
Net income $ 161,565,340 $ 115,778,456 $ 68,450,917
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization 169,295,774 107,477,787 81,580,828
Accretion of asset retirement obligation 1,034,322 761,042 673,654
Deferred income taxes 90,027,972 61,911,095 32,513,325
Stock-based compensation expense 6,905,260 1,450,600 57,709
Debt retirement cost - cash and non-cash --- --- 9,536,268
Other 3,225,561 362,013 (357,164)
Change in assets and liabilities-
Increase in accounts receivable (19,178,818) (6,778,383) (11,040,543)
Increase in accounts payable and accrued
liabilities 10,905,914 5,071,870 843,341
Increase (decrease) in income taxes payable 883,639 --- (135,984)
Increase (decrease) in accrued interest 256,082 (700,996) 460,536
----------------- ---------------- ----------------
Net Cash Provided by Operating Activities 424,921,046 285,333,484 182,582,887
----------------- ---------------- ----------------
Cash Flows from Investing Activities:
Additions to property and equipment (363,222,113) (235,547,815) (171,095,101)
Proceeds from the sale of property and equipment 24,678,020 7,296,833 5,058,147
Acquisition of properties (194,269,399) (28,927,091) (27,196,336)
Net cash received as operator of oil and gas properties 9,385,700 17,797,022 3,921,673
Net cash received (distributed) as operator of
partnerships 409,816 (948,292) 884,093
Other (528,415) 255,189 (658,630)
----------------- ---------------- ----------------
Net Cash Used in Investing Activities (523,546,391) (240,074,154) (189,086,154)
----------------- ---------------- ----------------
Cash Flows from Financing Activities:
Proceeds from long-term debt --- --- 150,000,000
Payments of long-term debt --- --- (125,000,000)
Net proceeds from (payments of) bank borrowings 31,400,000 (7,500,000) (8,400,000)
Net proceeds from issuances of common stock 12,508,621 10,325,114 4,825,251
Excess tax benefits from stock-based awards 3,327,713 --- ---
Payments of debt retirement costs --- --- (6,734,611)
Payments of debt issuance costs (557,500) --- (4,333,535)
----------------- ---------------- ----------------
Net Cash Provided by Financing Activities 46,678,834 2,825,114 10,357,105
----------------- ---------------- ----------------
Net Increase (Decrease) in Cash and Cash Equivalents $ (51,946,511) $ 48,084,444 $ 3,853,838
Cash and Cash Equivalents at Beginning of Year 53,004,562 4,920,118 1,066,280
----------------- ---------------- ----------------
Cash and Cash Equivalents at End of Year $ 1,058,051 $ 53,004,562 $ 4,920,118
================= ================ ================
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 22,690,797 $ 24,482,934 $ 26,064,158
Cash paid during year for income taxes $ 9,779,500 $ 750,000 $ 476,000
See accompanying Notes to Consolidated Financial Statements.
56
Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1. Summary of Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company ("Swift Energy") and its
wholly owned subsidiaries, which are engaged in the exploration, development,
acquisition, and operation of oil and natural gas properties, with a focus on
inland waters and onshore oil and natural gas reserves in Louisiana and Texas,
as well as onshore oil and natural gas reserves in New Zealand. Our undivided
interests in gas processing plants are accounted for using the proportionate
consolidation method, whereby our proportionate share of each entity's assets,
liabilities, revenues, and expenses are included in the appropriate
classifications in the accompanying consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
accompanying consolidated financial statements.
Holding Company Structure. In December 2005, we implemented a holding
company structure pursuant to Texas and federal law in a manner designed to be a
non-taxable transaction. The new parent holding company assumed the Swift Energy
Company name and its common stock and continued to trade on the New York Stock
Exchange. The purposes of this new holding company structure are to separate
Swift Energy's domestic and international operations to better reflect
management practices, to improve our economics, and to provide greater
administrative and organizational flexibility. Under the new organizational
structure, four new subsidiaries were formed with the Texas parent holding
company wholly owning four Delaware subsidiaries, which in turn wholly own Swift
Energy's operating subsidiaries. Swift Energy Operating, LLC is the operator of
record for Swift Energy's domestic properties. Swift Energy's name, charter,
bylaws, officers, board of directors, authorized shares and shares outstanding
remain substantially identical. The Company's international operations continue
to be conducted through Swift Energy International, Inc. Swift Energy made
amendments to its bank credit agreement, debt indentures and various other plans
and documents to accommodate the internal reorganization, but the Company's
day-to-day conduct of business was not impacted. Accordingly, there was no
impact on our financial position or results of operations.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States ("GAAP")
requires us to make estimates and assumptions that affect the reported amount of
certain assets and liabilities and the reported amounts of certain revenues and
expenses during each reporting period. We believe our estimates and assumptions
are reasonable; however, such estimates and assumptions are subject to a number
of risks and uncertainties that may cause actual results to differ materially
from such estimates. Significant estimates and assumptions underlying these
financial statements include:
o the estimated quantities of proved oil and natural gas reserves
used to compute depletion of oil and natural gas properties and
the related present value of estimated future net cash flows
there-from,
o accruals related to oil and gas revenues, capital expenditures
and lease operating expenses,
o estimates of insurance recoveries related to property damage,
o estimates in the calculation of stock compensation expense,
o estimates of our ownership in properties prior to final division
of interest determination,
o the estimated future cost and timing of asset retirement
obligations, and
o estimates made in our income tax calculations.
While we are not aware of any material revisions to any of our estimates,
there will likely be future revisions to our estimates resulting from matters
such as new accounting pronouncements, changes in ownership interests, payouts,
joint venture audits, re-allocations by purchasers or pipelines, or other
corrections and adjustments common in the oil and gas industry, many of which
require retroactive application. These types of adjustments cannot be currently
estimated and will be recorded in the period during which the adjustment occurs.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Such costs may be incurred
57
both prior to and after the acquisition of a property and include lease
acquisitions, geological and geophysical services, drilling, completion, and
equipment. Internal costs incurred that are directly identified with
exploration, development, and acquisition activities undertaken by us for our
own account, and which are not related to production, general corporate
overhead, or similar activities, are also capitalized. For the years 2006, 2005,
and 2004, such internal costs capitalized totaled $28.3 million, $18.8 million,
and $13.1 million, respectively. Interest costs are also capitalized to unproved
oil and gas properties. For the years 2006, 2005, and 2004, capitalized interest
on unproved properties totaled $9.2 million, $7.2 million, and $6.5 million,
respectively. Interest not capitalized and general and administrative costs
related to production and general corporate overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil and
gas properties, except in transactions involving a significant amount of
reserves or where the proceeds from the sale of oil and gas properties would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas attributable to a cost center. Internal costs associated
with selling properties are expensed as incurred.
Future development costs are estimated property-by-property based on
current economic conditions and are amortized to expense as our capitalized oil
and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization
("DD&A") of oil and gas properties by the unit-of-production method. Under this
method, we compute the provision by multiplying the total unamortized costs of
oil and gas properties--including future development costs, gas processing
facilities, and both capitalized asset retirement obligations and undiscounted
abandonment costs of wells to be drilled, net of salvage values, but excluding
costs of unproved properties--by an overall rate determined by dividing the
physical units of oil and gas produced during the period by the total estimated
units of proved oil and gas reserves at the beginning of the period. This
calculation is done on a country-by-country basis, and the period over which we
will amortize these properties is dependent on our production from these
properties in future years. Furniture, fixtures, and other equipment, recorded
at cost, are depreciated by the straight-line method at rates based on the
estimated useful lives of the property, which range between three and 20 years.
Repairs and maintenance are charged to expense as incurred. Renewals and
betterments are capitalized.
Geological and geophysical ("G&G") costs incurred on developed properties
are recorded in "Proved properties" and therefore subject to amortization. G&G
costs incurred that are directly associated with specific unproved properties
are capitalized in "Unproved properties" and evaluated as part of the total
capitalized costs associated with a prospect.
The cost of unproved properties not being amortized is assessed quarterly, on a
property-by-property basis, to determine whether such properties have been
impaired. In determining whether such costs should be impaired, we evaluate
current drilling results, lease expiration dates, current oil and gas industry
conditions, international economic conditions, capital availability, foreign
currency exchange rates, and available geological and geophysical information.
Any impairment assessed is added to the cost of proved properties being
amortized. To the extent costs accumulate in countries where there are no proved
reserves, any costs determined by management to be impaired are charged to
expense.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties (including gas processing facilities,
capitalized asset retirement obligations, net of related salvage values and
deferred income taxes, and excluding the recognized asset retirement obligation
liability) is limited to the sum of the estimated future net revenues from
proved properties (excluding cash outflows from recognized asset retirement
obligations, including future development and abandonment costs of wells to be
drilled, using period-end prices, adjusted for the effects of hedging,
discounted at 10%, and the lower of cost or fair value of unproved properties)
adjusted for related income tax effects ("Ceiling Test"). Our hedges at December
31, 2006 consisted of natural gas price floors with strike prices higher than
the period-end price but did not materially affect prices used in this
calculation. This calculation is done on a country-by-country basis.
The calculation of the Ceiling Test and provision for DD&A is based on
estimates of proved reserves. There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting the future rates of
production, timing, and plan of development. The accuracy of any reserves
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify revision of such
estimates. Accordingly, reserves estimates are often different from the
quantities of oil and gas that are ultimately recovered. Our reserves estimates
are prepared in accordance with Securities and Exchange Commission guidelines;
and, are audited on an annual basis at year-end by a firm of independent
petroleum engineers in accordance with standards approved by the Board of
Directors of the Society of Petroleum Engineers.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from our
58
period-end prices used in the Ceiling Test, even if only for a short period, it
is possible that non-cash write-downs of oil and gas properties could occur in
the future.
Revenue Recognition. Oil and gas revenues are recognized when production is
sold to a purchaser at a fixed or determinable price, when delivery has occurred
and title has transferred, and if collectibility of the revenue is probable.
Processing costs for natural gas and natural gas liquids ("NGLs") that are paid
in-kind are deducted from revenues. The Company uses the entitlement method of
accounting in which the Company recognizes its ownership interest in production
as revenue. If our sales exceed our ownership share of production, the natural
gas balancing payables are reported in "Accounts payable and accrued
liabilities" on the accompanying balance sheet. Natural gas balancing
receivables are reported in "Other current assets" on the accompanying balance
sheet when our ownership share of production exceeds sales. As of December 31,
2006, we did not have any material natural gas imbalances.
Accounts Receivable. We assess the collectibility of accounts receivable,
and based on our judgment, we accrue a reserve when we believe a receivable may
not be collected. At December 31, 2006 and 2005, we had an allowance for
doubtful accounts of approximately $0.1 million. The allowance for doubtful
accounts has been deducted from the total "Accounts receivable" balances on the
accompanying balance sheets.
Debt Issuance Costs. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in April
2002 of our 9-3/8% senior subordinated notes due 2012, the June 2004 extension
of our bank credit facility, and the public offering in June 2004 of our 7-5/8%
senior notes due 2011 were capitalized and are amortized on an effective
interest basis over the life of each of the respective note offerings and credit
facility. The 9-3/8% senior subordinated notes due 2012 mature on May 1, 2012,
and the balance of their issuance costs at December 31, 2006, was $3.6 million,
net of accumulated amortization of $2.0 million. The issuance costs associated
with our revolving credit facility, which was extended in October 2006, have
been capitalized and are being amortized over the life of the facility. The
balance of revolving credit facility issuance costs at December 31, 2006, was
$1.0 million, net of accumulated amortization of $2.0 million. The 7-5/8% senior
notes due 2011 mature on July 15, 2011, and the balance of their issuance costs
at December 31, 2006, was $2.8 million, net of accumulated amortization of $1.2
million.
Settlement of Insurance Claims. In 2006, we settled all insurance claims
with our insurers relating to hurricanes Katrina and Rita for approximately
$30.5 million and entered into a confidential final settlement agreement. The
receipt of these amounts resulted in a benefit of $7.7 million in 2006 recorded
in "Price-risk management and other, net," for the portion of the above
referenced settlement, which we have determined to be non-property damage
related claims. Approximately $22.8 million of the above referenced settlement
was determined to be property damage related claims. We recorded $14.1 million
of the property related settlement as a reduction to "Proved properties" on the
accompanying consolidated balance sheet, as this related to reimbursement of
capital costs we incurred. We also recorded $8.7 million of the property related
settlement as a reduction to "Lease operating cost" on the accompanying
consolidated statement of income, as this related to reimbursement of repair
costs which had been expensed as incurred. In the accompanying consolidated
statement of cash flows, we have recorded the reimbursement which reduced
"Proved properties" as a reduction of "Net Cash Used in Investing Activities"
and the remainder of the insurance settlement was recorded as an increase to
"Net Cash Provided by Operating Activities."
Limited Partnerships. In 2006, we served as managing general partner for
two private limited partnerships, and during fiscal 2006, less than 1% of our
total oil and gas sales was attributable to our general and limited partner
interests in those partnerships. These two partnerships were formed between 1996
and 1998, and were dissolved in December 2006.
Price-Risk Management Activities. The Company follows SFAS No. 133, which
requires that changes in the derivative's fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. The statement also
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) is recorded in the balance sheet as either an asset or a liability
measured at its fair value. Hedge accounting for a qualifying hedge allows the
gains and losses on derivatives to offset related results on the hedged item in
the income statements and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
Changes in the fair value of derivatives that do not meet the criteria for hedge
accounting, and the ineffective portion of the hedge, are recognized currently
in income.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase of
price floors and collars. During 2006, 2005 and 2004, we recognized net gains of
59
$4.0 million and net losses of $1.1 million and $1.3 million, respectively,
relating to our derivative activities. This activity is recorded in "Price-risk
management and other, net" on the accompanying statements of income. At December
31, 2006, the Company had recorded $0.3 million, net of taxes of less than $0.2
million, of derivative gains in "Accumulated other comprehensive income (loss),
net of income tax" on the accompanying balance sheet. This amount represents the
change in fair value for the effective portion of our hedging transactions that
qualified as cash flow hedges. The ineffectiveness reported in "Price-risk
management and other, net" for 2006, 2005, and 2004 was not material. We expect
to reclassify all amounts currently held in "Accumulated other comprehensive
income (loss), net of income tax" into the statement of income within the next
three months when the forecasted sale of hedged production occurs.
At December 31, 2006, we had in place price floors in effect for February
2007 through the March 2007 contract month for natural gas, that cover a portion
of our domestic natural gas production for February 2007 to March 2007. The
natural gas price floors cover notional volumes of 800,000 MMBtu, with a
weighted average floor price of $7.00 per MMBtu. Our natural gas price floors in
place at December 31, 2006 are expected to cover approximately 25% to 30% of our
estimated domestic natural gas production from February 2007 to March 2007.
When we entered into these transactions discussed above, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of natural gas production. Changes in the fair value of a hedge
that is highly effective and is designated and documented and qualifies as a
cash flow hedge, to the extent that the hedge is effective, are recorded in
"Accumulated other comprehensive income (loss), net of income tax." When the
hedged transactions are recorded upon the actual sale of the natural gas, these
gains or losses are reclassified from "Accumulated other comprehensive income
(loss), net of income tax" and recorded in "Price-risk management and other,
net" on the accompanying statement of income. The fair value of our derivatives
is computed using the Black-Scholes-Merton option pricing model and is
periodically verified against quotes from brokers. The fair value of these
instruments at December 31, 2006, was $0.7 million and is recognized on the
accompanying balance sheet in "Other current assets."
Supervision Fees. Consistent with industry practice, we charge a
supervision fee to the wells we operate including our wells in which we own up
to a 100% working interest. Supervision fees are recorded as a reduction to
general and administrative, net based on our estimate of the costs incurred to
operate the wells, with the remainder applied as a reduction to lease operating
cost. The total amount of supervision fees charged to the wells we operate was
$8.8 million in 2006, $7.8 million in 2005, and $5.8 million in 2004.
Inventories. We value inventories at the lower of cost or market value.
Cost of crude oil inventory is determined using the weighted average method and
all other inventory is accounted for using the first in, first out method
("FIFO"). The major categories of inventories, which are included in "Other
current assets" on the accompanying balance sheets, are shown as follows:
Balance at Balance at
December 31, 2006 December 31, 2005
(in thousands) (in thousands)
------------------ ------------------
Materials, Supplies and
Tubulars................ $ 10,611 $ 8,494
Crude Oil ................ 474 916
------------------ ------------------
Total .................... $ 11,085 $ 9,410
================== ==================
Income Taxes. Under SFAS No. 109, "Accounting for Income Taxes," deferred
taxes are determined based on the estimated future tax effects of differences
between the financial statement and tax basis of assets and liabilities, given
the provisions of the enacted tax laws.
Accounts Payable and Accrued Liabilities. Included in "Accounts payable and
accrued liabilities," on the accompanying balance sheets, at December 31, 2006
and 2005 are liabilities of approximately $13.9 million and $9.9 million,
respectively, which represent the amounts by which checks issued, but not
presented to the Company's banks for collection, exceeded balances in the
applicable bank accounts.
Cash and Cash Equivalents. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in
the form of uncollateralized oil and gas sales and joint interest owners
receivables, to various companies in the oil and gas industry, which results in
a concentration of credit risk. The concentration of credit risk may be affected
60
by changes in economic or other conditions within our industry and may
accordingly impact our overall credit risk. However, we believe that the risk of
these unsecured receivables is mitigated by the size, reputation, and nature of
the companies to which we extend credit. During 2006 and 2005, oil and gas sales
to Shell Oil Company and affiliates were $180.4 million and $179.9 million, or
30% and 42% of total oil and gas sales, respectively. During 2006, Chevron
Corporation and its affiliates accounted for $193.9 million or 32% of our total
oil and gas sales. During 2004, oil and gas sales to Shell Oil Company and
affiliates, both domestically and in New Zealand, were $149.2 million, or 48% of
total oil and gas sales. Credit losses in 2005, 2004 and 2003 have been
immaterial.
Environmental Costs. Our operations include activities that are subject to
extensive federal and state environmental regulations. Costs associated with
redemption projects, which are probable and reasonably estimable, are accrued in
advance. Ongoing environmental compliance costs are expensed as incurred.
Restricted Assets. These balances primarily include amounts deposited on
plugging bonds in New Zealand, along with amounts held in escrow accounts to
satisfy domestic plugging and abandonment obligations. These amounts are
restricted as to their current use, and will be released when we have satisfied
all plugging and abandonment obligations in certain fields domestically and in
New Zealand.
Foreign Currency. We use the U.S. Dollar as our functional currency in New
Zealand. The functional currency is determined by examining the entities cash
flows, commodity pricing environment and financing arrangements. We have both
assets and liabilities denominated in New Zealand Dollars, the New Zealand
"Deferred income taxes" and a portion of our "Asset Retirement Obligation" on
the accompanying balance sheet. For accounts other than "Deferred income taxes,"
as the currency rate changes between the U.S. Dollar and the New Zealand Dollar,
we recognize transaction gains and losses in "Price-risk management and other,
net" on the accompanying statements of income. We recognize transaction gains
and losses on "Deferred income taxes" in "Provision for Income Taxes" on the
accompanying statement of income.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and senior notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid or short-term nature of these instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2006 and
2005, and were determined based upon variable interest rates currently available
to us for borrowings with similar terms. Based upon quoted market prices as of
December 31, 2006 and 2005, the fair values of our senior subordinated notes due
2012 were $211.0 million, or 105.5% of face value, and $214.5 million, or
107.25% of face value, respectively. Based upon quoted market prices as of
December 31, 2006 and 2005, the fair values of our senior notes due 2011 were
$152.6 million, or 101.75% of face value, and $153.8 million, or 102.5% of face
value. The carrying value of our senior subordinated notes due 2012 was $200.0
million at December 31 for both 2006 and 2005. The carrying value of our senior
notes due 2011 was $150.0 million at December 31 for both 2006 and 2005.
Reclassification of Prior Period Balances. Certain reclassifications have
been made to prior period amounts to conform to the current year presentation.
Accumulated Other Comprehensive Income (Loss), Net of Income Tax. We follow
the provisions of SFAS No. 130, "Reporting Comprehensive Income," which
establishes standards for reporting comprehensive income. In addition to net
income, comprehensive income or loss includes all changes to equity during a
period, except those resulting from investments and distributions to the owners
of the Company. At December 31, 2006, we recorded $0.3 million, net of taxes of
less than $0.2 million, of derivative gains in "Accumulated other comprehensive
income (loss), net of income tax" on the accompanying balance sheet. The
components of accumulated other comprehensive Income (loss) and related tax
effects for 2006 were as follows:
Gross Value Tax Effect Net of Tax Value
---------------- ----------------- -------------------
Other comprehensive loss at December 31, 2005 $ (110,094) $ 40,625 $ (69,469)
Change in fair value of cash flow hedges 4,672,043 (1,733,328) 2,938,715
Effect of cash flow hedges settled
during the period (4,059,052) 1,506,128 (2,552,924)
---------------- ----------------- -------------------
Other comprehensive income at December 31, 2006 $ 502,897 $ (186,575) $ 316,322
================ ================= ===================
Total comprehensive income was $162.0 million, $115.3 million, and $69.2
million for 2006, 2005, and 2004, respectively.
61
Stock Based Compensation. Effective January 1, 2006, the Company adopted
Statement of Financial Accounting Standards (SFAS) No. 123 (R), "Share-Based
Payment" (SFAS No. 123R) utilizing the modified prospective approach. Under the
modified prospective approach, SFAS No. 123R applies to new awards and to awards
that were outstanding on January 1, 2006 as well as those that are subsequently
modified, repurchased or cancelled. Under the modified prospective approach,
compensation cost recognized for the year ended December 31, 2006 includes
compensation cost for all share-based awards granted prior to, but not yet
vested as of January 1, 2006, based on the grant-date fair value estimated in
accordance with the original provisions of SFAS No. 123, and compensation cost
for all share-based awards granted subsequent to January 1, 2006, based on the
grant-date fair value estimated in accordance with the provisions of SFAS No.
123R. Prior periods were not restated to reflect the impact of adopting the new
standard.
We have three stock-based compensation plans, which are described more
fully in Note 6.
Prior to 2006, we accounted for those plans under the recognition and
measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations. No stock-based employee compensation
cost is reflected in net income for employee stock options prior to 2006, as all
options granted under those plans had an exercise price equal to the fair market
value of the underlying common stock on the date of the grant; or in the case of
the employee stock purchase plan, the purchase price is 85% of the lower of the
closing price of our common stock as quoted on the New York Stock Exchange at
the beginning or end of the plan year or a date during the year chosen by the
participant. Had compensation expense for these plans been determined based on
the fair value of the options consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," our net income and earnings per share would have been
adjusted to the following pro forma amounts:
2005 2004
---------------- --------------
Net Income: As Reported $115,778,456 $68,450,917
Stock-based employee
compensation expense determined
under fair value method for all
awards, net of tax (2,712,441) (3,557,541)
---------------- --------------
Pro Forma $113,066,015 $64,893,376
Basic EPS: As Reported $4.06 $2.46
Pro Forma $3.97 $2.33
Diluted EPS: As Reported $3.95 $2.41
Pro Forma $3.86 $2.29
Pro forma compensation cost reflected above may not be representative of
the cost to be expected in future years. The fair value of each option grant, as
opposed to its exercise price, is estimated on the date of grant using the
Black-Scholes-Merton option-pricing model with the following weighted average
assumptions in 2006, 2005, and 2004, respectively: no dividend yield; expected
volatility factors of 39.3%, 41.6%, and 38.6%; risk-free interest rates of 4.8%,
3.8%, and 3.6%; and expected lives of 4.8, 3.9, and 5.4 years. We view all
awards of stock compensation as a single award with an expected life equal to
the average expected life of component awards and amortize the award on a
straight-line basis over the life of the award.
Asset Retirement Obligation. In June 2001, the Financial Accounting
Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the carrying amount of the related long-lived
asset is increased. The liability is discounted from the year the well is
expected to deplete. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depreciated on a unit-of-production basis
over the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss which increases or decreases the full cost pool. This standard requires us
to record a liability for the fair value of our dismantlement and abandonment
costs, excluding salvage values. Based on our experience and analysis of the oil
and gas services industry, we have not factored a market risk premium into our
asset retirement obligation. SFAS No. 143 was adopted by us effective January 1,
2003.
62
The following provides a roll-forward of our asset retirement obligation:
Asset Retirement Obligation recorded as of January 1, 2004 $ 10,137,473
Accretion expense for 2004 673,654
Liabilities incurred for new wells and facilities construction 712,521
Liabilities incurred for acquisitions 2,941,490
Reductions due to sold and abandoned wells (1,083,174)
Revisions in estimated cash flows 4,195,474
Increase due to currency exchange rate fluctuations 61,698
----------------
Asset Retirement Obligation as of December 31, 2004 $ 17,639,136
Accretion expense for 2005 761,041
Liabilities incurred for new wells and facilities construction 616,206
Liabilities incurred for acquisitions 426,377
Reductions due to sold and abandoned wells (464,519)
Revisions in estimated cash flows 416,861
Decrease due to currency exchange rate fluctuations (38,735)
----------------
Asset Retirement Obligation as of December 31, 2005 $ 19,356,367
----------------
Accretion expense for 2006 1,034,322
Liabilities incurred for new wells and facilities construction 684,175
Liabilities incurred for acquisitions 12,207,480
Reductions due to sold and abandoned wells (334,591)
Revisions in estimated cash flows 1,467,673
Increase due to currency exchange rate fluctuations 45,027
----------------
Asset Retirement Obligation as of December 31, 2006 $ 34,460,453
----------------
At December 31, 2006 and 2005, approximately $0.8 million and $0.3 million,
respectively, of our asset retirement obligation is classified as a current
liability in "Accounts payable and accrued liabilities" on the accompanying
consolidated balance sheets.
New Accounting Pronouncements. Effective January 1, 2006, the Company
adopted Statement of Financial Accounting Standards (SFAS) No. 123 (R),
"Share-Based Payment" (SFAS No. 123R) utilizing the modified prospective
approach. Prior to the adoption of SFAS No. 123R, we accounted for stock option
grants in accordance with Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees" (the intrinsic value method), and
accordingly, recognized no compensation expense for employee stock option
grants. Under the modified prospective approach, SFAS No. 123R applies to new
awards and to awards that were outstanding on January 1, 2006 as well as those
that are subsequently modified, repurchased or cancelled. Under the modified
prospective approach, compensation cost recognized for the year ended December
31, 2006 includes compensation cost for all share-based awards granted prior to,
but not yet vested as of January 1, 2006, based on the grant-date fair value
estimated in accordance with the original provisions of SFAS No. 123, and
compensation cost for all share-based awards granted subsequent to January 1,
2006, based on the grant-date fair value estimated in accordance with the
provisions of SFAS No. 123R. Prior periods were not restated to reflect the
impact of adopting the new standard. As a result of adopting SFAS No. 123R on
January 1, 2006, our income before taxes, net income and basic and diluted
earnings per share for the year ended December 31, 2006, were $3.4 million, $2.8
million, $0.09, and $0.09 lower, respectively. Upon adoption of SFAS 123R, we
recorded an immaterial cumulative effect of a change in accounting principle as
a result of our change in policy from recognizing forfeitures as they occur to
one recognizing expense based on our expectation of the amount of awards that
will vest over the requisite service period for our restricted stock awards.
This amount was recorded in "General and Administrative, net" in the
accompanying consolidated statements of income.
In September 2006, the SEC released SAB 108, "Considering the Effects of
Prior Year Misstatements when Quantifying Misstatements in Current Year
Financial Statements" ( SAB 108). SAB 108 addresses the process of quantifying
financial statement misstatements, such as assessing both the carryover and
reversing effects of prior year misstatements on the current year financial
statements. SAB 108 became effective for our fiscal year ended December 31,
2006. The adoption of this statement had no impact on our financial position or
results of operations.
In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting
for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109."
This Interpretation provides guidance for recognizing and measuring uncertain
tax positions, as defined in SFAS No. 109, "Accounting for Income Taxes." FIN
No. 48 prescribes a threshold condition that a tax position must meet for any of
63
the benefit of the uncertain tax position to be recognized in the financial
statements. Guidance is also provided regarding derecognition, classification
and disclosure of these uncertain tax positions. FIN No. 48 is effective for
fiscal years beginning after December 15, 2006. The adoption of this
Interpretation is not expected to have a material impact on its financial
position or results of operations.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements.
SFAS No. 157 addresses how companies should approach measuring fair value when
required by GAAP; it does not create or modify any current GAAP requirements to
apply fair value accounting. SFAS No. 157 provides a single definition for fair
value that is to be applied consistently for all accounting applications, and
also generally describes and prioritizes, according to reliability, the methods
and inputs used in valuations. SFAS No. 157 prescribes various disclosures about
financial statement categories and amounts which are measured at fair value, if
such disclosures are not already specified elsewhere in GAAP. The new
measurement and disclosure requirements of SFAS No. 157 are effective for us in
the first quarter 2008. The Company has not yet determined what impact, if any,
this statement will have on its financial position or results of operations.
2. Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted earnings per share ("Diluted EPS") for all periods also
assumes, as of the beginning of the period, exercise of stock options and
restricted stock grants using the treasury stock method. Certain of our stock
options and restricted stock that would potentially dilute Basic EPS in the
future were also antidilutive for the 2006, 2005, and 2004 periods and are
discussed below.
64
The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
2006, 2005, and 2004:
2006 2005 2004
---- ---- ----
Net Per Share Net Per Share Net Per Share
Income Shares Amount Income Shares Amount Income Shares Amount
------------ ---------- --------- ------------ ---------- --------- ------------ ---------- ---------
Basic EPS:
Net Income and
Share Amounts $161,565,340 29,265,366 $5.52 $115,778,456 8,496,275 $4.06 $ 68,450,917 27,822,413 $2.46
Dilutive
Securities:
Restricted Stock -- 168,759 -- 61,516 -- --
Stock Options -- 581,891 -- 736,937 -- 524,860
------------ ----------- ------------ ---------- ------------ ----------
Diluted EPS:
Net Income and
Assumed Share
Conversions $161,565,340 30,016,016 $5.38 $115,778,456 29,294,728 $3.95 $ 68,450,917 28,347,273 $2.41
============ =========== ============ ========== ============ ==========
Options to purchase approximately 1.5 million shares at an average exercise
price of $24.59 were outstanding at December 31, 2006, while options to purchase
2.1 million shares at an average exercise price of $21.28 were outstanding at
December 31, 2005, and options to purchase 3.0 million shares at an average
exercise price of $18.51 were outstanding at December 31, 2004. Approximately
1.0 million, 0.1 million, and 1.1 million options to purchase shares were not
included in the computation of Diluted EPS for the years ended December 31,
2006, 2005, and 2004, respectively, because these options were antidilutive, in
that the sum of the option price, unrecognized compensation expense and excess
tax benefits recognized as proceeds in the treasury stock method was greater
than the average closing market price for the common shares during those
periods. Employee restricted stock grants of 334,425 shares, 6,990 shares and
70,900 shares, were not included in the computation of Diluted EPS for the year
ended December 31, 2006, 2005, and 2004, respectively, because these restricted
stock grants were antidilutive in that the sum of the unrecognized compensation
expense and excess tax benefits recognized as proceeds under the treasury stock
method was greater than the average closing market price for the common shares
during that period. Other restricted stock grants of 15,000 shares, which were
issued in 2004, were not included in the computation of Diluted EPS for the year
ended December 31, 2005, as performance conditions surrounding the vesting of
these shares had not occurred.
65
3. Provision for Income Taxes
Year Ended December 31,
(in thousands)
---------------------------------------------------
2006 2005 2004
--------------- -------------- --------------
United States $ 247,645 $ 155,863 $ 86,001
Foreign 14,641 22,577 15,439
--------------- -------------- --------------
Total $ 262,286 $ 178,440 $ 101,440
=============== ============== ==============
The following is an analysis of the consolidated income tax provision:
Year Ended December 31,
(in thousands)
---------------------------------------------------
2006 2005 2004
--------------- -------------- --------------
Current - Domestic $ 2,860 $ 644 $ 469
--------------- -------------- --------------
Deferred - Domestic 94,375 57,605 31,138
- Foreign 3,486 4,412 1,382
--------------- -------------- --------------
Total Deferred 97,861 62,017 32,520
--------------- -------------- --------------
Total $ 100,721 $ 62,661 $ 32,989
=============== ============== ==============
Reconciliations of income taxes computed using the U.S. Federal statutory
rate to the effective income tax rates are as follows:
(in thousands) 2006 2005 2004
--------------- -------------- --------------
Income taxes computed at U.S.
statutory rate (35%) $ 91,800 $ 62,454 $ 35,504
State tax provisions, net of federal benefits 3,921 2,145 1,140
Effect of foreign operations (293) (452) (309)
Currency exchange impact on foreign tax calculation (1,346) (2,769) (2,516)
Cumulative impact of adjustments to net state income
tax rate 1,547 1,008 859
Valuation allowance 3,200 --- ---
Other, net 1,892 275 (1,689)
--------------- --------------- --------------
Provision for income taxes $ 100,721 $ 62,661 $ 32,989
=============== ============== ==============
Effective rate 38.4% 35.1% 32.5%
The primary upward adjustment in the effective tax rate above the U.S.
statutory rate is the provision for state income taxes (computed net of the
offsetting federal benefit), which were $3.9, million, $2.1 million and $1.1
million for 2006, 2005, and 2004, respectively. In 2006 the Company recorded a
valuation allowance of $3.2 million discussed further below. Additionally, the
Company recorded adjustments to the cumulative state deferred tax liability in
the amounts of $1.5 million, $1.0 million, and $0.9 million for 2006, 2005, and
2004, respectively.
Favorable adjustments are primarily attributable to currency exchange
impact on foreign operations. The Company's New Zealand subsidiaries use the
U.S. Dollar as their functional currency for financial reporting purposes, but
66
income taxes are calculated from New Zealand Dollar financial statements and
re-measured into U.S. Dollars. Volatility in exchange rates creates variable
results when computing income in different currencies In aggregate, the Company
recognized foreign exchange benefits to tax expense in the amounts of $1.3
million, $2.8 million, and $2.5 million for 2006, 2005, and 2004, respectively.
The New Zealand statutory rate is 33%, which resulted in differences of
$0.3 million, $0.5 million, and $0.3 million for 2006, 2005, and 2004
respectively vs. the U.S. statutory rate. The Company does not compute a
provision for U.S. taxes on the undistributed earnings of our New Zealand
subsidiaries as management has plans to reinvest such earnings outside of the
United States indefinitely. As of December 31, 2006, the undistributed earnings
of foreign subsidiaries are approximately $58.5 million. If, in the future,
these earnings are distributed into the U.S. in the form of dividends or
otherwise, we may be subject to U.S. income taxes and New Zealand withholding
taxes. It is not practical, however, to estimate the amount of taxes that may be
payable if such remittances occur. Presently, there are no foreign tax credits
available to reduce the U.S. taxes on such amounts if repatriated.
The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 2006 and 2005 were as follows (in thousands):
2006 2005
---- ----
Current deferred tax assets:
Carryover items net of valuation allowance (Domestic) $ 2,383 $ 0
--------- ---------
Non-Current deferred tax assets:
Alternative minimum tax credits (Domestic) $ (2,202) $ (3,201)
Carryover items (Domestic) (2,648) (38,119)
Acquired deferred tax asset (Foreign) (1,204) (2,408)
Carryover Items (Foreign) (55,197) (46,089)
Unrealized stock compensation (2,680) (575)
Other (Domestic) (325) (309)
--------- ---------
Total deferred tax assets $ (64,256) $ (90,701)
--------- ---------
Non-Current deferred tax liabilities:
Domestic oil and gas exploration and development costs $ 224,580 $ 167,088
Foreign oil and gas exploration and development costs 63,254 51,863
Other (Domestic) 1,389 1,057
--------- ---------
Total deferred tax liabilities $ 289,223 $ 220,008
--------- ---------
Net Non-Current deferred tax liabilities $ 224,967 $ 129,307
========= =========
The total change in the net non-current deferred liability from 2005 to
2006 was $95.7 million. Increases in the liability were attributable to deferred
tax expense of $97.9 million, reclassification of a carryover item to current
assets of $2.4 million and $0.2 million for other adjustments. Reductions were
made to the net liability for the tax benefit of stock compensation deductions
of $4.8 million, which are recorded as additions to paid-in-capital.
The primary non-current deferred tax asset is $55.2 million for foreign
carryover items. This is attributable to cumulative New Zealand net operating
losses of $167.3 million. New Zealand tax net operating losses do not expire.
Other non-current deferred tax assets include $2.7 million for unrealized
stock compensation, $2.6 million for State of Louisiana net operating loss
carryovers, $2.2 million for U.S. Federal alternative minimum tax credits, and
$1.5 million for other items. The unrealized stock compensation is attributable
to stock compensation expenses accrued for employee stock options and restricted
stock that is not realized for income tax purposes until exercise (for stock
options) or vesting (for restricted stock). The actual tax deduction realized
may be significantly different than the accrued amounts depending on the market
value of the stock on the date of exercise or vesting. The Louisiana net
operating loss carryforwards are scheduled to expire between 2013 and 2019. The
alternative minimum tax credits carryforward indefinitely. These credits are
available to reduce future regular tax liability to the extent they exceed the
alternative minimum tax otherwise due.
The Company has not recorded any valuation allowance against any of the
non-current deferred tax assets as management estimates that it is more likely
than not that these assets will be fully utilized in future periods before any
applicable expiration dates. Significant changes in estimates caused by changes
in oil and gas prices, production levels, capital expenditures, and other
variables could impact the Company's ability to utilize the carryover amounts.
67
The current deferred tax asset of $2.4 million is for capital loss
carryforward assets of $6.1 million, offset by a valuation allowance of $3.7
million (an increase of $3.2 million in 2006). The increase in the valuation
allowance is due to changes in the Company's property disposition plans.
Management expects to realize the net tax asset from a property disposition
planned for 2007.
4. Long-Term Debt
Our long-term debt as of December 31, 2006 and 2005, is as follows:
2006 2005
------------ -------------
Bank Borrowings $ 31,400,000 $ ---
7-5/8% senior notes due 2011 150,000,000 150,000,000
9-3/8% senior subordinated notes due 2012 200,000,000 200,000,000
------------ -------------
Long-Term Debt $ 381,400,000 $ 350,000,000
============ =============
Bank Borrowings. At December 31, 2006, we had borrowings of $31.4 million
under our $500.0 million credit facility with a syndicate of ten banks that has
a borrowing base of $250.0 million and expires in October 2011. At December 31,
2005, we had no borrowings under our credit facility. The interest rate is
either (a) the lead bank's prime rate (8.25% at December 31, 2006) or (b) the
adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt. The applicable margin is based on
the ratio of the outstanding balance to the last calculated borrowing base. In
October 2006, we increased, renewed and extended this credit facility,
increasing the facility to $500 million from $400 million, increasing the
commitment amount under the borrowing base to $250 million from $150 million,
and extending its expiration to October 3, 2011 from October 1, 2008. The other
terms of the credit facility stayed largely the same. The covenants related to
this credit facility changed somewhat with the extension of the facility and are
discussed below. We incurred $0.6 million of debt issuance costs related to the
extension of this facility in 2006 and $0.4 million of debt issuance costs
related to the renewal of this facility in 2004, which is included in "Debt
issuance costs" on the accompanying consolidated balance sheets and will be
amortized to interest expense over the life of the facility.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $15.0 million in any
fiscal year), a remaining aggregate limitation on purchases of our stock of
$50.0 million, requirements as to maintenance of certain minimum financial
ratios (principally pertaining to adjusted working capital ratios and EBITDAX),
and limitations on incurring other debt or repurchasing our 7-5/8% senior notes
due 2011 or 9-3/8% senior subordinated notes due 2012. Since inception, no cash
dividends have been declared on our common stock. We are currently in compliance
with the provisions of this agreement. The credit facility is secured by our
domestic oil and natural gas properties. We have also pledged 65% of the stock
in our two New Zealand subsidiaries as collateral for this credit facility. The
borrowing base is re-determined at least every six months and was reconfirmed by
our bank group at $250.0 million effective November 1, 2006, and the commitment
amount was increased to $250.0 million effective October 2, 2006. The next
scheduled borrowing base review is in May 2007.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $1.5 million in 2006, $1.0 million
in 2005, and $1.5 million in 2004. The amount of commitment fees included in
interest expense, net was $0.6 million in 2006, and $0.5 million in both 2005
and 2004.
68
Senior Subordinated Notes Due 2009. These notes consisted of $125.0 million
of 10-1/4% senior subordinated notes, which were issued at 99.236% of the
principal amount on August 4, 1999, and were scheduled to mature on August 1,
2009. These notes were unsecured senior subordinated obligations with interest
payable semiannually, on February 1 and August 1. In June 2004, we repurchased
$32.1 million of these notes pursuant to a tender offer. In July 2004, we
repurchased an additional $0.5 million of these notes, and as of August 1, 2004,
we redeemed the remaining $92.5 million in outstanding notes. In 2004, we
recorded a charge of $9.5 million related to the repurchase of these notes,
which is recorded in "Debt retirement costs" on the accompanying consolidated
statement of income. The costs were comprised of approximately $6.5 million of
premiums paid to repurchase the notes, $2.2 million to write-off unamortized
debt issuance costs, $0.6 million to write-off unamortized debt discount, and
approximately $0.2 million of other costs.
Interest expense on the 10-1/4% senior subordinated notes due 2009,
including amortization of debt issuance costs and discount, totaled $7.4 million
in 2004.
Senior Notes Due 2011. These notes consist of $150.0 million of 7-5/8%
senior notes, which were issued on June 23, 2004 at 100% of the principal amount
and will mature on July 15, 2011. The notes are senior unsecured obligations
that rank equally with all of our existing and future senior unsecured
indebtedness, are effectively subordinated to all our existing and future
secured indebtedness to the extent of the value of the collateral securing such
indebtedness, including borrowing under our bank credit facility, and rank
senior to all of our existing and future subordinated indebtedness. Interest on
these notes is payable semi-annually on January 15 and July 15, and commenced on
January 15, 2005. On or after July 15, 2008, we may redeem some or all of the
notes, with certain restrictions, at a redemption price, plus accrued and unpaid
interest, of 103.813% of principal, declining to 100% in 2010 and thereafter. In
addition, prior to July 15, 2007, we may redeem up to 35% of the notes with the
net proceeds of qualified offerings of our equity at a redemption price of
107.625% of the principal amount of the notes, plus accrued and unpaid interest.
We incurred approximately $3.9 million of debt issuance costs related to these
notes, which is included in "Debt issuance costs" on the accompanying
consolidated balance sheets and will be amortized to interest expense, net over
the life of the notes using the effective interest method. Upon certain changes
in control of Swift Energy, each holder of notes will have the right to require
us to repurchase all or any part of the notes at a purchase price in cash equal
to 101% of the principal amount, plus accrued and unpaid interest to the date of
purchase. The terms of these notes include, among other restrictions, a
limitation on how much of our own common stock we may repurchase. We are
currently in compliance with the provisions of the indenture governing these
senior notes.
Interest expense on the 7-5/8% senior notes due 2011, including
amortization of debt issuance costs totaled $11.9 million in both 2006 and 2005,
and $6.2 million in 2004.
Senior Subordinated Notes Due 2012. These notes consist of $200.0 million
of 9-3/8% senior subordinated notes, which were issued on April 11, 2002 and
will mature on May 1, 2012. The notes are unsecured senior subordinated
obligations and are subordinated in right of payment to all our existing and
future senior debt, including our bank credit facility. Interest on these notes
is payable semiannually on May 1 and November 1, with the first interest payment
on November 1, 2002. On or after May 1, 2007, we may redeem these notes, with
certain restrictions, at a redemption price, plus accrued and unpaid interest,
of 104.688% of principal, declining to 100% in 2010. Upon certain changes in
control of Swift Energy, each holder of these notes will have the right to
require us to repurchase the notes at a purchase price in cash equal to 101% of
the principal amount, plus accrued and unpaid interest to the date of purchase.
The terms of these notes include, among other restrictions, a limitation on how
much of our own common stock we may repurchase. We are currently in compliance
with the provisions of the indenture governing these subordinated notes due
2012.
Interest expense on the 9-3/8% senior subordinated notes due 2012,
including amortization of debt issuance costs totaled $19.2 million for each of
the years 2006, 2005, and 2004.
The maturities on our long-term debt are $0 for 2007, 2008, 2009 and 2010,
$181.4 million for 2011, and $200 million thereafter.
We have capitalized interest on our unproved properties in the amount of
$9.2 million, $7.2 million, and $6.5 million, in 2006, 2005, and 2004,
respectively.
69
5. Commitments and Contingencies
Total rental and lease expenses which were included in "General and
administrative, net" on our accompanying consolidated statements of income were
$3.2 million in 2006, $3.0 million in 2005, and $2.4 million in 2004. Rental and
lease expenses which were included in "Lease operating cost" on our accompanying
consolidated statements of income were $3.6 million in 2006, $1.9 million in
2005, and $2.2 million in 2004. Our remaining minimum annual obligations under
non-cancelable operating lease commitments are $5.3 million for both 2007 and
2008, $3.3 million for both 2009 and 2010, $3.2 million for 2011, and $10.1
million thereafter or $30.6 million in the aggregate. The rental and lease
expenses and remaining minimum annual obligations under non-cancelable operating
lease commitments primarily relate to the lease of our office space in Houston,
Texas which is a ten year lease and expires in 2015.
In the ordinary course of business, we have entered into agreements with
drilling contractors for such services and tubing and pipe inventory
commitments. The remaining commitments at December 31, 2006 for these services
and materials totaled $28.9 million for 2007.
Through December 2006, we were the managing general partner of two private
limited partnerships. Because we served as the general partner of these
entities, under state partnership law we were contingently liable for the
liabilities of these partnerships. These liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets. As of
December 31, 2006, these partnerships were dissolved.
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and
natural gas wells. In management's opinion, the outcome of any such currently
pending legal actions will not have a material adverse effect on our financial
position or results of operations.
6. Stockholders' Equity
Stock-Based Compensation Plans. We have three stock option plans that
awards are currently granted under, the 2005 Stock Compensation Plan, which was
adopted by our Board of Directors in March 2005 and was approved by shareholders
at the 2005 annual meeting of shareholders, the 2001 Omnibus Stock Compensation
Plan, which was adopted by our Board of Directors in February 2001 and was
approved by shareholders at the 2001 annual meeting of shareholders, and the
1990 Non-Qualified Stock Option Plan solely for our independent directors. No
further grants, other than stock option reload grants, will be made under the
2001 Omnibus Stock Compensation Plan or the 1990 Non-Qualified Stock Option
Plan, both of which were replaced by the 2005 Stock Compensation Plan, although
options remain outstanding under both plans and are accordingly included in the
tables below. In addition, we have an employee stock purchase plan and an
employee stock ownership plan.
Under the 2005 plan, incentive stock options and other options and awards
may be granted to employees, directors, and consultants to purchase shares of
common stock. Under the 2001 plan, incentive stock options and other options and
awards may be granted to employees to purchase shares of common stock. Under the
1990 non-qualified plan, non-employee members of our Board of Directors were
automatically granted options to purchase shares of common stock on a formula
basis. All three plans provide that the exercise prices equal 100% of the fair
value of the common stock on the date of grant. Restricted stock grants become
vested in various terms ranging from three years to five years, stock options
become exercisable in various terms ranging from one year to five years. Options
granted typically expire ten years after the date of grant or earlier in the
event of the optionee's separation from employment. At the time the stock
options are exercised, the cash received is credited to common stock and
additional paid-in capital. Options issued under these plans also include a
reload feature where additional options are granted at the then current market
price when mature shares of Swift Energy common stock are used to satisfy the
exercise price of an existing stock option grant. When Swift Energy common stock
is used to satisfy the exercise price, the net shares actually issued are
reflected in the accompanying Statement of Stockholders' Equity (see note 1 to
table below). We view all awards of stock compensation as a single award with an
expected life equal to the average expected life of component awards and
amortize the award on a straight-line basis over the life of the award.
The employee stock purchase plan, which began in 1993, provides eligible
employees the opportunity to acquire shares of Swift Energy common stock at a
discount through payroll deductions. Through May 31, 2006, the prior plan year
was from June 1 to the following May 31. A transition period from June 1 to
70
December 31 was used during the second half of 2006 and a new plan year, from
January 1 to December 31, began being used in 2007. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan is 85% of the lower
of the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year (or a date during the year
chosen by the participant through the plan year, for plan years ending on or
before May 31, 2006). Under this plan for the last three years, we have issued
22,425 shares at a price range of $29.84 to $32.80 in 2006, 32,495 shares at a
price range of $15.56 to $18.12 in 2005, and 50,418 shares at a price range of
$9.98 to $10.83 in 2004. In January 2007, we issued 17,678 shares at a price of
$35.00 related to the transition period ended December 31, 2006. As of December
31, 2006, 84,366 shares remained available for issuance under this plan.
As a result of adopting SFAS No. 123R on January 1, 2006, our income before
taxes, net income and basic and diluted earnings per share for the year ended
December 31, 2006, were $3.4 million, $2.8 million, $0.09, and $0.09 lower,
respectively. Upon adoption of SFAS 123R, we recorded an immaterial cumulative
effect of a change in accounting principle as a result of our change in policy
from recognizing forfeitures as they occur to one recognizing expense based on
our expectation of the amount of awards that will vest over the requisite
service period for our restricted stock awards. This amount was recorded in
"General and Administrative, net" in the accompanying consolidated statements of
income.
We receive a tax deduction for certain stock option exercises during the
period the options are exercised, generally for the excess of the price at which
the stock is sold over the exercise price of the options. In addition, we
receive an additional tax deduction when restricted stock vests at a higher
value than the value used to recognize compensation expense at the date of
grant. Prior to adoption of SFAS No. 123R, we reported all tax benefits
resulting from the award of equity instruments as operating cash flows in our
consolidated statements of cash flows. In accordance with SFAS No. 123R, we are
required to report excess tax benefits from the award of equity instruments as
financing cash flows, these benefits totaled $3.3 million for the year ended
December 31, 2006, respectively.
Net cash proceeds from the exercise of stock options were $11.8 million for
the year ended December 31, 2006. The actual income tax benefit realized from
stock option exercises was $4.8 million for the same period.
Stock compensation expense for both stock options and restricted stock
issued to both employees and non-employees is recorded in "General and
Administrative, net" in the accompanying consolidated statements of income, and
was $6.3 million, $1.5 million, and less than $0.1 million for the years ended
December 31, 2006, 2005, and 2004 respectively. We also capitalized $3.4
million, $1.0 million, and $0.1 million of stock compensation in 2006, 2005, and
2004, respectively.
Our shares available for future grant under our stock compensation plans
were 959,063 at December 31, 2006. Each stock option granted reduces the
aforementioned total by one share, while each restricted stock grant reduces the
shares available for future grant by 1.44 shares.
Stock Options. We use the Black-Scholes-Merton option pricing model to
estimate the fair value of stock option awards with the following
weighted-average assumptions for the indicated periods.
Years Ended
December 31,
-----------------------
2006 2005
-----------------------
Dividend yield 0% 0%
Expected volatility 39.3% 41.6%
Risk-free interest rate 4.8% 3.8%
Expected life of options (in years) 4.8 3.9
Weighted-average grant-date fair
value $ 18.03 $ 12.84
71
The expected term has been calculated using the Securities and Exchange
Commission Staff's shortcut approach from Staff Accounting Bulletin No. 107. We
have analyzed historical volatility and based on an analysis of all relevant
factors use a three-year period to estimate expected volatility of our stock
option grants.
At December 31, 2006, $3.6 million of unrecognized compensation cost
related to stock options is expected to be recognized over a weighted-average
period of 1.5 years.
The following table represents stock option activity for the years ended
December 31, 2006, 2005 and 2004:
2006 2005 2004
------------------------- ------------------------ -------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Exer. Shares Shares Exer. Price Shares Exer. Price
----------- ------------ ----------- ----------- ------------ ----------
Options outstanding, beginning of period 2,118,179 $ 21.28 2,998,668 $ 18.51 3,238,611 $ 16.37
Options granted 234,110 $ 45.73 176,262 $ 35.17 415,744 $ 23.36
Options canceled (51,739) $ 22.25 (45,142) $ 18.94 (64,866) $ 21.85
Options exercised(1) (751,410) $ 22.02 (1,011,609) $ 9.78 (590,821) $ 9.83
----------- ----------- ------------
Options outstanding, end of period 1,549,140 $ 24.59 2,118,179 $ 21.28 2,998,668 $ 18.51
=========== =========== ============
Options exercisable, end of period 884,876 $ 22.60 1,085,509 $ 20.98 1,542,571 $ 17.78
=========== =========== ============
The aggregate intrinsic value and weighted average remaining contract life
of options outstanding and exercisable at December 31, 2006 was $31.9 million
and 5.5 years and $19.8 million and 4.5 years, respectively. The total intrinsic
value of options exercised during the year ended December 31, 2006 was $18.4
million.
The following table summarizes information about stock options outstanding
at December 31, 2006:
Options Outstanding Options Exercisable
--------------------------------------- -------------------------
Wtd. Avg.
Range of Number Remaining Wtd. Avg. Number Wtd. Avg.
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices at 12/31/06 Life Price At 12/31/06 Price
------------------- -------------- ----------- ----------- ------------- -----------
$8.00 to $21.99 747,779 5.4 $ 13.56 452,555 $ 13.40
$22.00 to $37.99 513,566 5.3 $ 28.73 374,736 $ 30.09
$38.00 to $51.84 287,795 6.2 $ 45.84 57,585 $ 46.21
-------------- -------------
$8.00 to $51.84 1,549,140 5.5 $ 24.59 884,876 $ 22.60
============== =============
1 The plans allow for the use of a "stock swap" in lieu of a cash exercise
for options, under certain circumstances. The delivery of Swift Energy common
stock, held by the optionee for a minimum of six months, which are considered
mature shares, with a fair market value equal to the required purchase price of
the shares to which the exercise relates, constitutes a valid "stock swap."
Options issued under a "stock swap" also include a reload feature where
additional options are granted at the then current market price when mature
shares of Swift stock are used to satisfy the exercise price of an existing
stock option grant. The terms of the plans provide that the mature shares
delivered, as full or partial payment in a "stock swap", shall again be
available for awards under the plans. In 2006, 2005 and 2004 respectively,
98,581, 170,762 and 81,716 mature shares were delivered in "stock swap"
transactions, which resulted in the issuance of an equal number of reload option
grants.
Restricted Stock. In 2006, 2005 and 2004, the Company issued 324,640,
158,500 and 70,900 shares, respectively, of restricted stock to employees and
directors. These shares vest over a three-year to five-year period and remain
subject to forfeiture if vesting conditions are not met. The fair value of these
shares when issued in 2006, 2005 and 2004 was approximately $43, $38 and $25 per
share.
The compensation expense for these awards was determined based on the
market price of our stock at the date of grant applied to the total number of
shares that were anticipated to fully vest. As of December 31, 2006, we have
unrecognized compensation expense of approximately $13.9 million associated with
72
these awards which are expected to be recognized over a weighted-average period
of 2.2 years. The total fair value of shares vested during the year ended
December 31, 2006 was $1.6 million.
The following is a summary of our restricted stock issued to employees and
directors under these plans as of December 31, 2006, 2005, and 2004:
2006 2005 2004
------------------------- ------------------------- ----------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Grant Price Shares Grant Price Shares Grant Price
------------ ------------ ----------- ------------ ----------- --------------
Restricted shares outstanding, beginning
of period 236,950 $ 34.79 100,900 $ 23.92 --- $ ---
Restricted shares granted 324,640 $ 43.21 158,500 $ 38.31 100,900 $ 23.92
Restricted shares canceled (22,630) $ 38.01 (7,450) $ 39.03 --- $ ---
Restricted shares vested (35,776) $ 24.57 (15,000) $ --- --- $ ---
----------- ----------- -----------
Restricted shares outstanding, end of
period 503,184 $ 40.04 236,950 $ 34.79 100,900 $ 23.92
=========== =========== ===========
Employee Stock Ownership Plan. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting. The ESOP is designed to enable our employees to accumulate stock
ownership. While there will be no employee contributions, participants will
receive an allocation of stock that has been contributed by Swift Energy.
Compensation expense is recognized upon vesting when such shares are released to
employees. The plan may also acquire Swift Energy common stock, purchased at
fair market value. The ESOP can borrow money from Swift Energy to buy Swift
Energy common stock. ESOP payouts will be paid in a lump sum or installments,
and the participants generally have the choice of receiving cash or stock. At
December 31, 2006, 2005, and 2004, all of the ESOP compensation was earned. Our
contribution to the ESOP plan totaled $0.4 million for the year ended December
31, 2006, and $0.2 million for the years ended December 31, 2005 and 2004, and
were made all in common stock, and are recorded as "General and administrative,
net" on the accompanying consolidated statements of income. The shares of common
stock contributed to the ESOP plan totaled 8,927, 4,438, and 6,911 shares for
the 2006, 2005, and 2004 contributions, respectively.
Employee Savings Plan. We have a savings plan under Section 401(k) of the
Internal Revenue Code. Eligible employees may make voluntary contributions into
the 401(k) savings plan with Swift contributing on behalf of the eligible
employee an amount equal to 100% of the first 2% of compensation and 75% of the
next 4% of compensation based on the contributions made by the eligible
employees. Our contributions to the 401(k) savings plan were $1.0 million for
2006, $0.8 million for 2005, and $0.7 million for 2004, and are recorded as
"General and administrative, net" on the accompanying consolidated statements of
income. The contributions in 2006, 2005, and 2004 were made all in common stock.
The shares of common stock contributed to the 401(k) savings plan totaled
23,890, 17,920, and 24,513 shares for the 2006, 2005, and 2004 contributions,
respectively.
Treasury Shares. In March 1997, our Board of Directors approved a common
stock repurchase program that terminated as of June 30, 1999. Under this
program, we spent approximately $13.3 million to acquire 927,774 shares in the
open market at an average cost of $14.34 per share. At December 31, 2006,
427,086 shares remain in treasury (net of 500,688 shares used to fund the ESOP,
401(k) contributions and acquisitions) with a total cost of $6.1 million and are
included in "Treasury stock held, at cost" on the accompanying consolidated
balance sheet.
Shareholder Rights Plan. Our Rights Agreement was initially adopted by the
Board of Directors in 1997 for a ten year term. The Board of Directors renewed
and extended the Rights Agreement for an additional ten year term from December
21, 2006. Pursuant to the Rights Agreement as amended, for each share of Swift
Energy common stock a holder has the right to purchase one one-thousandth of a
share of Swift Energy preferred stock for $250 upon the occurance of certain
events triggered when a person or entity purchases 15% or more beneficial
ownership of Swift Energy's outstanding common stock. The rights are not
exercisable by such 15% or more beneficial owner.
73
7. Related-Party Transactions
We were the operator of a number of properties owned by private limited
partnerships and, accordingly, charge these entities operating fees. The
operating supervision fees charged to the partnerships totaled approximately
$0.2 million in 2006, 2005, and 2004, and are recorded as reductions of "General
and administrative, net." We also have been reimbursed for administrative, and
overhead costs incurred in conducting the business of the private limited
partnerships, which totaled $0.1 million per year in 2006 and 2005, and $0.2
million in 2004, and are recorded as reductions in "General and administrative,
net." As of December 31, 2006, the remaining two partnerships have been
dissolved.
We receive research, technical writing, publishing, and website-related
services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and
controlled and majority owned by the aunt of the Company's Chairman of the Board
and Chief Executive Officer. We paid approximately $0.5 million to Tec-Com for
such services pursuant to the terms of the contract between the parties in 2006,
and $0.4 million per year in 2005 and 2004. The contract was renewed June 30,
2004 on substantially the same terms and expires June 30, 2007. We believe that
the terms of this contract are consistent with third party arrangements that
provide similar services.
As a matter of corporate governance policy and practice, related party
transactions are annually presented and considered by the Corporate Governance
Committee of our Board of Directors in accordance with the Committee's charter.
8. Foreign Activities
As of December 31, 2006, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $349.1 million. Approximately $332.5
million has been included in the "Proved properties" portion of our oil and gas
properties, while $16.6 million is included as "Unproved properties." Our
functional currency in New Zealand is the U.S. Dollar. Net assets of our New
Zealand operations total $261.3 million at December 31, 2006. Our capital
expenditures on oil and gas property in New Zealand were approximately $56.7
million in 2006.
9. Acquisitions and Dispositions
In October 2006, we acquired interests in five South Louisiana fields. The
property interests are located in: Bayou Sale, Horseshoe Bayou and Jeanerette
fields (all located in St. Mary Parish), High Island field in Cameron Parish and
Bayou Penchant field in Terrebonne Parish. We paid approximately $167.9 million
in cash for these interests. After taking into account internal acquisition
costs of $4.0 million, our total cost was $171.9 million. We allocated $143.1
million of the acquisition price to "Proved Properties," $28.8 million to
"Unproved Properties," and recorded a liability for $11.5 million to "Asset
retirement obligation" on our accompanying consolidated balance sheet. These
acquisitions were accounted for by the purchase method of accounting. We made
these acquisitions to increase our exploration and development opportunities in
South Louisiana. The revenues and expenses from these properties have been
included in our accompanying consolidated statements of income from the date of
acquisition forward; however, given the acquisitions closed in the fourth
quarter of 2006, these amounts were not material to our full year 2006 results.
In December 2006, we acquired additional interests in our Lake Washington
field. We paid approximately $20.0 million in cash for these interests. After
taking into account internal acquisition costs of $0.4 million, our total cost
was $20.4 million. We allocated $17.9 million of the acquisition price to
"Proved Properties," $2.5 million to "Unproved Properties," and recorded a
liability for $0.8 million to "Asset retirement obligation" on our accompanying
consolidated balance sheet. This acquisition was accounted for by the purchase
method of accounting. We made this acquisition to increase our exploration and
development opportunities in South Louisiana. The revenues and expenses from
this acquisition have been included in our accompanying consolidated statements
of income from the date of acquisition forward; however, given the acquisition
closed in December 2006, these amounts were not material to our full year 2006
results.
74
In April 2006, we sold our minority interest in the Brookeland natural gas
processing plants for approximately $20.3 million in cash. Under the "full-cost"
method of accounting for oil and gas property and equipment costs, the proceeds
of this sale were applied against our oil and gas properties and equipment
balance, and no gain or loss was recognized on this transaction.
In November 2005, we acquired interests in the South Bearhead Creek field
in Central Louisiana. This field is approximately 50 miles south of our Masters
Creek field. We paid approximately $24.3 million in cash for these interests.
After taking into account internal acquisition costs of $2.6 million and assumed
liabilities of $1.4 million, our total cost was $28.3 million. We allocated
$26.2 million of the acquisition price to "Proved Properties," $2.5 million to
"Unproved Properties," and recorded a liability for $0.4 million to "Asset
retirement obligation" on our accompanying consolidated balance sheet. In
December 2006, we acquired additional interests in this field. We paid
approximately $4.5 million in cash for these additional interests. After taking
into account internal acquisition costs of $0.1 million, our total cost was $4.6
million. We allocated $4.1 million of the acquisition price to "Proved
Properties" and $0.5 million to "Unproved Properties" on our accompanying
consolidated balance sheet. These acquisitions were accounted for by the
purchase method of accounting. We made these acquisitions to increase our
exploration and development opportunities in this area. The revenues and
expenses from these properties have been included in our accompanying
consolidated statements of income from the date the acquisition closed. However,
given the acquisitions closed in November 2005 and December 2006, these amounts
were immaterial for both the 2005 and 2006 periods.
In December 2004, we acquired interests in two fields in South Louisiana,
the Bay de Chene and Cote Blanche Island fields. We paid approximately $27.7
million in cash for these interests. After taking into account internal
acquisition costs of $2.8 million, our total cost was $30.5 million. We
allocated $27.8 million of the acquisition price to "Proved properties" and $5.1
million to "Unproved properties" we also recorded $0.5 million to "Restricted
assets" and recorded a liability of $2.9 million to "Asset retirement
obligation" on our accompanying consolidated balance sheet. This acquisition was
accounted for by the purchase method of accounting. We made this acquisition to
increase our exploration and development opportunities in South Louisiana. The
revenues and expenses from these properties have been included in our
accompanying consolidated statements of income from the date the acquisition
closed. However, given the acquisition closed in late December 2004, these
amounts were immaterial for that year.
10. Condensed Consolidating Financial Information
In December 2005, we amended the indenture for our 9-3/8% Senior
Subordinated Notes due 2012 and our 7-5/8% Senior Notes due 2011 to reflect our
new holding company organizational structure (as discussed in Note 1). As part
of this restructuring our indentures were amended so that both Swift Energy
Company and Swift Energy Operating, LLC (a wholly owned indirect subsidiary of
Swift Energy Company) became co-obligors of these senior notes and senior
subordinated debt. The co-obligations are full and unconditional and are joint
and several. Prior to this restructure, Swift Energy Company was the sole
obligor. The following is condensed consolidating financial information for
Swift Energy Company, Swift Energy Operating, LLC, and other subsidiaries:
75
Condensed Consolidating Balance Sheets
(in 000's) December 31, 2006
-----------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Elminations Consolidated
---------------- -------------- ------------ --------------- ----------------
ASSETS
Current assets $ --- $ 75,270 $ 17,303 $ --- $ 92,573
Property and equipment --- 1,239,722 243,590 --- 1,483,312
Investment in subsidiaries (equity
method) 797,917 --- 590,720 (1,388,637) ---
Other assets --- 42,519 705 (33,427) 9,797
---------------- -------------- ------------ --------------- ----------------
Total assets $ 797,917 $ 1,357,511 $ 852,318 $ (1,422,064) $ 1,585,682
================ ============== ============ =============== ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ --- $ 137,016 $ 8,959 $ --- $ 145,975
Long-term liabilities --- 629,775 45,442 (33,427) 641,789
Stockholders' equity 797,917 590,720 797,917 (1,388,637) 797,917
---------------- -------------- ------------ --------------- ----------------
Total liabilities and
stockholders' equity $ 797,917 $ 1,357,511 $ 852,318 $ (1,422,064) $ 1,585,682
================ ============== ============ =============== ================
(in 000's) December 31, 2005
-----------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Elminations Consolidated
---------------- -------------- ------------ --------------- ----------------
ASSETS
Current assets $ --- $ 92,788 $ 22,267 $ --- $ 115,055
Property and equipment --- 862,717 216,316 --- 1,079,034
Investment in subsidiaries (equity
method) 607,318 --- 410,612 (1,017,930) ---
Other assets --- 31,955 682 (22,313) 10,324
---------------- -------------- ------------ --------------- ----------------
Total assets $ 607,318 $ 987,460 $ 649,877 $ (1,040,243) $ 1,204,413
================ ============== ============ =============== ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ --- $ 85,472 $ 12,949 $ --- $ 98,421
Long-term liabilities --- 491,376 29,610 (22,313) 498,674
Stockholders' Equity 607,318 410,612 607,318 (1,017,930) 607,318
---------------- -------------- ------------ --------------- ----------------
Total liabilities and
stockholders' equity $ 607,318 $ 987,460 $ 649,877 $ (1,040,243) $ 1,204,413
================ ============== ============ =============== ================
76
(in 000's) December 31, 2004
------------------------------------------------------------------
Swift Energy Co.
(Parent and Other Swift Energy Co.
Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ -----------------
ASSETS
Current assets $ 38,713 $ 15,673 $ --- $ 54,386
Property and equipment 719,209 204,229 --- 923,438
Investment in subsidiaries (equity
method) 104,003 --- (104,003) ---
Other assets 116,537 2,364 (106,152) 12,749
---------------- -------------- ------------ -----------------
Total assets $ 978,462 $ 222,265 $ (210,155) $ 990,573
================ ============== ============ =================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ 60,160 $ 8,458 $ --- $ 68,618
Long-term liabilities 444,130 109,805 (106,152) 447,783
Stockholders' Equity 474,172 104,003 (104,003) 474,172
---------------- -------------- ------------ -----------------
Total liabilities and
stockholders' equity $ 978,462 $ 222,265 $ (210,155) $ 990,573
================= ============== ============ =================
77
Condensed Consolidating Statements of Income
(in 000's) Year Ended December 31, 2006
-----------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Elminations Consolidated
---------------- -------------- ------------ --------------- -----------------
Revenues $ --- $ 550,540 $ 64,901 $ --- $ 615,441
Expenses --- 302,232 50,923 --- 353,155
---------------- -------------- ------------ --------------- ----------------
Income (loss) before the following: --- 248,308 13,978 --- 262,286
Equity in net earnings of
subsidiaries 161,565 --- 151,075 (312,640) ---
---------------- -------------- ------------ --------------- ----------------
Income before income taxes 161,565 248,308 165,052 (312,640) 262,286
Income tax provision (benefit) --- 97,234 3,487 --- 100,721
---------------- -------------- ------------ --------------- ----------------
Net income $ 161,565 $ 151,074 $ 161,565 $ (312,640) $ 161,565
================ ============== ============ =============== ================
(in 000's) Year Ended December 31, 2005
-----------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Elminations Consolidated
---------------- -------------- ------------ --------------- ----------------
Revenues $ --- $ 354,367 $ 68,893 $ (34) $ 423,226
Expenses --- 198,237 46,583 (34) 244,787
---------------- -------------- ------------ --------------- ----------------
Income (loss) before the following: --- 156,130 22,309 --- 178,440
Equity in net earnings of
subsidiaries 115,778 --- 97,880 (213,659) ---
---------------- -------------- ------------ --------------- ----------------
Income before income taxes 115,778 156,130 120,190 (213,659) 178,440
Income tax provision (benefit) --- 58,249 4,412 --- 62,661
---------------- -------------- ------------ --------------- ----------------
Net income $ 115,778 $ 97,881 $ 115,778 $ (213,659) $ 115,778
================ ============== ============ =============== ================
78
(in 000's) Year Ended December 31, 2004
-----------------------------------------------------------------
Swift Energy Co.
(Parent and Other Swift Energy Co.
Issuer) Subsidiaries Elminations Consolidated
---------------- -------------- ------------ ----------------
Revenues $ 256,608 $ 53,817 $ (147) $ 310,277
Expenses 171,147 37,838 (147) 208,837
---------------- -------------- ------------ ----------------
Income (loss) before the following: 85,461 15,979 --- 101,440
Equity in net earnings of
subsidiaries 14,733 --- (14,733) ---
----------------- -------------- ------------ ----------------
Income before income taxes 100,194 15,979 (14,733) 101,440
Income tax provision (benefit) 31,743 1,247 --- 32,989
---------------- -------------- ------------ ----------------
Net income $ 68,451 $ 14,733 $ (14,733) $ - 68,451
================ ============== ============ ================
79
Condensed Consolidating Statements of Cash Flow
(in 000's) Year Ended December 31, 2006
------------------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Elminations Consolidated
----------------- ---------------- -------------- -------------- ------------------
Cash flow from operations $ --- $ 383,241 $ 41,680 $ --- $ 424,921
Cash flow from investing
activities --- (474,781) (59,881) 11,115 (523,546)
Cash flow from financing
activities --- 46,679 11,115 (11,115) 46,679
----------------- ---------------- -------------- -------------- ----------------
Net decrease in cash --- (44,861) (7,086) --- (51,947)
Cash, beginning of period --- 44,911 8,094 --- 53,005
----------------- ---------------- -------------- -------------- ----------------
Cash, end of period $ --- $ 50 $ 1,008 $ --- $ 1,058
================= ================ ============== ============== ================
(in 000's) Year Ended December 31, 2005
------------------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Elminations Consolidated
----------------- ---------------- -------------- -------------- ------------------
Cash flow from operations $ --- $ 236,790 $ 48,543 $ --- $ 285,333
Cash flow from investing
activities --- (194,909) (48,837) 3,672 (240,074)
Cash flow from financing
activities --- 2,825 3,672 (3,672) 2,825
----------------- ---------------- -------------- -------------- -------------------
Net increase in cash $ --- $ 44,706 $ 3,379 $ --- $ 48,084
Cash, beginning of period --- 205 4,715 --- 4,920
---------------- ---------------- -------------- -------------- ------------------
Cash, end of period $ --- $ 44,911 $ 8,094 $ --- $ 53,005
================= ================ ============== ============== ==================
(in 000's) Year Ended December 31, 2004
-----------------------------------------------------------------------------
Swift Energy Co.
(Parent and Swift Energy Co.
Issuer) Other Subsidiaries Eliminations Consolidated
------------------ ------------------ ----------------- ----------------
Cash flow from operations $ 147,114 $ 35,469 $ --- $ 182,583
Cash flow from investing activities (158,308) (35,878) 5,100 (189,086)
Cash flow from financing activities 10,357 5,100 (5,100) 10,357
------------------ ------------------ ----------------- ----------------
Net increase (decrease) in cash (837) 4,691 --- 3,854
Cash, beginning of period 1,042 24 --- 1,066
------------------ ------------------ ----------------- ----------------
Cash, end of period $ 205 $ 4,715 $ --- $ 4,920
================== ================== ================= ================
80
11. Segment Information
The Company has two reportable segments, one domestic and one foreign,
which are in the business of crude oil and natural gas exploration and
production. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies. We evaluate our
performance based on profit or loss from oil and gas operations before
price-risk management and other, net, general and administrative, net, interest
expense, net and debt retirement costs. Our reportable segments are managed
separately based on their geographic locations. Financial information by
operating segment is presented below:
2006
------------------------------------------------
Domestic New Zealand Total
-------------- ------------- ---------------
Oil and gas sales $ 537,512,509 $ 64,038,859 $ 601,551,368
Costs and Expenses:
Depreciation, depletion, and
amortization (139,244,630) (30,051,144) (169,295,774)
Accretion of asset retirement
obligation (884,105) (150,217) (1,034,322)
Lease operating cost (49,948,039) (12,526,580) (62,474,619)
Severance and other taxes (61,234,906) (4,217,137) (65,452,043)
------------ ------------- ---------------
Income from oil and gas operations $ 286,200,829 $ 17,093,781 $ 303,294,610
Price-risk management and other,
net 13,889,862
General and administrative, net (31,316,644)
Interest expense, net (23,581,663)
---------------
Income before Income Taxes $ 262,286,165
===============
Property and Equipment, net $1,255,331,575 $ 227,980,590 $ 1,483,312,165
Total Assets 1,349,684,402 235,997,356 1,585,681,758
Capital Expenditures $ 502,342,254 $ 55,149,258 $ 557,491,512
============== ============= ===============
81
2005
------------------------------------------------
Domestic New Zealand Total
-------------- ------------- ---------------
Oil and gas sales $ 355,872,616 $ 67,893,629 $ 423,766,245
Costs and Expenses:
Depreciation, depletion, and
amortization (81,123,588) (26,354,199) (107,477,787)
Accretion of asset retirement
obligation (626,134) (134,908) (761,042)
Lease operating cost (34,941,430) (12,380,411) (47,321,841)
Severance and other taxes (37,805,742) (4,370,763) (42,176,505)
-------------- ------------- ---------------
Income from oil and gas operations $ 201,375,722 $ 24,653,348 $ 226,029,070
Price-risk management and other,
net (539,756)
General and administrative, net (22,176,362)
Interest expense, net (24,873,401)
---------------
Income before Income Taxes $ 178,439,551
===============
Property and Equipment, net $ 863,154,295 $ 215,879,444 $ 1,079,033,739
Total Assets 962,469,183 241,943,439 1,204,412,622
Capital Expenditures $ 215,785,080 $ 48,689,826 $ 264,474,906
============== ============= ===============
2004
------------------------------------------------
Domestic New Zealand Total
-------------- ------------- ---------------
Oil and gas sales $ 258,663,936 $ 52,621,236 $ 311,285,172
Costs and Expenses:
Depreciation, depletion, and
amortization (62,283,350) (19,297,478) (81,580,828)
Accretion of asset retirement
obligation (505,174) (168,480) (673,654)
Lease operating cost (30,191,889) (11,022,367) (41,214,256)
Severance and other taxes (26,713,592) (3,687,701) (30,401,293)
-------------- ------------- ---------------
Income from oil and gas operations $ 138,969,931 $ 18,445,210 $ 157,415,141
Price-risk management and other,
net (1,008,398)
General and administrative, net (17,787,125)
Interest expense, net (27,643,108)
Debt retirement costs (9,536,268)
---------------
Income before Income Taxes $ 101,440,242
===============
Property and Equipment, net $ 731,890,068 $ 191,548,092 $ 923,438,160
Total Assets 778,611,100 211,962,047 990,573,147
Capital Expenditures $ 162,535,617 $ 35,755,820 $ 198,291,437
============== ============= ===============
82
Supplementary Information
Swift Energy Company and Subsidiaries
Oil and Gas Operations (Unaudited)
Capitalized Costs. The following table presents our aggregate capitalized
costs relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:
Total Domestic New Zealand
-------------------- --------------- -----------------
December 31, 2006:
Proved oil and gas properties $ 2,264,831,638 $ 1,932,336,298 $ 332,495,340
Unproved oil and gas properties 112,136,836 95,569,089 16,567,747
-------------------- --------------- -----------------
2,376,968,474 2,027,905,387 349,063,087
Accumulated depreciation, depletion, and amortization (915,397,437) (808,708,770) (106,688,667)
-------------------- --------------- -----------------
Net capitalized costs $ 1,461,571,037 $ 1,219,196,617 $ 242,374,420
==================== =============== =================
December 31, 2005:
Proved oil and gas properties $ 1,731,866,298 $ 1,468,981,981 $ 262,884,317
Unproved oil and gas properties 87,553,220 58,196,531 29,356,689
-------------------- --------------- -----------------
1,819,419,518 1,527,178,512 292,241,006
Accumulated depreciation, depletion, and amortization (748,327,443) (671,117,089) (77,210,354)
-------------------- --------------- -----------------
Net capitalized costs $ 1,071,092,075 $ 856,061,423 $ 215,030,652
==================== =============== =================
Of the $95.6 million of domestic Unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 2006, excluded from the amortizable
base, $68.3 million was incurred in 2006, $13.3 million was incurred in 2005,
$8.9 million was incurred in 2004, and $5.1 million was incurred in prior years.
When we are in an active drilling mode, we evaluate the majority of these
unproved costs within a two to four year time frame.
Of the $16.6 million of New Zealand Unproved property costs at December 31,
2006, excluded from the amortizable base, $8.0 million was incurred in 2006,
$2.1 million was incurred in 2005, $1.7 million was incurred in 2004, and $4.8
million was incurred in prior years. We expect to continue drilling in New
Zealand to delineate our prospects there within a two to four year time frame.
Capitalized asset retirement obligations have been included in the Proved
properties as of December 31, 2006, 2005, and 2004.
83
Costs Incurred. The following table sets forth costs incurred related to
our oil and gas operations:
Year Ended December 31, 2006
-----------------------------------------------------------
Total Domestic New Zealand
-------------------- --------------- -----------------
Acquisition of proved and unproved properties $ 212,499,280 $ 212,499,280 $ --
Lease acquisitions and prospect costs(1) 79,183,368 68,594,051 10,589,317
Exploration 29,285,958 13,224,894 16,061,064
Development (2) 261,142,220 231,085,290 30,056,930
-------------------- --------------- -----------------
Total acquisition, exploration, and development (3),(4) $ 582,110,826 $ 525,403,515 $ 56,707,311
-------------------- --------------- -----------------
Year Ended December 31, 2005
-----------------------------------------------------------
Total Domestic New Zealand
-------------------- --------------- -----------------
Acquisition of proved and unproved properties $ 31,429,343 $ 31,429,343 $ --
Lease acquisitions and prospect costs(1) 41,397,277 34,502,163 6,895,114
Exploration 52,350,339 38,424,995 13,925,344
Development (2) 141,081,231 111,057,945 30,023,286
-------------------- --------------- -----------------
Total acquisition, exploration, and development (3),(4) $ 266,258,190 $ 215,414,446 $ 50,843,744
-------------------- --------------- -----------------
Year Ended December 31, 2004
-----------------------------------------------------------
Total Domestic New Zealand
-------------------- --------------- -----------------
Acquisition of proved and unproved properties $ 31,771,094 $ 31,771,094 $ --
Lease acquisitions and prospect costs(1) 34,545,393 27,713,059 6,832,334
Exploration 17,430,265 16,714,982 715,283
Development (2) 108,259,091 79,338,697 28,920,394
-------------------- --------------- -----------------
Total acquisition, exploration, and development (3),(4) $ 192,005,843 $ 155,537,832 $ 36,468,011
-------------------- --------------- -----------------
(1)These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties in 2006, 2005, and 2004 were $70.5 million, $30.4 million,
and $17.8 million, respectively. Domestic costs for seismic data acquisition,
included above, were $23.1 million, 4.2 million, and $1.0 million in 2006, 2005
and 2004, respectively. New Zealand costs for seismic data acquisition, included
above were $3.8 million in 2006.
(2)Facility construction costs and capital costs have been included in
development costs, and totaled $16.5 million, $26.9 million, and $12.6 million
for the years ended December 31, 2006, 2005 and 2004.
(3)Includes capitalized general and administrative costs directly associated
with the acquisition, exploration, and development efforts of approximately
$28.3 million, $18.8 million, and $13.1 million in 2006, 2005, and 2004,
respectively. In addition, total includes $9.2 million, $7.2 million, and $6.5
million in 2006, 2005, and 2004, respectively, of capitalized interest on
unproved properties.
(4)Asset retirement obligations incurred have been included in exploration,
development and acquisition costs as applicable for the years ended December 31,
2006, 2005, and 2004.
84
Results of Operations.
Year Ended December 31, 2006
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 601,551,368 $ 537,512,509 $ 64,038,859
Lease operating cost (62,474,619) (49,948,039) (12,526,580)
Severance and other taxes (65,452,043) (61,234,906) (4,217,137)
Depreciation, depletion, and amortization (166,518,190) (136,826,013) (29,692,177)
Accretion of asset retirement obligation (1,034,322) (884,105) (150,217)
---------------- --------------- ----------------
306,072,194 288,619,446 17,452,748
Provision for income taxes 117,531,722 110,829,867 6,701,855
---------------- --------------- ----------------
Results of producing activities $ 188,540,472 $ 177,789,579 $ 10,750,893
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 2.37 $ 2.41 $ 2.20
================ =============== ================
Year Ended December 31, 2005
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 423,766,245 $ 355,872,616 $ 67,893,629
Lease operating cost (47,321,841) (34,941,430) (12,380,411)
Severance and other taxes (42,176,505) (37,805,742) (4,370,763)
Depreciation, depletion and amortization (106,037,775) (79,926,245) (26,111,530)
Accretion of asset retirement obligation (761,042) (626,134) (134,908)
---------------- --------------- ----------------
227,469,082 202,573,065 24,896,017
Provision for income taxes 79,878,043 74,953,611 4,924,432
---------------- --------------- ----------------
Results of producing activities $ 147,591,039 $ 127,619,454 $ 19,971,585
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.78 $ 1.86 $ 1.58
================ =============== ================
Year Ended December 31, 2004
---------------------------------------------------
Total Domestic New Zealand
---------------- --------------- ----------------
Oil and gas sales $ 311,285,172 $ 258,663,936 $ 52,621,236
Lease operating cost (41,214,256) (30,191,889) (11,022,367)
Severance and other taxes (30,401,293) (26,713,592) (3,687,701)
Depreciation, depletion and amortization (80,504,043) (61,478,364) (19,025,679)
Accretion of asset retirement obligation (673,654) (505,174) (168,480)
---------------- --------------- ----------------
158,491,926 139,774,917 18,717,009
Provision for income taxes 53,093,022 51,576,944 1,516,078
---------------- --------------- ----------------
Results of producing activities $ 105,398,904 $ 88,197,973 $ 17,200,931
================ =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.38 $ 1.46 $ 1.17
================ =============== ================
These results of operations do not include the gains from our hedging
activities of $4.0 million in 2006, and losses from our hedging activities of
$1.1 million and $1.3 million for 2005 and 2004, respectively. Our lease
operating costs per Mcfe produced were $0.89 in 2006, $0.79 in 2005, and $0.71
in 2004.
The accretion of asset retirement obligation has been included in the 2006,
2005 and 2004 periods.
We used our effective tax rate in each country to compute the provision for
income taxes in each year presented.
85
Supplementary Reserves Information. The following information presents
estimates of our proved oil and gas reserves. Reserves were determined by us and
audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum
consultants. Gruy has audited 100% of our proved reserves. Gruy's audit was
conducted according to standards approved by the Board of Directors of the
Society of Petroleum Engineers, Inc. and included examination, on a test basis,
of the evidence supporting our reserves. Gruy's audit was based upon review of
production histories and other geological, economic, and engineering data
provided by us. Gruy's report dated January 23, 2007, is set forth as an exhibit
to the Form 10-K Report for the year ended December 31, 2006, and includes
definitions and assumptions that served as the basis for the audit of proved
reserves and future net cash flows. Such definitions and assumptions should be
referred to in connection with the following information:
Estimates of Proved Reserves Total Domestic New Zealand
-------------------------- ----------------------------- -------------------------
Oil, NGL, Oil, NGL, Oil, NGL,
and and and
Natural Gas Condensate Natural Gas Condensate Natural Gas Condensate
(Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
------------ ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2003 335,804,862 80,759,903 242,321,275 67,015,693 93,483,587 13,744,210
Revisions of previous estimates(1) (3,306,705) (1,117,715) (1,619,531) 695,274 (1,687,174) (1,812,989)
Purchases of minerals in place 9,808,953 5,602,508 9,808,953 5,602,508 -- --
Sales of minerals in place (2,524,760) (44,803) (2,524,760) (44,803) -- --
Extensions, discoveries, and other
additions 2,205,670 830,111 2,205,670 830,111 -- --
Production (23,741,726) (5,762,796) (12,299,772) (4,959,740) (11,441,954) (803,056)
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2004 318,246,294 80,267,208 237,891,835 69,139,043 80,354,459 11,128,165
Revisions of previous estimates(1) (21,461,605) (2,199,673) (13,751,124) (1,023,808) (7,710,481) (1,175,866)
Purchases of minerals in place 9,336,088 3,262,761 9,336,088 3,262,761 -- --
Sales of minerals in place (3,737,714) (100,121) (3,737,714) (100,121) -- --
Extensions, discoveries, and other
additions 8,699,329 3,819,595 7,275,207 3,722,744 1,424,122 96,851
Production (23,609,242) (5,996,714) (11,739,485) (5,217,343) (11,869,757) (779,371)
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2005 287,473,150 79,053,056 225,274,807 69,783,276 62,198,343 9,269,779
Revisions of previous estimates(1) (33,631,025) 3,127,635 (34,542,219) 3,135,885 911,194 (8,250)
Purchases of minerals in place 60,187,095 2,922,553 60,187,095 2,922,553 -- --
Sales of minerals in place (6,122,283) (708,691) (6,122,283) (708,691) -- --
Extensions, discoveries, and other
additions 39,012,428 5,627,297 38,466,980 5,512,795 545,448 114,502
Production (22,787,948) (7,902,766) (13,603,589) (7,181,287) (9,184,359) (721,479)
------------- ------------ -------------- ------------ ------------ ------------
Proved reserves as of December 31, 2006 324,131,417 82,119,084 269,660,791 73,464,531 54,470,626 8,654,552
============= ============ ============== ============ ============ ============
Proved developed reserves: (2)
December 31, 2003 210,119,927 45,525,366 138,173,341 38,767,983 71,946,586 6,757,383
December 31, 2004 193,310,761 42,037,852 140,549,052 36,628,873 52,761,709 5,408,979
December 31, 2005 152,001,133 37,989,821 125,367,690 35,298,324 26,633,443 2,691,497
December 31, 2006 151,276,834 34,956,469 133,815,108 33,345,567 17,461,726 1,610,902
(1)Revisions of previous estimates are related to upward or downward variations
based on current engineering information for production rates, volumetrics, and
reservoir pressure. Additionally, changes in quantity estimates are affected by
the increase or decrease in crude oil, NGL, and natural gas prices at each
year-end. Proved reserves, as of December 31, 2006, were based upon prices in
effect at year-end. Our hedges at year-end 2006 consisted of natural gas price
floors with strike prices higher than the period end price and thus would not
materially affect prices used in these calculations. The weighted average of
2006 year-end prices for total, domestic, and New Zealand were $5.46, $5.84, and
$3.59 per Mcf of natural gas, $60.41, $60.07, and $63.51 per barrel of oil, and
$30.93, $31.54 and $26.84 per barrel of NGL, respectively. This compares to
$8.94, $10.36, and $3.79 per Mcf of natural gas, $60.12, $60.00, and $60.98 per
barrel of oil, and $31.40, $33.28 and $19.20 per barrel of NGL as of December
31, 2005, for total, domestic, and New Zealand, respectively. The weighted
average of 2004 year-end prices for total, domestic, and New Zealand were $5.16,
$5.87, and $3.07 per Mcf of natural gas, $41.07, $42.21, and $33.60 per barrel
of oil, and $25.48, $26.49 and $20.48 per barrel of NGL, respectively.
(2)At December 31, 2006, 44% of our reserves were proved developed, compared to
50% at December 31, 2005, 56% at December 31, 2004, and 59% at December 31,
2003.
86
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future nt cash flows relating to proved oil and gas
reserves is as follows:
Year Ended December 31, 2006
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 6,341,394,321 $ 5,659,084,913 $ 682,309,408
Future production costs (1,393,634,094) (1,167,117,123) (226,516,971)
Future development costs (935,003,617) (886,842,793) (48,160,824)
----------------- ----------------- -----------------
Future net cash flows before income taxes 4,012,756,610 3,605,124,997 407,631,613
Future income taxes (1,187,858,603) (1,137,617,295) (50,241,308)
----------------- ----------------- -----------------
Future net cash flows after income taxes 2,824,898,007 2,467,507,702 357,390,305
Discount at 10% per annum (956,238,277) (835,593,066) (120,645,211)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,868,659,730 $ 1,631,914,636 $ 236,745,094
================= ================= =================
Year Ended December 31, 2005
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 6,917,103,123 $ 6,194,560,214 $ 722,542,909
Future production costs (1,334,822,738) (1,122,637,935) (212,184,803)
Future development costs (710,343,331) (667,526,650) (42,816,681)
----------------- ----------------- -----------------
Future net cash flows before income taxes 4,871,937,054 4,404,395,629 467,541,425
Future income taxes (1,538,799,956) (1,461,577,946) (77,222,010)
----------------- ----------------- -----------------
Future net cash flows after income taxes 3,333,137,098 2,942,817,683 390,319,415
Discount at 10% per annum (1,173,767,635) (1,048,193,951) (125,573,684)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 2,159,369,463 $ 1,894,623,732 $ 264,745,731
================= ================= =================
Year Ended December 31, 2004
---------------------------------------------------------
Total Domestic New Zealand
----------------- ----------------- -----------------
Future gross revenues $ 4,711,060,300 $ 4,122,705,861 $ 588,354,439
Future production costs (1,029,449,670) (819,035,166) (210,414,504)
Future development costs (480,093,684) (434,305,537) (45,788,147)
----------------- ----------------- -----------------
Future net cash flows before income taxes 3,201,516,946 2,869,365,158 332,151,788
Future income taxes (896,135,438) (866,598,544) (29,536,894)
----------------- ----------------- -----------------
Future net cash flows after income taxes 2,305,381,508 2,002,766,614 302,614,894
Discount at 10% per annum (840,436,013) (746,227,690) (94,208,323)
----------------- ----------------- -----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,464,945,495 $ 1,256,538,924 $ 208,406,571
================= ================= =================
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future gross revenues of proved reserves are priced on the
basis of year-end prices, except in those instances where fixed and determinable
gas price escalations are covered by contracts limited to the price we
reasonably expect to receive.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as asset retirement
obligation costs, net of salvage value, based on year-end cost estimates and the
estimated effect of future income taxes.
87
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period. Our hedges at year-end 2006
consisted mainly of natural gas price floors with strike prices higher than the
period end price and did not materially affect prices used in these
calculations. Subsequent changes to such year-end oil and gas prices could have
a significant impact on discounted future net cash flows. Under Securities and
Exchange Commission rules, companies that follow the full-cost accounting method
are required to make quarterly Ceiling Test calculations using hedge adjusted
prices in effect as of the period end date presented (see Note 1 to the
consolidated financial statements). Application of these rules during periods of
relatively low oil and gas prices, even if of short-term seasonal duration, may
result in non-cash write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of our oil and gas property reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, an allowance for return on investment, and the risks inherent
in reserves estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
--------------------------------------------------------
2006 2005 2004
----------------- ------------------ ----------------
Beginning balance $ 2,159,369,463 $ 1,464,945,495 $ 1,134,856,535
----------------- ------------------ ----------------
Revisions to reserves proved in prior years--
Net changes in prices, and production costs (658,283,413) 1,232,876,998 398,333,372
Net changes in future development costs (166,890,534) (173,219,347) (117,672,270)
Net changes due to revisions in quantity (60,713,716) (138,969,442) (12,754,357)
estimates
Accretion of discount 314,344,631 199,799,374 152,715,946
Other (98,478,730) 17,191,849 49,111,385
----------------- ------------------ ----------------
Total revisions (670,021,762) 1,137,679,432 469,734,076
New field discoveries and extensions, net of future
production and development costs 212,629,383 152,461,162 30,609,517
Purchases of minerals in place 289,338,576 99,129,117 118,575,886
Sales of minerals in place (20,378,583) (10,164,069) (7,339,601)
Sales of oil and gas produced, net of production (473,624,706) (334,267,899) (239,669,623)
costs
Previously estimated development costs incurred 187,133,510 100,614,837 98,924,021
Net change in income taxes 184,213,849 (451,028,612) (140,745,316)
----------------- ------------------ ----------------
Net change in standardized measure of discounted
future net cash flows (290,709,733) 694,423,968 330,088,960
----------------- ------------------ ----------------
Ending balance $ 1,868,659,730 $ 2,159,369,463 $ 1,464,945,495
================= ================== ================
88
Selected Quarterly Financial Data (Unaudited). The following table presents
summarized quarterly financial information for the years ended December 31, 2006
and 2005:
Income Basic Diluted
Before EPS EPS
Income Net Net Net
Revenues Taxes Income Income Income
-------------- ------------- ------------- -------- --------
2006:
First $ 136,168,931 $ 57,774,996 $ 37,314,506 $ 1.28 $ 1.24
Second 147,177,246 60,189,700 38,168,448 1.31 1.27
Third 173,458,852 82,209,164 50,811,567 1.74 1.68
Fourth 158,636,201 62,112,305 35,270,819 1.19 1.16
-------------- ------------- -------------
Total $ 615,441,230 $ 262,286,165 $ 161,565,340 $ 5.52 $ 5.38
============== ============= =============
2005:
First $ 95,620,684 $ 39,758,619 $ 25,689,152 $ 0.91 $ 0.89
Second 104,299,925 41,778,041 27,881,658 0.98 0.96
Third 100,853,505 42,901,655 27,506,899 0.96 0.92
Fourth 122,452,375 54,001,236 34,700,747 1.20 1.16
-------------- ------------- ------------- ------- -------
Total $ 423,226,489 $ 178,439,551 $ 115,778,456 $ 4.06 $ 3.95
============== ============= ============= ======= =======
There were no extraordinary items in 2006 or 2005.
The sum of the individual quarterly net income per common share amounts may
not agree with year-to-date net income per common share as each quarterly
computation is based on the weighted average number of common shares outstanding
during that period. In addition, certain potentially dilutive securities were
not included in certain of the quarterly computations of diluted net income per
common share because to do so would have been antidilutive.
89
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Item 9A. Controls and Procedures
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange
Act") as of the end of the period covered by this report. Based on that
evaluation, they have concluded that such disclosure controls and procedures are
effective in alerting them on a timely basis to material information relating to
the Company required under the Exchange Act to be disclosed in this report.
There were no significant changes in the Company's internal controls that could
significantly affect such controls subsequent to the date of their evaluation.
Management's Report On Internal Control Over Financial Reporting as of
December 31, 2006 is included in Item 8. Financial Statements and Supplementary
Data. The Report of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting is also included in Item 8.
Item 9B. Other Information
None.
90
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required under Item 10 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 8, 2007, annual shareholders' meeting
is incorporated herein by reference.
Item 11. Executive Compensation
The information required under Item 11 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 8, 2007, annual shareholders' meeting
is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
The information required under Item 12 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 8, 2007, annual shareholders' meeting
is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director
Independence
The information required under Item 13 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 8, 2007, annual shareholders' meeting
is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
The information required under Item 14 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 8, 2007, annual shareholders' meeting
is incorporated by reference.
91
PART IV
Item 15. Exhibits and Financial Statement Schedules.
o 1. The following consolidated financial statements of Swift Energy Company
together with the report thereon of Ernst & Young LLP dated February 27,
2007, and the data contained therein are included in Item 8 hereof:
Management's Report on Internal Control Over Financial Reporting...............47
Report of Independent Registered Public Accounting Firm on Internal Control
Over Financial Reporting..............................................48
Report of Independent Registered Public Accounting Firm........................49
Consolidated Balance Sheets....................................................50
Consolidated Statements of Income..............................................51
Consolidated Statements of Stockholders' Equity................................52
Consolidated Statements of Cash Flows..........................................53
Notes to Consolidated Financial Statements.....................................54
o Financial Statement Schedules
[None]
3. Exhibits
2 Plan and Agreement and Articles of Merger to Form
Holding Company, dated as of December 21, 2005, but
effective at 9:00 a.m., local time in Austin, Texas
on December 28, 2005, by and among Swift Energy
Company, New Swift Energy Company and Swift Energy
Operating, LLC (incorporated by reference as Exhibit
2.1 to Swift Energy Company's Form 8-K filed December
29, 2005, File No. 1-08754).
3.1 Restated Articles of Incorporation of Swift Energy
Company (incorporated by reference as Exhibit 3.3 to
Swift Energy Company's Form 8-K filed December 29,
2005, File No. 1-08754).
3.2 Amended and Restated Bylaws of Swift Energy Company,
as amended through December 28, 2005 (incorporated by
reference as Exhibit 3.5 to Swift Energy Company's
Form 8-K filed December 29, 2005, File No. 1-08754).
3.3 Certificate of Designation of Series A Junior
Participating Preferred Stock of Swift Energy Company
(incorporated by reference as Exhibit 3.4 to Swift
Energy Company's Form 8-K filed December 29, 2005,
File No. 1-08754).
4.1 Indenture dated as of April 16, 2002, between Swift
Energy Company and Bank One, N.A., as Trustee
(incorporated by reference as Exhibit 4.1 to Swift
Energy Company's Form 8-K filed April 16, 2002, File
No. 1-08754).
4.2 First Supplemental Indenture dated as of April 16,
2002, between Swift Energy Company and Bank One,
N.A., including the form of 9 3/8% Senior
Subordinated Notes due 2012 (incorporated by
reference as Exhibit 4.2 to Swift Energy Company's
Form 8-K filed April 16, 2002, File No. 1-08754).
92
4.3 Second Supplemental Indenture dated as of December
28, 2005, between Swift Energy Company and J.P.
Morgan Trust Company, National Association as
successor Trustee to Bank One, NA (incorporated by
reference as Exhibit 4.1 to Swift Energy Company's
Form 8-K filed December 29, 2005, File No. 1-08754).
4.4 Indenture dated as of June 23, 2004, between Swift
Energy Company and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference as
Exhibit 4.1 to Swift Energy Company's Form 8-K filed
June 25, 2004, File No. 1-08754).
4.5 First Supplemental Indenture dated as of June 23,
2004, between Swift Energy Company and Wells Fargo
Bank, National Association, as Trustee, including the
form of 7 5/8% Senior Notes (incorporated by
reference as Exhibit 4.2 to Swift Energy Company's
Form 8-K filed June 25, 2004, File No. 1-08754).
4.6 Second Supplemental Indenture dated as of December
28, 2005, between Swift Energy Company and Wells
Fargo Bank. National Association, as Trustee
(incorporated by reference as Exhibit 4.2 to Swift
Energy Company's Form 8-K filed December 29, 2005,
File No. 1-08754).
4.7 Amended and Restated Rights Agreement between Swift
Energy Company and American Stock Transfer & Trust
Company, dated March 31, 1999 (incorporated by
reference to Swift Energy Company's Amendment No. 1
to Form 8-A filed April 7, 1999, File No. 1-08754).
4.8 Amendment No. 1 to the Rights Agreement dated
December 12, 2005 between Swift Energy Company and
American Stock Transfer & Trust Company, as Rights
Agent (incorporated by reference as Exhibit 4.3 to
Swift Energy Company's Form 8-K filed December 29,
2005, File No. 1-08754).
4.9 Assignment, Assumption, Amendment and Novation
Agreement between Swift Energy Company, New Swift
Energy Company and American Stock Transfer & Trust
Company, as Rights Agent effective at 9:00 a.m. local
time in Austin, Texas on December 28, 2005
(incorporated by reference as Exhibit 4.4 to Swift
Energy Company's Form 8-K filed December 29, 2005,
File No. 1-08754).
4.10 Amendment No. 2 to the Rights Agreement dated
December 21, 2006 between Swift Energy Company and
American Stock Transfer & Trust Company, as Rights
Agent (incorporated by reference as Exhibit 4.1 to
Swift Energy Company's Form 8-K filed December 22,
2006, File No. 1-08754).
10.1+ Amended and Restated Swift Energy Company 1990
Nonqualified Stock Option Plan, as of May 13, 1997
(incorporated by reference from Swift Energy
Company's definitive proxy statement for the annual
shareholders meeting filed April 14, 1997, File No.
1-08754).
10.2+ Amended and Restated Swift Energy Company 1990 Stock
Compensation Plan, as of May 13, 1997 (incorporated
by reference from Swift Energy Company's definitive
proxy statement for the annual shareholders meeting
filed April 14, 1997, File No. 1-08754).
10.3+ Amendment to the Swift Energy Company 1990 Stock
Compensation Plan, as of May 9, 2000 (incorporated by
reference as Exhibit 4.2 to the Swift Energy Company
registration statement No. 333-67242 on Form S-8
filed August 10, 2001, File No. 1-08754).
10.4+ Swift Energy Company 2001 Omnibus Stock Compensation
Plan, as of January 1, 2001 (incorporated by
reference as Exhibit 4.3 to the Swift Energy Company
registration statement no. 333-67242 on Form S-8
filed August 10, 2001, File No. 1-08754).
93
10.5+ Swift Energy Company 2005 Stock Compensation Plan
(incorporated by reference as Exhibit 10.1 to the
Swift Energy Company Form 8-K filed May 12, 2005,
File No. 1-08754).
10.6+ Amendment No. 1 to the Swift Energy Company 2005
Stock Compensation Plan, as of May 9, 2006
(incorporated by reference as Exhibit 10.1 to the
Swift Energy Company Form 8-K filed May 12, 2006).
10.7+ Employee Stock Purchase Plan (incorporated by
reference as Exhibit 4(a) to Swift Energy Company's
Registration Statement No. 33-80228 on Form S-8 filed
June 15, 1994, File No. 1-08754).
10.8+ Amended and Restated Employee Stock Purchase Plan
dated June 1, 2006 (incorporated by reference to
Swift Energy Company's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 2006, File
No. 1-08754).
10.9* Form of Indemnity Agreement for Swift Energy Company
officers.
10.10* Form of Indemnity Agreement for Swift Energy Company
directors.
10.11+ Amended and Restated Employment Agreement dated as of
November 15, 2000 between Swift Energy Company,
predecessor to Swift Energy Operating, LLC, and A.
Earl Swift (incorporated by reference as Exhibit
10.12 to Swift Energy Company's Annual Report on Form
10-K for the fiscal year ended December 31, 2000,
File No. 1-08754).
10.12+ Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company, predecessor
to Swift Energy Operating, LLC, and Terry E. Swift
(incorporated by reference as Exhibit 10.2 to Swift
Energy Company's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2001, File No.
1-08754).
10.13+ Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company, predecessor
to Swift Energy Operating, LLC, and James M.
Kitterman (incorporated by reference as Exhibit 10.6
to Swift Energy Company's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2001,
File No. 1-08754).
10.14+ Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company, predecessor
to Swift Energy Operating, LLC, and Bruce H. Vincent
(incorporated by reference as Exhibit 10.4 to Swift
Energy Company's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2001, File No.
1-08754).
10.15+ Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company, predecessor
to Swift Energy Operating, LLC, and Joseph A. D'Amico
(incorporated by reference as Exhibit 10.3 to Swift
Energy Company's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2001, File No.
1-08754).
10.16+ Employment Agreement dated as of May 9, 2001
between Swift Energy Company, predecessor to Swift
Energy Operating, LLC, and Victor R. Moran
(incorporated by reference as Exhibit 10.7 to Swift
Energy Company's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 2001, File No.
1-08754).
10.17+ Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company, predecessor
to Swift Energy Operating, LLC, and Alton D.
Heckaman, Jr. (incorporated by reference as Exhibit
10.5 to Swift Energy Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30,
2001, File No. 1-08754).
94
10.18+ Amended and Restated Employment Agreement dated as of
May 9, 2001 between Swift Energy Company and Donald
L. Morgan (incorporated by reference as Exhibit 10.8
to Swift Energy Company's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2001,
File No. 1-08754).
10.19+ Consulting Agreement between Swift Energy Company and
A. Earl Swift effective as of July 1, 2006
(incorporated by reference as Exhibit 10.1 to Swift
Energy Company's Quarterly Report on Form 10-Q for
the quarterly period ended March 31, 2006, File No.
1-08754).
10.20+ Consulting Agreement between Swift Energy Company and
Virgil N. Swift effective as of July 1, 2006
(incorporated by reference as Exhibit 10.1 to Swift
Energy Company's Quarterly Report on Form 10-Q for
the quarterly period ended March 31, 2006, File No.
1-08754).
10.21+ Fourth Amended and Restated Agreement and Release by
and between Swift Energy Company and Virgil Neil
Swift, dated November 20, 2000 (incorporated by
reference as Exhibit 10.13 to Swift Energy Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 2000, File No. 1-08754).
10.22+ Description of executive officers' compensation
arrangements (incorporated by reference as Exhibit
10.25 to Swift Energy Company's Annual Report on Form
10-K for the fiscal year ended December 31, 2004,
File No. 1-08754).
10.23+ Description of non-employee directors' compensation
arrangements (incorporated by reference as Exhibit
10.16 to Swift Energy Company's Annual Report on Form
10-K for the fiscal year ended December 31, 2004,
File No. 1-08754).
10.24 + Forms of agreements for grant of incentive and
non-qualified stock options and forms of agreement
for grant of restricted stock under Swift Energy
Company 2001 Omnibus Stock Compensation Plan
(incorporated by reference as Exhibit 10.17 to Swift
Energy Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2004, File No.
1-08754).
10.25+ Forms of agreements for grant of incentive stock
options and forms of agreement for grant of
restricted stock under Swift Energy Company 2005
Stock Compensation Plan (incorporated by reference as
Exhibit 10.19 to Swift Energy Company's Annual Report
on Form 10-K for the fiscal year ended December 31,
2005, File No. 1-08754).
10.26 First Amended and Restated Credit Agreement effective
as of June 29, 2004, among Swift Energy Company and
Bank One, NA as Administrative Agent, Wells Fargo
Bank, National Association as Syndication Agent, BNP
Paribas, as Syndication Agent, Caylon, as
Documentation agent, Societe Generale, as
Documentation Agent and the Lenders Signatory Hereto
and Banc One Capital Markets, Inc., as Sole Lead
Arranger and Sole Book Runner (incorporated by
reference as Exhibit 10.2 to the Swift Energy Company
Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 2004, File No. 1-08754).
10.27 First Amendment to First Amended and Restated Credit
Agreement effective as of November 1, 2005 by and
among Swift Energy Company, JP Morgan Chase Bank,
N.A. as Administrative Agent, J.P. Morgan Securities,
Inc. as Sole Lead Arranger and Sole Book Runner,
Wells Fargo Bank, National Association, as Sydication
Agent, BNP Paribas, as Syndication Agent, Caylon, as
Documentation Agent, and Societe Generale, as
Documentation Agent. (incorporated by reference as
Exhibit 10.1 to the Swift Energy Company Quarterly
Report on Form 10-Q for the quarterly period ended
September 30, 2005, File No. 1-08754).
95
10.28 Second Amendment to First Amended and Restated Credit
Agreement effective as of December 28, 2005, by and
among Swift Energy Company and Swift Energy
Operating, LLC, and, J.P. Morgan Chase Bank, N.A., as
Administrative Agent, J.P. Morgan Securities, Inc. as
Sole Lead Arranger and Sole Book Runner, Wells Fargo
Bank, National Association, as Syndication Agent, BNP
PARIBAS, as Syndication Agent, Calyon as
Documentation Agent and Societe Generale as
Documentation Agent (incorporated by reference as
Exhibit 10.23 to Swift Energy Company's Annual Report
on Form 10-K for the fiscal year ended December 31,
2005, File No. 1-08754).
10.29* Third Amendment to First Amended and Restated Credit
Agreement effective as of October 2, 2006, by and
among Swift Energy Company and Swift Energy
Operating, LLC, and, J.P. Morgan Chase Bank, N.A., as
Administrative Agent, J.P. Morgan Securities, Inc. as
Sole Lead Arranger and Sole Book Runner, Wells Fargo
Bank, National Association, as Syndication Agent, BNP
PARIBAS, as Syndication Agent, Calyon as
Documentation Agent and Societe Generale as
Documentation Agent (incorporated by reference to
Swift Energy Company's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 2006,
File No. 1-08754).
10.30 Eighth Amendment to Lease Agreement between Swift
Energy Company and Greenspoint Plaza Limited
Partnership dated as of June 30, 2004 (incorporated
by reference as Exhibit 10.1 to the Swift Energy
Company Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 2004, File No.
1-08754).
10.31* Purchase and Sale Agreement dated as of August 24,
2006 but effective as of April 1, 2006, between Swift
Energy Operating, LLC and BP America Production
Company.
12* Swift Energy Company Ratio of Earnings to Fixed
Charges.
21 * List of Subsidiaries of Swift Energy Company.
23.1 * The consent of H.J. Gruy and Associates, Inc.
23.2 * Consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration
Statements.
31.1 * Certification of Chief Executive Officer pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 * Certification of Chief Financial Officer pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32 * Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1 * The summary of H.J. Gruy and Associates, Inc.
report, dated January 23, 2007.
--------------------------------------------------------------------------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
96
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By /s/ Terry E. Swift
------------------------------
Terry E. Swift
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant, Swift Energy Company, and in the capacities and on the dates
indicated:
Signatures Title Date
----------- ------ -----
Director
---------------------------- Chief Executive Officer February 28, 2007
Terry E. Swift
Executive Vice-President
---------------------------- Principal Financial Officer February 28, 2007
Alton D. Heckaman, Jr.
Controller
---------------------------- Principal Accounting Officer February 28, 2007
David W. Wesson
---------------------------- Director February 28, 2007
Deanna L. Cannon
---------------------------- Director February 28, 2007
Raymond E. Galvin
97
---------------------------- Director February 28, 2007
Douglas J. Lanier
---------------------------- Director February 28, 2007
Greg Matiuk
---------------------------- Director February 28, 2007
Henry C. Montgomery
---------------------------- Director February 28, 2007
Clyde W. Smith, Jr.
---------------------------- Director February 28, 2007
Charles J. Swindells
---------------------------- Director February 28, 2007
Bruce H. Vincent
98
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 2006
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
99
EXHIBIT INDEX
10.9 Form of Indemnity Agreement for Swift Energy Company
officers.
10.10 Form of Indemnity Agreement for Swift Energy Company
directors.
10.31 Purchase and Sale Agreement dated as of August 24,
2006 but effective as of April 1, 2006, between Swift
Energy Operating, LLC and BP America Production
Company.
12 Swift Energy Company Ratio of Earnings to Fixed
Charges.
21 List of Subsidiaries of Swift Energy Company.
23.1 The consent of H.J. Gruy and Associates, Inc.
23.2 Consent of Ernst & Young LLP as to incorporation by
reference regarding Forms S-8 and S-3 Registration
Statements.
31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2003.
31.2 Certification of Chief Financial Officer pursuant to
Section 3-2 of the Sarbanes-Oxley Act of 2002.
32 Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1 The summary of H.J. Gruy and Associates, Inc. report,
dated January 23, 2007.
100
Exhibit 10.9
SWIFT ENERGY COMPANY
INDEMNIFICATION AGREEMENT
THIS INDEMNIFICATION AGREEMENT (the "Agreement"), is made and entered into as of
__________________, by and between Swift Energy Company, a Texas corporation
(the "Company"), and __________________ (the "Indemnitee").
BACKGROUND
A. The Company is aware that, in order to induce highly competent persons to
serve or continue to serve the Company as officers or in other capacities, the
Company must provide such persons with adequate protection through insurance and
indemnification against risks of claims and actions against them arising out of
their service to and activities on behalf of the Company.
B. The Company has adopted bylaws (the "Bylaws") providing for indemnification
of the directors, officers, employees and other agents of the Company, including
persons serving at the request of the Company in these capacities with other
corporations or enterprises, to the full extent permitted under the applicable
law of the State of Texas, which is currently the Texas Business Corporation Act
(the "Act").
C. The Act expressly provides that the indemnification provided in the Bylaws is
not exclusive, and expressly permits contracts between the Company and its
directors, officers and employees and other agents with respect to
indemnification.
D. The Board of Directors of the Company (the "Board") has determined that (1)
it is essential to the best interests of the Company's shareholders that the
Company act to assure such persons that there will be increased certainty of
such protection in the future, and that (2) it is reasonable, prudent and
necessary for the Company contractually to obligate itself to indemnify and to
advance expenses to such persons to the fullest extent permitted by applicable
law, so that they will continue to serve the Company free from undue concern
that they will not be so indemnified.
E. The Indemnitee is willing to serve, continue to serve, or take on additional
service for or on behalf of the Company provided that he or she is furnished
with the indemnification set forth in this Agreement.
AGREEMENT
The parties hereto, intending to be legally bound, hereby agree as
follows:
1. Definitions. The following terms shall have the meanings referenced
below for purposes of this Agreement.
(a) "Agent" shall mean any person who is or was (i) an officer of the
Company, or (ii) at the request of, for the convenience of, or to
represent the interests of the Company, serving as a director, manager,
officer, trustee, general partner, member, venturer, fiduciary,
101
employee, other agent or similar functionary of a Subsidiary; or (iii)
at the request of, for the convenience of, or to represent the interest
of the Company or a Subsidiary of the Company, serving as a director,
manager, officer, trustee, general partner, member, venturer,
fiduciary, employee other agent of another corporation, limited
liability company, partnership, joint venture, trust, employee benefit
plan or other enterprise, in each case (i) whether or not the person
was serving in that capacity at the time any liability or expense is
incurred and (ii) whether the basis for any Proceeding brought against
the person is alleged action in an official capacity as a director,
manager, officer, trustee, general partner, member, venturer,
fiduciary, employee or agent or any other capacity while serving as a
director, manager, officer, trustee, general partner, member, venturer,
fiduciary, employee or other agent.
(b) "Expenses" means all out-of-pocket expenses or costs of any type or
nature whatsoever (including, without limitation, all court costs,
attorneys' fees and related disbursements and any deductibles that
Indemnitee might be required to pay under applicable insurance
policies), actually and reasonably incurred by the Indemnitee in
connection with the investigation with respect to, or the defense or
appeal of, a Proceeding, or establishing or enforcing a right to
indemnification under this Agreement or the Act or otherwise, but
excluding all judgments, fines, ERISA excise taxes or penalties, or
amounts paid in settlement of a Proceeding.
(c) "Proceeding" means any threatened, pending, or completed action, suit
or other proceeding, whether civil, criminal, administrative, or
investigative, any appeal in such an action, suit or proceeding, and
any inquiry or investigation that could lead to such an action, suit or
proceeding.
(d) "Subsidiary" means any foreign or domestic corporation, partnership,
limited liability company, employee benefit plan, other enterprise or
other entity of which more than fifty percent (50%) of the outstanding
voting securities or interests is owned directly or indirectly by the
Company.
2. Scope. Notwithstanding any other provision of this Agreement, the
Company hereby agrees to indemnify the Indemnitee to the fullest extent
permitted by law for the indemnification of directors, notwithstanding
that such indemnification is not specifically authorized by the other
provisions of this Agreement, the Articles of Incorporation, the Bylaws
or by statute.
3. Mandatory Indemnification. Subject to the limitations of Section 6 of
this Agreement:
(a) Indemnification for Expenses of a Party Who is Wholly or Partly
Successful.
(i) To the extent that the Indemnitee is, by reason of the fact
that he or she is or was an Agent, a party to and is
successful, on the merits or otherwise, in any Proceeding
102
(including an action by or in the right of the Company), the
Company shall indemnify the Indemnitee against all Expenses
actually and reasonably incurred by his or her or on his or
her behalf in connection therewith. If the Indemnitee is not
wholly successful in defense of any Proceeding but is
successful, on the merits or otherwise, as to one or more but
less than all claims, issues or matters in such Proceeding,
the Company shall indemnify the Indemnitee against all
Expenses actually and reasonably incurred by his or her or on
his or her behalf in connection with each such claim, issue or
matter as to which the Indemnitee is successful, on the merits
or otherwise. For purposes of this Section 3(a)(i), the term
"successful, on the merits or otherwise," shall include (A)
the termination of any claim, issue or matter in a Proceeding
by withdrawal or dismissal, with or without prejudice, (B)
termination of any claim, issue or matter in a Proceeding by
any other means without any express finding of liability or
guilt against the Indemnitee, with or without prejudice, (C)
the expiration of 120 days after the making of a claim or
threat of a Proceeding without the institution of the same and
without any promise or payment made to induce a settlement or
(D) the settlement of any claim, issue or matter in a
Proceeding pursuant to which the Indemnitee pays less than
$100,000.
(ii) In no event shall the Indemnitee be entitled to
indemnification under Section 3(a)(i) above with respect to a
claim, issue or matter to the extent (A) applicable law
prohibits the indemnification, or (B) an admission is made by
the Indemnitee in writing to the Company or in such Proceeding
or a determination is made by a court of competent
jurisdiction from which all appeals have been exhausted that
the standard of conduct required for indemnification under
this Agreement has not been met with respect to such claim,
issue or matter.
(b) Third-Party Actions. If the Indemnitee was or is a party or is
threatened to be made a party to any Proceeding (other than a
proceeding brought by or in the right of the Company) by reason of the
fact that he or she is or was an Agent, or by reason of anything done
or not done by him or her in any such capacity, then the Company shall
indemnify the Indemnitee against any and all Expenses and any
judgments, fines, ERISA excise taxes and penalties, and amounts paid in
settlement in connection with the investigation, defense, settlement or
appeal of such Proceeding, unless the Indemnitee: (i) did not conduct
himself or herself in good faith; (ii) did not reasonably believe: (A)
in the case of conduct in his or her official capacity as an officer of
the Company, that his or her conduct was in the Company's best
interests; and (B) in all other cases, that his or her conduct was at
least not opposed to the Company's best interests; or (iii) in the case
of any criminal proceeding, had no reasonable cause to believe his or
her conduct was unlawful. The termination of any Proceeding by
judgment, order, settlement or conviction, or upon a plea of nolo
contendere or its equivalent, shall not, of itself, create a
presumption that Indemnitee did not satisfy the foregoing standard of
conduct to the extent applicable thereto. A person shall be deemed to
have been found liable in respect of any claim, issue or matter only
103
after the person shall have been so adjudged by a court of competent
jurisdiction after exhaustion of all appeals therefrom.
(c) Derivative Actions. If the Indemnitee was or is a party or is
threatened to be made a party to any Proceeding in a derivative action
by or in the right of the Company, because he or she is or was an
Agent, or because of anything done or not done by him or her in any
such capacity, then the Company shall indemnify the Indemnitee against
all Expenses, as well as any judgments, fines, ERISA excise taxes and
penalties, and amounts paid in settlement in connection with the
investigation, defense, settlement or appeal of such Proceeding, unless
the Indemnitee: (i) did not conduct himself or herself in good faith;
(ii) did not reasonably believe: (A) in the case of conduct in his or
her official capacity as an officer of the Company, that his or her
conduct was in the Company's best interests; and (B) in all other
cases, that his or her conduct was at least not opposed to the
Company's best interests; or (iii) in the case of any criminal
proceeding, had no reasonable cause to believe his or her conduct was
unlawful. The termination of any Proceeding by judgment, order,
settlement or conviction, or upon a plea of nolo contendere or its
equivalent, shall not, of itself, create a presumption that Indemnitee
did not satisfy the foregoing standard of conduct to the extent
applicable thereto. A person shall be deemed to have been found liable
in respect of any claim, issue or matter only after the person shall
have been so adjudged by a court of competent jurisdiction after
exhaustion of all appeals therefrom.
(d) Actions where Indemnitee is Deceased. If the Indemnitee was or is a
party or is threatened to be made a party to any Proceeding because he
or she is or was an Agent, or because of anything done or not done by
him or her in any such capacity, and if prior to, during the pendency
of or after completion of such Proceeding, Indemnitee dies, then the
Company shall indemnify the Indemnitee's heirs, devisees, executors and
administrators against any and all Expenses, and any judgments, fines,
ERISA excise taxes and penalties, and amounts paid in settlement in
connection with the investigation, defense, settlement or appeal of
such Proceeding, to the extent Indemnitee would have been entitled to
indemnification pursuant to Sections 3(a), 3(b), or 3(c) of this
Agreement if the Indemnitee was still alive.
4. Partial Indemnification and Contribution.
(a) Partial Indemnification. If the Indemnitee is entitled under any
provision of this Agreement to indemnification by the Company for some
or a portion of any Expenses or other liabilities of any type
whatsoever (including, but not limited to, judgments, fines, ERISA
excise taxes and penalties, and amounts paid in settlement) incurred by
him or her in the investigation, defense, settlement or appeal of a
Proceeding, but not entitled to indemnification for all of the total
amount hereof, the Company shall indemnify the Indemnitee for such
total amount less that portion to which the Indemnitee is not entitled.
104
(b) Contribution. If the indemnification provided in Section 3 is
unavailable and may not be paid to Indemnitee for any reason, then in
respect to any Proceeding in which the Company and all officers,
directors and employees of the Company other than the Indemnitee are
jointly liable with Indemnitee (or would be if joined in such
Proceeding), the Company shall contribute to the amount of Expenses and
other liabilities of any type whatsoever (including, but not limited
to, judgments, fines, ERISA excise taxes and penalties, and amounts
paid in settlement) in connection with the investigation, defense,
settlement or appeal of such Proceeding, in such proportion as is
appropriate to reflect the relative benefits received by the Company
and all officers, directors and employees of the Company other than the
Indemnitee, who are jointly liable with the Indemnitee (or would be if
joined in such Proceeding), on the one hand, and the Indemnitee, on the
other hand, from the transaction from which such Proceeding arose. The
proportion determined on the basis of relative benefit may, to the
extent necessary to conform to law, be further adjusted to reflect the
relative fault of the Company and all officers, directors and employees
of the Company other than the Indemnitee who are jointly liable with
the Indemnitee (or would be if joined in such Proceeding), on the one
hand, and of Indemnitee, on the other hand, in connection with the
events that resulted in such Expenses or other liabilities of any type
whatsoever (including, but not limited to, judgments, fines, ERISA
excise taxes and penalties, and amounts paid in settlement) in
connection with the investigation, defense, settlement or appeal of
such Proceeding, as well as any other relevant equitable
considerations. The relative fault of the Company and all officers,
directors and employees of the Company other than the Indemnitee who
are jointly liable with the Indemnitee (or would be if joined in such
Proceeding), on the one hand, and of Indemnitee, on the other hand,
shall be determined by reference to, among other things, the parties'
relative intent, knowledge, access to information and opportunity to
correct or prevent the circumstances resulting in such Expenses,
judgments, fines or settlement amounts. The Company agrees that it
would not be just and equitable if contribution pursuant to this
Section 4(b) were determined by pro rata allocation or any other method
of allocation that does not take account of the foregoing equitable
considerations.
5. Mandatory Advancement of Expenses.
(a) Subject to the provisions of Section 7 of this Agreement, the Company
shall advance all Expenses incurred by the Indemnitee in connection
with the investigation, defense, settlement or appeal of any Proceeding
to which the Indemnitee is a party or is threatened to be made a party
by reason of the fact that the Indemnitee is or was an Agent; provided,
however, that if Indemnitee is at that time an officer of the Company,
prior to the advancement of Expenses to the Indemnitee in connection
with the Proceeding, the Indemnitee shall provide the Company with a
written affirmation by the Indemnitee of his or her good faith belief
that he or she has met the standard of conduct necessary for
indemnification stated in the relevant provision of Section 3 of this
Agreement, together with a written undertaking to repay the amount paid
or reimbursed if it is ultimately determined that the Indemnitee has
105
not met the standard of conduct necessary for indemnification or if it
is ultimately determined that indemnification of the Indemnitee against
Expenses incurred by him or her in connection with the Proceeding would
have been prohibited by Section E of Article 2.02-1 of the Act if
Indemnitee is treated as if he or she were serving as a director of the
Company. The advances to be made hereunder shall be paid from time to
time by the Company to the Indemnitee within thirty (30) days following
delivery of a written request therefor by the Indemnitee to the
Company, together with reasonable evidence of such Expenses. Any
advances and undertakings to repay pursuant to this Section 5 shall not
be secured, shall not bear interest and shall provide that, if
Indemnitee has commenced or thereafter commences legal proceedings in a
court of competent jurisdiction to secure a determination that
Indemnitee should be indemnified under applicable law with respect to
such Proceeding, Indemnitee shall not be required to reimburse the
Company for any advancement of Expenses in respect of such Proceeding
until so determined by a court of competent jurisdiction after
exhaustion of all appeals therefrom.
(b) Subject to the provisions of Section 7(c) and 7(d) of this Agreement,
the Company shall advance all Expenses incurred by the Indemnitee in
connection with the Indemnitee's appearance as a witness in, or in
responding to a subpoena to testify or serve as a witness in or in
connection with, a Proceeding in which the Indemnitee is not named as a
defendant or respondent.
6. Defense of the Underlying Proceeding.
(a) Indemnitee shall notify the Company promptly upon being served with or
receiving any summons, citation, subpoena, complaint, indictment,
information, notice, request or other document relating to any
Proceeding which may result in the right to indemnification or the
advance of Expenses hereunder; provided, however, that the failure to
give any such notice shall not disqualify Indemnitee from the right, or
otherwise affect in any manner any right of Indemnitee, to
indemnification or the advance of Expenses under this Agreement unless
the Company's ability to defend in such Proceeding or to obtain
proceeds under any insurance policy is materially and adversely
prejudiced thereby, and then only to the extent the Company is thereby
actually so prejudiced.(b) If, at the time of the receipt of a notice
of the commencement of a Proceeding pursuant to Section 6(a) hereof,
the Company has a directors' and officers' liability insurance policy
in effect, the Company shall give prompt notice of the commencement of
such Proceeding to the insurers in accordance with the procedures set
forth in the respective policies. The Company shall thereafter take all
necessary or desirable action to cause such insurers to pay, on behalf
of the Indemnitee, all amounts payable as a result of such Proceeding
in accordance with the terms of such policies.
(b) Subject to the provisions of the last sentence of this Section 6(c) and
of Section 6(d) below, the Company shall have the right to defend
Indemnitee in any Proceeding which may give rise to indemnification
106
hereunder with counsel approved by Indemnitee, which approval shall not
be unreasonably withheld; provided, however, that the Company shall
notify Indemnitee of any such decision to defend within 15 calendar
days following receipt of notice of any such Proceeding under Section
6(a) above. The Company shall not, without the prior written consent of
Indemnitee, which shall not be unreasonably withheld or delayed,
consent to the entry of any judgment against Indemnitee or enter into
any settlement or compromise which (i) includes an admission of fault
of Indemnitee or (ii) does not include, as an unconditional term
thereof, the full release of Indemnitee from all liability in respect
of such Proceeding, which release shall be in form and substance
reasonably satisfactory to Indemnitee. This Section 6 shall not apply
to a Proceeding brought by Indemnitee under Section 9.
(c) Notwithstanding the provisions of Section 6(c) above, if in a
Proceeding for which the Company has notified Indemnitee that it
intends to defend Indemnitee, (i) Indemnitee reasonably concludes,
based upon an opinion of counsel approved by the Company, which
approval shall not be unreasonably withheld, that he or she may have
separate defenses or counterclaims to assert with respect to any issue
which may not be consistent with other defendants in such Proceeding,
(ii) Indemnitee reasonably concludes, based upon an opinion of counsel
approved by the Company, which approval shall not be unreasonably
withheld, that an actual or apparent conflict of interest or potential
conflict of interest exists between Indemnitee and the Company, or
(iii) if the Company fails to assume the defense of such Proceeding in
a timely manner, Indemnitee shall be entitled to be represented by
separate legal counsel of Indemnitee's choice, subject to the prior
approval of the Company, which shall not be unreasonably withheld, at
the expense of the Company. In addition, if the Company fails to comply
with any of its obligations under this Agreement or in the event that
the Company or any other person takes any action to declare this
Agreement void or unenforceable, or institutes any Proceeding to deny
or to recover from Indemnitee the benefits intended to be provided to
Indemnitee hereunder, Indemnitee shall have the right to retain counsel
of Indemnitee's choice, subject to the prior approval of the Company,
which shall not be unreasonably withheld, at the expense of the
Company, to represent Indemnitee in connection with any such matter.
7. Exceptions. Any other provision herein to the contrary notwithstanding,
the Company shall not be obligated pursuant to the terms of this
Agreement:
(a) Claims Initiated by Indemnitee. To advance to the Indemnitee Expenses
or indemnify Expenses or any other liabilities of any type whatsoever
(including, but not limited to, judgments, fines, ERISA excise taxes
and penalties, and amounts paid in settlement) with respect to
Proceedings or claims initiated or brought voluntarily by the
Indemnitee and not by way of defense, unless:
(i) such indemnification is expressly required to be made by law;
107
(ii) the Proceeding was authorized by the Board;
(iii) such indemnification is provided by the Company, in its sole
discretion, pursuant to the powers vested in the Company under
the Act or the Bylaws; or
(iv) a counterclaim or cross claim is asserted against Indemnitee
for which Indemnitee otherwise would be entitled to indemnity
by Company.
(b) Lack of Good Faith. To indemnify the Indemnitee for any Expenses or any
other liabilities of any type whatsoever (including, but not limited
to, judgments, fines, ERISA excise taxes and penalties, and amounts
paid in settlement) incurred by the Indemnitee (i) with respect to any
Proceeding instituted by the Indemnitee to enforce or interpret this
Agreement, if a court of competent jurisdiction determines that each of
the material assertions made by the Indemnitee in such Proceeding was
not made in good faith or was frivolous, or (ii) with respect to any
Proceeding if the Indemnitee is found liable by a court of competent
jurisdiction after exhaustion of all appeals for willful or intentional
misconduct in the performance of his or her duty to the Company;
(c) Unauthorized Settlements. To indemnify the Indemnitee under this
Agreement for any amounts paid in settlement of a Proceeding unless the
Company consents to such settlement, which consent shall not be
unreasonably withheld; or
(d) No Duplication of Payments. To indemnify the Indemnitee for Expenses or
liabilities of any type whatsoever (including, but not limited to,
judgments, fines, ERISA excise taxes and penalties, and amounts paid in
settlement) for which payment is actually made to Indemnitee under a
valid and collectible directors' and officers' liability insurance
policy, or under a valid and enforceable indemnity clause of the Bylaws
or other agreement.
8. Non-exclusivity. The provisions for advancement of Expenses and
indemnification of Expenses and any judgments, fines, ERISA excise
taxes and amounts paid in settlement set forth in this Agreement shall
not be deemed exclusive of any other rights which the Indemnitee may
have under any provision of law, the Company's Articles of
Incorporation, as amended and restated from time to time, or Bylaws,
the vote of the Company's shareholders or disinterested directors, any
employment agreement between the Company and Indemnitee, other
agreements, or otherwise, both as to action in his or her official
capacity and to action in another capacity while occupying his or her
position as an Agent.
9. Remedies of Indemnitee.
(a) If (i) a determination is made that Indemnitee is not entitled to
indemnification under this Agreement, (ii) advance of Expenses is not
timely made pursuant to Section 5 of this Agreement, or (iii) payment
of indemnification is not made pursuant to Section 3 of this Agreement
within 30 days after receipt by the Company of a written request
108
therefor, Indemnitee shall be entitled to an adjudication in an
appropriate court located in the State of Texas, or in any other court
of competent jurisdiction, of his or her entitlement to such
indemnification or advance of Expenses.
(b) In any judicial proceeding commenced pursuant to this Section 9 the
Company shall have the burden of proving that Indemnitee is not
entitled to indemnification or advance of Expenses, as the case may be.
(c) If a determination shall have been made that Indemnitee is entitled to
indemnification, the Company shall be bound by such determination in
any judicial proceeding commenced pursuant to this Section 9, absent a
misstatement by Indemnitee of a material fact, or an omission of a
material fact necessary to make Indemnitee's statement not materially
misleading, in connection with the request for indemnification.
(d) In the event that Indemnitee, pursuant to this Section 9, seeks a
judicial adjudication to enforce his or her rights under, or to recover
damages for breach of, this Agreement, Indemnitee, if successful in
such enforcement action in whole or in part, shall be entitled to
recover from the Company, and shall be indemnified by the Company for,
any and all Expenses actually and reasonably incurred by him or her in
such judicial adjudication or arbitration, including any claim or
counterclaim brought by the Company in connection therewith. If it
shall be determined in such judicial adjudication or arbitration that
Indemnitee is entitled to receive part but not all of the
indemnification or advance of Expenses sought, the Expenses incurred by
Indemnitee in connection with such judicial adjudication or arbitration
shall be appropriately prorated.
(e) The Company shall be precluded from asserting in any Proceeding,
including, without limitation, an action under Section 9(a) above, that
the provisions of this Agreement are not valid, binding and enforceable
or that there is insufficient consideration for this Agreement and
shall stipulate in court that the Company is bound by all the
provisions of this Agreement.
(f) The failure of the Company (including its Board of Directors or any
committee thereof, independent legal counsel, or shareholders) to make
a determination concerning the permissibility of the payment of
indemnifiable amounts or the advance of Expenses under this Agreement
shall not be a defense in any action brought under Section 9(a) above,
and shall not create a presumption that such payment or advance is not
permissible.
10. Determination of "Good Faith".
(a) For purposes of any determination of "good faith" under this Agreement,
the Indemnitee shall be deemed to have acted in good faith if in taking
such action the Indemnitee relied on the records or books of account of
the Company or a Subsidiary or affiliate of the Company, including
109
financial statements, or on information, opinions, reports or
statements provided to the Indemnitee by the officers or other
employees of the Company or a Subsidiary or affiliate of the Company in
the course of their duties, or on the advice of legal counsel for the
Company or a Subsidiary or affiliate of the Company, or on information
or records given or reports made to the Company or a Subsidiary or
affiliate of the Company by an independent certified public accountant
or by an appraiser or other expert selected by the Company or a
Subsidiary or affiliate of the Company, or by any other person
(including legal counsel, accountants and financial advisors) as to
matters the Indemnitee reasonably believes are within such other
person's professional or expert competence and who has been selected
with reasonable care by or on behalf of the Company. In connection with
any determination as to whether the Indemnitee is entitled to be
indemnified under this Agreement, the person or court making the
determination shall presume that the Indemnitee has satisfied the
applicable standard of conduct and shall be entitled to
indemnification, and the burden of proof shall be on the Company to
establish that the Indemnitee is not so entitled. The provisions of
this Section 9 shall not be deemed to be exclusive or to limit in any
way the other circumstances in which the Indemnitee may be deemed to
have met the applicable standard of conduct set forth in this
Agreement. In addition, the knowledge and/or actions, or failures to
act, of any other person serving the Company or a Subsidiary or
affiliate of the Company as an indemnifiable person shall not be
imputed to the Indemnitee for purposes of determining the right to
indemnification under this Agreement.
(b) The determination as to whether an Indemnitee has met the applicable
standard of conduct set forth in Section 3 hereof shall be made in
accordance with Section F. of Article 2.02-1 of the Act. If for
purposes of making such determination there are no directors who at the
time are not named defendants or respondents in the Proceeding for
which indemnification or reimbursement is sought, then such
determination may be made by independent legal counsel (who may be the
outside counsel regularly employed by the Company) in a written
opinion.
11. Subrogation. If payment is made under this Agreement, the Company shall
be subrogated to the extent of such payment to all of the rights of
recovery of Indemnitee from any third parties, the Indemnitee shall
execute all documents reasonably required and shall do all acts that
may be reasonably necessary to secure such rights and to enable the
Company to effectively bring suit to enforce such rights.
12. Continuation of Obligations.
(a) After Service as an Agent. All agreements and obligations of the
Company contained herein shall continue during the period Indemnitee is
an Agent and shall continue thereafter so long as Indemnitee shall be
subject to any possible Proceeding, by reason of the fact that
Indemnitee was serving in the capacity referred to herein.
110
(b) Successors and Assigns. This Agreement shall be binding upon and inure
to the benefit of and be enforceable by the parties hereto and their
respective successors, assigns (including any direct or indirect
successor by merger, consolidation, or otherwise to all or
substantially all of the business or assets of the Corporation), and
personal and legal representatives. The Company shall require any such
successor to the Company to expressly to assume and agree to perform
this Agreement in the same manner and to the same extent that the
Company would be required to perform if no such succession had taken
place.
13. Severability. If any provision or provisions of this Agreement shall be
held to be invalid, illegal or unenforceable for any reason whatsoever,
then:
(a) the validity, legality and enforceability of the remaining provisions
of the Agreement (including, without limitation, all portions of any
paragraphs of this Agreement containing any such provision held to be
invalid, illegal or unenforceable, that are not themselves invalid,
illegal or unenforceable) shall not in any way be affected or impaired
thereby; and
(b) to the fullest extent possible, the provisions of this Agreement
(including, without limitation, all portions of any provision of this
Agreement containing any such provision held to be invalid, illegal or
unenforceable, that are not themselves invalid, illegal or
unenforceable) shall be construed so as to give effect to the intent
manifested by the provision held invalid, illegal or unenforceable and
to give effect to Section 11 hereof.
14. Modification and Waiver. No supplement, modification or amendment of
this Agreement shall be binding unless executed in writing by the
parties hereto. No waiver of any provision of this Agreement shall be
deemed or shall constitute a waiver of any other provision hereof
(whether or not similar) nor shall such waiver constitute a continuing
waiver.
15. Notices. All notices, consents, waivers and other communications under
this Agreement must be in writing and will be deemed to have been duly
given when:
(a) delivered by hand (with written confirmation of receipt);
(b) sent by facsimile (with written confirmation of receipt), provided that
a copy is also promptly mailed by registered mail, return receipt
requested; or
(c) when received by the addressee, if sent by a nationally recognized
overnight delivery service (receipt requested),
in each case to the appropriate addresses and facsimile numbers set forth on the
signature page hereof, as the case may be (or to such other addresses and
facsimile numbers as a party may designate by notice to the other party).
111
16. Governing Law. This Agreement shall be governed exclusively by and construed
according to the laws of the State of Texas as applied to contracts between
Texas residents entered into and to be performed entirely within Texas without
giving effect to any conflict of laws provisions.
17. Consent to Jurisdiction. The Company and the Indemnitee each hereby
irrevocably consent to the jurisdiction of the state or federal courts in Harris
County, Texas and venue in Harris County, Texas with respect to any Proceeding
that arises out of or relates to this Agreement.
COMPANY:
SWIFT ENERGY COMPANY
By:
----------------------------------------
Terry E. Swift, Chief Executive Officer
Address: 16825 Northchase Dr., Suite 400
Houston, Texas 77060
281-874-2808 (facsimile no.)
INDEMNITEE:
----------------------------------------------
Name:
Address:
112
Exhibit 10.10
SWIFT ENERGY COMPANY
INDEMNIFICATION AGREEMENT
THIS INDEMNIFICATION AGREEMENT (the "Agreement"), is made and entered into as of
__________________, by and between Swift Energy Company, a Texas corporation
(the "Company"), and ______________ (the "Indemnitee").
BACKGROUND
A. The Company is aware that, in order to induce highly competent persons to
serve or continue to serve the Company as directors or in other capacities, the
Company must provide such persons with adequate protection through insurance and
indemnification against risks of claims and actions against them arising out of
their service to and activities on behalf of the Company.
B. The Company has adopted bylaws (the "Bylaws") providing for indemnification
of the directors, officers, employees and other agents of the Company, including
persons serving at the request of the Company in these capacities with other
corporations or enterprises, to the full extent permitted under the applicable
law of the State of Texas, which is currently the Texas Business Corporation Act
(the "Act").
C. The Act expressly provides that the indemnification provided in the Bylaws is
not exclusive, and expressly permits contracts between the Company and its
directors, officers and employees and other agents with respect to
indemnification.
D. The Board of Directors of the Company (the "Board") has determined that (1)
it is essential to the best interests of the Company's shareholders that the
Company act to assure such persons that there will be increased certainty of
such protection in the future, and that (2) it is reasonable, prudent and
necessary for the Company contractually to obligate itself to indemnify and to
advance expenses to such persons to the fullest extent permitted by applicable
law, so that they will continue to serve the Company free from undue concern
that they will not be so indemnified.
E. The Indemnitee is willing to serve, continue to serve, or take on additional
service for or on behalf of the Company provided that he or she is furnished
with the indemnification set forth in this Agreement.
AGREEMENT
The parties hereto, intending to be legally bound, hereby agree as
follows:
1. Definitions. The following terms shall have the meanings referenced
below for purposes of this Agreement.
(a) "Agent" shall mean any person who is or was (i) a director, manager,
officer, trustee, general partner, member, venturer, fiduciary,
employee, other agent or similar functionary; or (ii) at the request
of, for the convenience of, or to represent the interests of the
113
Company, serving as a director, manager, officer, trustee, general
partner, member, venturer, fiduciary, employee, other agent or similar
functionary of a Subsidiary; or (iii) at the request of, for the
convenience of, or to represent the interest of the Company or a
Subsidiary of the Company, serving as a director, manager, officer,
trustee, general partner, member, venturer, fiduciary, employee other
agent of another corporation, limited liability company, partnership,
joint venture, trust, employee benefit plan or other enterprise, in
each case (i) whether or not the person was serving in that capacity at
the time any liability or expense is incurred and (ii) whether the
basis for any Proceeding brought against the person is alleged action
in an official capacity as a director, manager, officer, trustee,
general partner, member, venturer, fiduciary, employee or agent or any
other capacity while serving as a director, manager, officer, trustee,
general partner, member, venturer, fiduciary, employee or other agent.
(b) "Expenses" means all out-of-pocket expenses or costs of any type or
nature whatsoever (including, without limitation, all court costs,
attorneys' fees and related disbursements and any deductibles that
Indemnitee might be required to pay under applicable insurance
policies), actually and reasonably incurred by the Indemnitee in
connection with the investigation with respect to, or the defense or
appeal of, a Proceeding, or establishing or enforcing a right to
indemnification under this Agreement or the Act or otherwise, but
excluding all judgments, fines, ERISA excise taxes or penalties, or
amounts paid in settlement of a Proceeding.
(c) "Proceeding" means any threatened, pending, or completed action, suit
or other proceeding, whether civil, criminal, administrative, or
investigative, any appeal in such an action, suit or proceeding, and
any inquiry or investigation that could lead to such an action, suit or
proceeding.
(d) "Subsidiary" means any foreign or domestic corporation, partnership,
limited liability company, employee benefit plan, other enterprise or
other entity of which more than fifty percent (50%) of the outstanding
voting securities or interests is owned directly or indirectly by the
Company.
2. Scope. Notwithstanding any other provision of this Agreement, the
Company hereby agrees to indemnify the Indemnitee to the fullest extent
permitted by law, notwithstanding that such indemnification is not
specifically authorized by the other provisions of this Agreement, the
Articles of Incorporation, the Bylaws or by statute. If after the date
of this Agreement, there is a change in any applicable law, statute, or
rule which expands the right of a Texas corporation to indemnify a
member of its board of directors then such changes shall be, ipso
facto, within the purview of Indemnitee's rights and Company's
obligations under this Agreement.
114
3. Mandatory Indemnification. Subject to the limitations of Section 6 of
this Agreement:
(a) Indemnification for Expenses of a Party Who is Wholly or Partly
Successful.
(i) To the extent that the Indemnitee is, by reason of the fact
that he or she is or was an Agent, a party to and is
successful, on the merits or otherwise, in any Proceeding
(including an action by or in the right of the Company), the
Company shall indemnify the Indemnitee against all Expenses
actually and reasonably incurred by his or her or on his or
her behalf in connection therewith. If the Indemnitee is not
wholly successful in defense of any Proceeding but is
successful, on the merits or otherwise, as to one or more but
less than all claims, issues or matters in such Proceeding,
the Company shall indemnify the Indemnitee against all
Expenses actually and reasonably incurred by his or her or on
his or her behalf in connection with each such claim, issue or
matter as to which the Indemnitee is successful, on the merits
or otherwise. For purposes of this Section 3(a)(i), the term
"successful, on the merits or otherwise," shall include (A)
the termination of any claim, issue or matter in a Proceeding
by withdrawal or dismissal, with or without prejudice, (B)
termination of any claim, issue or matter in a Proceeding by
any other means without any express finding of liability or
guilt against the Indemnitee, with or without prejudice, (C)
the expiration of 120 days after the making of a claim or
threat of a Proceeding without the institution of the same and
without any promise or payment made to induce a settlement or
(D) the settlement of any claim, issue or matter in a
Proceeding pursuant to which the Indemnitee pays less than
$100,000.
(ii) In no event shall the Indemnitee be entitled to
indemnification under Section 3(a)(i) above with respect to a
claim, issue or matter to the extent (A) applicable law
prohibits the indemnification, or (B) an admission is made by
the Indemnitee in writing to the Company or in such Proceeding
or a determination is made by a court of competent
jurisdiction from which all appeals have been exhausted that
the standard of conduct required for indemnification under
this Agreement has not been met with respect to such claim,
issue or matter.
(b) Third-Party Actions. If the Indemnitee was or is a party or is
threatened to be made a party to any Proceeding (other than a
proceeding brought by or in the right of the Company) by reason of the
fact that he or she is or was an Agent, or by reason of anything done
or not done by him or her in any such capacity, then the Company shall
indemnify the Indemnitee against any and all Expenses and any
115
judgments, fines, ERISA excise taxes and penalties, and amounts paid in
settlement in connection with the investigation, defense, settlement or
appeal of such Proceeding, unless the Indemnitee: (i) did not conduct
himself or herself in good faith; (ii) did not reasonably believe: (A)
in the case of conduct in his or her official capacity as a director of
the Company, that his or her conduct was in the Company's best
interests; and (B) in all other cases, that his or her conduct was at
least not opposed to the Company's best interests; or (iii) in the case
of any criminal proceeding, had no reasonable cause to believe his or
her conduct was unlawful. The termination of any Proceeding by
judgment, order, settlement or conviction, or upon a plea of nolo
contendere or its equivalent, shall not, of itself, create a
presumption that Indemnitee did not satisfy the foregoing standard of
conduct to the extent applicable thereto. A person shall be deemed to
have been found liable in respect of any claim, issue or matter only
after the person shall have been so adjudged by a court of competent
jurisdiction after exhaustion of all appeals therefrom.
(c) Derivative Actions. If the Indemnitee was or is a party or is
threatened to be made a party to any Proceeding in a derivative action
by or in the right of the Company, because he or she is or was an
Agent, or because of anything done or not done by him or her in any
such capacity, then the Company shall indemnify the Indemnitee against
all Expenses, as well as any judgments, fines, ERISA excise taxes and
penalties, and amounts paid in settlement in connection with the
investigation, defense, settlement or appeal of such Proceeding, unless
the Indemnitee: (i) did not conduct himself or herself in good faith;
(ii) did not reasonably believe: (A) in the case of conduct in his or
her official capacity as a director of the Company, that his or her
conduct was in the Company's best interests; and (B) in all other
cases, that his or her conduct was at least not opposed to the
Company's best interests; or (iii) in the case of any criminal
proceeding, had no reasonable cause to believe his or her conduct was
unlawful. The termination of any Proceeding by judgment, order,
settlement or conviction, or upon a plea of nolo contendere or its
equivalent, shall not, of itself, create a presumption that Indemnitee
did not satisfy the foregoing standard of conduct to the extent
applicable thereto. A person shall be deemed to have been found liable
in respect of any claim, issue or matter only after the person shall
have been so adjudged by a court of competent jurisdiction after
exhaustion of all appeals therefrom.
(d) Actions where Indemnitee is Deceased. If the Indemnitee was or is a
party or is threatened to be made a party to any Proceeding because he
or she is or was an Agent, or because of anything done or not done by
him or her in any such capacity, and if prior to, during the pendency
of or after completion of such Proceeding, Indemnitee dies, then the
Company shall indemnify the Indemnitee's heirs, devisees, executors and
administrators against any and all Expenses, and any judgments, fines,
ERISA excise taxes and penalties, and amounts paid in settlement in
connection with the investigation, defense, settlement or appeal of
such Proceeding, to the extent Indemnitee would have been entitled to
indemnification pursuant to Sections 3(a), 3(b), or 3(c) of this
Agreement if the Indemnitee was still alive.
116
4. Partial Indemnification and Contribution.
(a) Partial Indemnification. If the Indemnitee is entitled under any
provision of this Agreement to indemnification by the Company for some
or a portion of any Expenses or other liabilities of any type
whatsoever (including, but not limited to, judgments, fines, ERISA
excise taxes and penalties, and amounts paid in settlement) incurred by
him or her in the investigation, defense, settlement or appeal of a
Proceeding, but not entitled to indemnification for all of the total
amount hereof, the Company shall indemnify the Indemnitee for such
total amount less that portion to which the Indemnitee is not entitled.
(b) Contribution. If the indemnification provided in Section 3 is
unavailable and may not be paid to Indemnitee for any reason, then in
respect to any Proceeding in which the Company and all officers,
directors and employees of the Company other than the Indemnitee are
jointly liable with Indemnitee (or would be if joined in such
Proceeding), the Company shall contribute to the amount of Expenses and
other liabilities of any type whatsoever (including, but not limited
to, judgments, fines, ERISA excise taxes and penalties, and amounts
paid in settlement) in connection with the investigation, defense,
settlement or appeal of such Proceeding, in such proportion as is
appropriate to reflect the relative benefits received by the Company
and all officers, directors and employees of the Company other than the
Indemnitee, who are jointly liable with the Indemnitee (or would be if
joined in such Proceeding), on the one hand, and the Indemnitee, on the
other hand, from the transaction from which such Proceeding arose. The
proportion determined on the basis of relative benefit may, to the
extent necessary to conform to law, be further adjusted to reflect the
relative fault of the Company and all officers, directors and employees
of the Company other than the Indemnitee who are jointly liable with
the Indemnitee (or would be if joined in such Proceeding), on the one
hand, and of Indemnitee, on the other hand, in connection with the
events that resulted in such Expenses or other liabilities of any type
whatsoever (including, but not limited to, judgments, fines, ERISA
excise taxes and penalties, and amounts paid in settlement) in
connection with the investigation, defense, settlement or appeal of
such Proceeding, as well as any other relevant equitable
considerations. The relative fault of the Company and all officers,
directors and employees of the Company other than the Indemnitee who
are jointly liable with the Indemnitee (or would be if joined in such
Proceeding), on the one hand, and of Indemnitee, on the other hand,
shall be determined by reference to, among other things, the parties'
relative intent, knowledge, access to information and opportunity to
correct or prevent the circumstances resulting in such Expenses,
judgments, fines or settlement amounts. The Company agrees that it
would not be just and equitable if contribution pursuant to this
Section 4(b) were determined by pro rata allocation or any other method
of allocation that does not take account of the foregoing equitable
considerations.
117
5. Mandatory Advancement of Expenses.
(a) Subject to the provisions of Section 7 of this Agreement, the Company
shall advance all Expenses incurred by the Indemnitee in connection
with the investigation, defense, settlement or appeal of any Proceeding
to which the Indemnitee is a party or is threatened to be made a party
by reason of the fact that the Indemnitee is or was an Agent; provided,
however, that if Indemnitee is at that time a director of the Company,
prior to the advancement of Expenses to the Indemnitee in connection
with the Proceeding, the Indemnitee shall provide the Company with a
written affirmation by the Indemnitee of his or her good faith belief
that he or she has met the standard of conduct necessary for
indemnification stated in the relevant provision of Section 3 of this
Agreement, together with a written undertaking to repay the amount paid
or reimbursed if it is ultimately determined that the Indemnitee has
not met the standard of conduct necessary for indemnification or if it
is ultimately determined that indemnification of the Indemnitee against
Expenses incurred by him or her in connection with the Proceeding is
prohibited by Section E of Article 2.02-1 of the Act. The advances to
be made hereunder shall be paid from time to time by the Company to the
Indemnitee within thirty (30) days following delivery of a written
request therefor by the Indemnitee to the Company, together with
reasonable evidence of such Expenses. Any advances and undertakings to
repay pursuant to this Section 5 shall not be secured, shall not bear
interest and shall provide that, if Indemnitee has commenced or
thereafter commences legal proceedings in a court of competent
jurisdiction to secure a determination that Indemnitee should be
indemnified under applicable law with respect to such Proceeding,
Indemnitee shall not be required to reimburse the Company for any
advancement of Expenses in respect of such Proceeding until so
determined by a court of competent jurisdiction after exhaustion of all
appeals therefrom.
(b) Subject to the provisions of Section 7(c) and 7(d) of this Agreement,
the Company shall advance all Expenses incurred by the Indemnitee in
connection with the Indemnitee's appearance as a witness in, or in
responding to a subpoena to testify or serve as a witness in or in
connection with, a Proceeding in which the Indemnitee is not named as a
defendant or respondent.
6. Defense of the Underlying Proceeding.
(a) Indemnitee shall notify the Company promptly upon being served with or
receiving any summons, citation, subpoena, complaint, indictment,
information, notice, request or other document relating to any
Proceeding which may result in the right to indemnification or the
advance of Expenses hereunder; provided, however, that the failure to
give any such notice shall not disqualify Indemnitee from the right, or
otherwise affect in any manner any right of Indemnitee, to
indemnification or the advance of Expenses under this Agreement unless
the Company's ability to defend in such Proceeding or to obtain
proceeds under any insurance policy is materially and adversely
prejudiced thereby, and then only to the extent the Company is thereby
actually so prejudiced.
118
(b) If, at the time of the receipt of a notice of the commencement of a
Proceeding pursuant to Section 6(a) hereof, the Company has a
directors' and officers' liability insurance policy in effect, the
Company shall give prompt notice of the commencement of such Proceeding
to the insurers in accordance with the procedures set forth in the
respective policies. The Company shall thereafter take all necessary or
desirable action to cause such insurers to pay, on behalf of the
Indemnitee, all amounts payable as a result of such Proceeding in
accordance with the terms of such policies.
(c) Subject to the provisions of the last sentence of this Section 6(c) and
of Section 6(d) below, the Company shall have the right to defend
Indemnitee in any Proceeding which may give rise to indemnification
hereunder with counsel approved by Indemnitee, which approval shall not
be unreasonably withheld; provided, however, that the Company shall
notify Indemnitee of any such decision to defend within 15 calendar
days following receipt of notice of any such Proceeding under Section
6(a) above. The Company shall not, without the prior written consent of
Indemnitee, which shall not be unreasonably withheld or delayed,
consent to the entry of any judgment against Indemnitee or enter into
any settlement or compromise which (i) includes an admission of fault
of Indemnitee or (ii) does not include, as an unconditional term
thereof, the full release of Indemnitee from all liability in respect
of such Proceeding, which release shall be in form and substance
reasonably satisfactory to Indemnitee. This Section 6 shall not apply
to a Proceeding brought by Indemnitee under Section 9.
(d) Notwithstanding the provisions of Section 6(c) above, if in a
Proceeding for which the Company has notified Indemnitee that it
intends to defend Indemnitee, (i) Indemnitee reasonably concludes,
based upon an opinion of counsel approved by the Company, which
approval shall not be unreasonably withheld, that he or she may have
separate defenses or counterclaims to assert with respect to any issue
which may not be consistent with other defendants in such Proceeding,
(ii) Indemnitee reasonably concludes, based upon an opinion of counsel
approved by the Company, which approval shall not be unreasonably
withheld, that an actual or apparent conflict of interest or potential
conflict of interest exists between Indemnitee and the Company, or
(iii) if the Company fails to assume the defense of such Proceeding in
a timely manner, Indemnitee shall be entitled to be represented by
separate legal counsel of Indemnitee's choice, subject to the prior
approval of the Company, which shall not be unreasonably withheld, at
the expense of the Company. In addition, if the Company fails to comply
with any of its obligations under this Agreement or in the event that
the Company or any other person takes any action to declare this
Agreement void or unenforceable, or institutes any Proceeding to deny
or to recover from Indemnitee the benefits intended to be provided to
Indemnitee hereunder, Indemnitee shall have the right to retain counsel
of Indemnitee's choice, subject to the prior approval of the Company,
which shall not be unreasonably withheld, at the expense of the
Company, to represent Indemnitee in connection with any such matter.
119
7. Exceptions. Any other provision herein to the contrary notwithstanding,
the Company shall not be obligated pursuant to the terms of this
Agreement:
(a) Claims Initiated by Indemnitee. To advance to the Indemnitee Expenses
or indemnify Expenses or any other liabilities of any type whatsoever
(including, but not limited to, judgments, fines, ERISA excise taxes
and penalties, and amounts paid in settlement) with respect to
Proceedings or claims initiated or brought voluntarily by the
Indemnitee and not by way of defense, unless:
(i) such indemnification is expressly required to be made by law;
(ii) the Proceeding was authorized by the Board;
(iii) such indemnification is provided by the Company, in its sole
discretion, pursuant to the powers vested in the Company under
the Act or the Bylaws; or
(iv) a counterclaim or cross claim is asserted against Indemnitee
for which Indemnitee otherwise would be entitled to indemnity
by Company.
(b) Lack of Good Faith. To indemnify the Indemnitee for any Expenses or any
other liabilities of any type whatsoever (including, but not limited
to, judgments, fines, ERISA excise taxes and penalties, and amounts
paid in settlement) incurred by the Indemnitee (i) with respect to any
Proceeding instituted by the Indemnitee to enforce or interpret this
Agreement, if a court of competent jurisdiction determines that each of
the material assertions made by the Indemnitee in such Proceeding was
not made in good faith or was frivolous, or (ii) with respect to any
Proceeding if the Indemnitee is found liable by a court of competent
jurisdiction after exhaustion of all appeals for willful or intentional
misconduct in the performance of his or her duty to the Company;
(c) Unauthorized Settlements. To indemnify the Indemnitee under this
Agreement for any amounts paid in settlement of a Proceeding unless the
Company consents to such settlement, which consent shall not be
unreasonably withheld; or
(d) No Duplication of Payments. To indemnify the Indemnitee for Expenses or
liabilities of any type whatsoever (including, but not limited to,
judgments, fines, ERISA excise taxes and penalties, and amounts paid in
settlement) for which payment is actually made to Indemnitee under a
valid and collectible directors' and officers' liability insurance
policy, or under a valid and enforceable indemnity clause of the Bylaws
or other agreement.
8. Non-exclusivity. The provisions for advancement of Expenses and
indemnification of Expenses and any judgments, fines, ERISA excise
taxes and amounts paid in settlement set forth in this Agreement shall
not be deemed exclusive of any other rights which the Indemnitee may
120
have under any provision of law, the Company's Articles of
Incorporation, as amended and restated from time to time, or Bylaws,
the vote of the Company's shareholders or disinterested directors, any
employment agreement between the Company and Indemnitee, other
agreements, or otherwise, both as to action in his or her official
capacity and to action in another capacity while occupying his or her
position as an Agent.
9. Remedies of Indemnitee.
(a) If (i) a determination is made that Indemnitee is not entitled to
indemnification under this Agreement, (ii) advance of Expenses is not
timely made pursuant to Section 5 of this Agreement, or (iii) payment
of indemnification is not made pursuant to Section 3 of this Agreement
within 30 days after receipt by the Company of a written request
therefor, Indemnitee shall be entitled to an adjudication in an
appropriate court located in the State of Texas, or in any other court
of competent jurisdiction, of his or her entitlement to such
indemnification or advance of Expenses.
(b) In any judicial proceeding commenced pursuant to this Section 9 the
Company shall have the burden of proving that Indemnitee is not
entitled to indemnification or advance of Expenses, as the case may be.
(c) If a determination shall have been made that Indemnitee is entitled to
indemnification, the Company shall be bound by such determination in
any judicial proceeding commenced pursuant to this Section 9, absent a
misstatement by Indemnitee of a material fact, or an omission of a
material fact necessary to make Indemnitee's statement not materially
misleading, in connection with the request for indemnification.
(d) In the event that Indemnitee, pursuant to this Section 9, seeks a
judicial adjudication to enforce his or her rights under, or to recover
damages for breach of, this Agreement, Indemnitee, if successful in
such enforcement action in whole or in part, shall be entitled to
recover from the Company, and shall be indemnified by the Company for,
any and all Expenses actually and reasonably incurred by him or her in
such judicial adjudication or arbitration, including any claim or
counterclaim brought by the Company in connection therewith. If it
shall be determined in such judicial adjudication or arbitration that
Indemnitee is entitled to receive part but not all of the
indemnification or advance of Expenses sought, the Expenses incurred by
Indemnitee in connection with such judicial adjudication or arbitration
shall be appropriately prorated.
(e) The Company shall be precluded from asserting in any Proceeding,
including, without limitation, an action under Section 9(a) above, that
the provisions of this Agreement are not valid, binding and enforceable
or that there is insufficient consideration for this Agreement and
shall stipulate in court that the Company is bound by all the
provisions of this Agreement.
121
(f) The failure of the Company (including its Board of Directors or any
committee thereof, independent legal counsel, or shareholders) to make
a determination concerning the permissibility of the payment of
indemnifiable amounts or the advance of Expenses under this Agreement
shall not be a defense in any action brought under Section 9(a) above,
and shall not create a presumption that such payment or advance is not
permissible.
10. Determination of "Good Faith".
(a) For purposes of any determination of "good faith" under this Agreement,
the Indemnitee shall be deemed to have acted in good faith if in taking
such action the Indemnitee relied on the records or books of account of
the Company or a Subsidiary or affiliate of the Company, including
financial statements, or on information, opinions, reports or
statements provided to the Indemnitee by the officers or other
employees of the Company or a Subsidiary or affiliate of the Company in
the course of their duties, or on the advice of legal counsel for the
Company or a Subsidiary or affiliate of the Company, or on information
or records given or reports made to the Company or a Subsidiary or
affiliate of the Company by an independent certified public accountant
or by an appraiser or other expert selected by the Company or a
Subsidiary or affiliate of the Company, or by any other person
(including legal counsel, accountants and financial advisors) as to
matters the Indemnitee reasonably believes are within such other
person's professional or expert competence and who has been selected
with reasonable care by or on behalf of the Company. In connection with
any determination as to whether the Indemnitee is entitled to be
indemnified under this Agreement, the person or court making the
determination shall presume that the Indemnitee has satisfied the
applicable standard of conduct and shall be entitled to
indemnification, and the burden of proof shall be on the Company to
establish that the Indemnitee is not so entitled. The provisions of
this Section 9 shall not be deemed to be exclusive or to limit in any
way the other circumstances in which the Indemnitee may be deemed to
have met the applicable standard of conduct set forth in this
Agreement. In addition, the knowledge and/or actions, or failures to
act, of any other person serving the Company or a Subsidiary or
affiliate of the Company as an indemnifiable person shall not be
imputed to the Indemnitee for purposes of determining the right to
indemnification under this Agreement.
(b) The determination as to whether an Indemnitee has met the applicable
standard of conduct set forth in Section 3 hereof shall be made in
accordance with Section F. of Article 2.02-1 of the Act. If for
purposes of making such determination there are no directors who at the
time are not named defendants or respondents in the Proceeding for
which indemnification or reimbursement is sought, then such
determination may be made by independent legal counsel (who may be the
outside counsel regularly employed by the Company) in a written
opinion.
122
11. Subrogation. If payment is made under this Agreement, the Company shall
be subrogated to the extent of such payment to all of the rights of
recovery of Indemnitee from any third parties, the Indemnitee shall
execute all documents reasonably required and shall do all acts that
may be reasonably necessary to secure such rights and to enable the
Company to effectively bring suit to enforce such rights.
12. Continuation of Obligations.
(a) After Service as an Agent. All agreements and obligations of the
Company contained herein shall continue during the period Indemnitee is
an Agent and shall continue thereafter so long as Indemnitee shall be
subject to any possible Proceeding, by reason of the fact that
Indemnitee was serving in the capacity referred to herein.
(b) Successors and Assigns. This Agreement shall be binding upon and inure
to the benefit of and be enforceable by the parties hereto and their
respective successors, assigns (including any direct or indirect
successor by merger, consolidation, or otherwise to all or
substantially all of the business or assets of the Corporation), and
personal and legal representatives. The Company shall require any such
successor to the Company to expressly to assume and agree to perform
this Agreement in the same manner and to the same extent that the
Company would be required to perform if no such succession had taken
place.
13. Severability. If any provision or provisions of this Agreement shall be
held to be invalid, illegal or unenforceable for any reason whatsoever,
then:
(a) the validity, legality and enforceability of the remaining provisions
of the Agreement (including, without limitation, all portions of any
paragraphs of this Agreement containing any such provision held to be
invalid, illegal or unenforceable, that are not themselves invalid,
illegal or unenforceable) shall not in any way be affected or impaired
thereby; and
(b) to the fullest extent possible, the provisions of this Agreement
(including, without limitation, all portions of any provision of this
Agreement containing any such provision held to be invalid, illegal or
unenforceable, that are not themselves invalid, illegal or
unenforceable) shall be construed so as to give effect to the intent
manifested by the provision held invalid, illegal or unenforceable and
to give effect to Section 11 hereof.
14. Modification and Waiver. No supplement, modification or amendment of
this Agreement shall be binding unless executed in writing by the
parties hereto. No waiver of any provision of this Agreement shall be
deemed or shall constitute a waiver of any other provision hereof
(whether or not similar) nor shall such waiver constitute a continuing
waiver.
123
15. Notices. All notices, consents, waivers and other communications under
this Agreement must be in writing and will be deemed to have been duly
given when:
(a) delivered by hand (with written confirmation of receipt);
(b) sent by facsimile (with written confirmation of receipt), provided that
a copy is also promptly mailed by registered mail, return receipt
requested; or
(c) when received by the addressee, if sent by a nationally recognized
overnight delivery service (receipt requested),
in each case to the appropriate addresses and facsimile numbers set forth on the
signature page hereof, as the case may be (or to such other addresses and
facsimile numbers as a party may designate by notice to the other party).
16. Governing Law. This Agreement shall be governed exclusively by and construed
according to the laws of the State of Texas as applied to contracts between
Texas residents entered into and to be performed entirely within Texas without
giving effect to any conflict of laws provisions.
17. Consent to Jurisdiction. The Company and the Indemnitee each hereby
irrevocably consent to the jurisdiction of the state or federal courts in Harris
County, Texas and venue in Harris County, Texas with respect to any Proceeding
that arises out of or relates to this Agreement.
COMPANY:
SWIFT ENERGY COMPANY
By:
----------------------------------------
Terry E. Swift, Chief Executive Officer
Address: 16825 Northchase Dr., Suite 400
Houston, Texas 77060
281-874-2808 (facsimile no.)
INDEMNITEE:
----------------------------------------------
Name:
Address:
124
Exhibit 10.31
PURCHASE AND SALE AGREEMENT
BY AND BETWEEN
BP AMERICA PRODUCTION COMPANY
AND
SWIFT ENERGY OPERATING, LLC
125
INDEX
ARTICLE I
DEFINITIONS
1.1 Definitions 1
ARTICLE II
SALE OF PROPERTIES
2.1 Sale and Purchase 10
2.2 Purchase Price 10
2.3 Performance Deposit 12
2.4 Financial Assurances 12
ARTICLE III
PREFERENTIAL RIGHTS
3.1 Preferential Rights to Purchase 12
ARTICLE IV
TITLE REVIEW
4.1 Review of Title Records 13
4.2 Alleged Title Defects 13
4.3 Waiver 14
4.4 Title Benefits 14
ARTICLE V
CONDITION OF THE PROPERTIES
5.1 Condition of the Properties 15
5.2 Alleged Adverse Conditions 16
5.3 Waiver 17
ARTICLE VI
ACCOUNTING
6.1 Products 17
6.2 Revenues, Expenses and Capital Expenditures 18
6.3 Taxes 18
6.4 Credits 19
6.5 Final Accounting Settlement 19
6.6 Post-Final Accounting Settlement Revenues 20
6.7 Post-Final Accounting Settlement Expenses 20
6.8 Joint Interest Audits 20
ARTICLE VII
LOSS, CASUALTY AND CONDEMNATION
7.1 Notice of Loss 21
7.2 Casualty Loss 21
126
ARTICLE VIII
ALLOCATION OF RESPONSIBILITIES AND INDEMNITIES
8.1 Opportunity for Review 21
8.2 Seller's Non-Environmental Indemnity Obligation 22
8.3 Limitations on Seller's Non-Environmental and Other Indemnities 22
8.4 Seller's Environmental indemnity Obligation 23
8.5 Limitations on Seller's Environmental Indemnities 23
8.6 Buyer's Indemnity Obligation 23
8.7 Notice of Third Party Claims 24
8.8 Defense of Third Party Claims 24
8.9 Duplication of Remedies 25
8.10 Waiver of Certain Damages 25
8.11 Exclusive Remedies 25
8.12 Other Contracts Between the Parties 25
ARTICLE IX
DISCLAIMERS
9.1 Disclaimers 26
9.2 Disclaimer of Statements and Information 26
ARTICLE X
SELLER'S REPRESENTATIONS AND WARRANTIES
10.1 Seller's Representations and Warranties 27
ARTICLE XI
BUYER'S REPRESENTATIONS AND WARRANTIES
11.1 Buyer's Representations and Warranties 28
ARTICLE XII
ADDITIONAL COVENANTS
12.1 Subsequent Operations 30
12.2 Rights of Non-Exclusive Use 30
12.3 Buyer's Assumption of Obligations 30
12.4 Asbestos and NORM 30
12.5 Plugging and Abandonment 31
12.6 Process Safety Management 32
12.7 Imbalances 32
12.8 Suspense Funds 33
12.9 Sales Tax 33
12.10 Transition Agreement 34
12.11 interim Period 34
12.12 Consents to Assign 39
12.13 Notification of Breaches 35
12.14 Third Party-Owned Technology 35
12.15 Shared Systems IP License 40
12.16 Financial Audit for SEC Filings 40
127
ARTICLE XIII
HSR ACT
13.1 HSR Filings 37
ARTICLE XIV
PERSONNEL
14.1 Employee List 37
14.2 Restriction on Solicitation 37
ARTICLE XV
CONDITIONS PRECEDENT TO CLOSING
15.1 Conditions Precedent to Seller's Obligation to Close 37
15.2 Conditions Precedent to Buyer's Obligation to Close 38
15.3 Conditions Precedent to Obligation of Each Party to Close 38
ARTICLE XVI
THE CLOSING
16.1 Closing 39
16.2 Seller's Obligations at Closing 40
16.3 Buyer's Obligations at Closing 40
ARTICLE XVII
TERMINATION
17.1 Grounds for Termination 41
17.2 Effect of Termination 42
17.3 Dispute over Right to Terminate 42
17.4 Confidentiality 42
ARTICLE XVIII
ARBITRATION
18.1 Arbitration 42
ARTICLE XIX
MISCELLANEOUS
19.1 Notices 43
19.2 Costs and Post-Closing Consents 44
19.3 Brokers, Agents and Finders 44
19.4 Records 45
19.5 Further Assurances 45
19.6 Survival of Certain Obligations 46
19.7 Amendments and Severability 46
19.8 Successors and Assigns 46
19.9 Headings 47
19.10 Governing Law 47
19.11 No Partnership Created 47
19.12 Public Announcements 47
128
19.13 No Third Party Beneficiaries 47
19.14 Indemnities Applicability 47
19.15 Waiver of Consumer Rights 48
19.16 Redhibition Waiver 48
19.17 UTPCPL Waiver 48
19.18 Not to be Construed Against Drafter 48
19.19 Conspicuousness of Provisions 49
19.20 Possible Exchange 49
19.21 Execution in Counterparts 49
19.22 Entire Agreement 49
EXHIBITS
EXHIBIT "A" - PROPERTIES AND ALLOCATIONS
EXHIBIT "A-1" INDIVIDUAL WELL AND FACILITY LISTING AND ALLOCATIONS
EXHIBIT "B" - EXCLUDED PROPERTIES
EXHIBIT "C" - LITIGATION, CLAIMS AND DISPUTES
EXHIBIT "D" - DEED, ASSIGNMENT AND BILL OF SALE
EXHIBIT "E" - CERTIFICATE
EXHIBIT "F" - LETTERS-IN-LIEU
EXHIBIT "G" - NON-FOREIGN CERTIFICATE
EXHIBIT "H" - FORM OF TRANSITION AGREEMENT
EXHIBIT "I" - FORM OF PREFERENTIAL PURCHASE RIGHT NOTICE LETTER
EXHIBIT "J" SHARED SYSTEMS IP LICENSE
129
SCHEDULES
SCHEDULE 1.1 LIST OF PARTNERSHIPS
SCHEDULE 6.2.2 REIMBURSEMENT IN LIEU OF OVERHEAD
SCHEDULE 12.7 IMBALANCES
130
PURCHASE AND SALE AGREEMENT
THIS PURCHASE AND SALE AGREEMENT (this "AGREEMENT") dated August 24,
2006, is by and between BP AMERICA PRODUCTION COMPANY, A Delaware corporation,
with an office at 501 WestLake Park Boulevard, Houston, Texas 77079 ("SELLER")
and SWIFT ENERGY OPERATING, LLC, a limited liability company, with an office at
16825 Northchase Drive, Suite 400, Houston, Texas 77060 ("BUYER") (individually,
a "Party" and collectively, the "PARTIES").
WHEREAS, Seller desires to sell and deliver to Buyer, and Buyer desires
to purchase and accept Seller's interests in certain oil and gas properties and
related assets; and
WHEREAS, the Parties have reached agreement regarding the sale and
purchase,
NOW, THEREFORE, for and in consideration of the mutual covenants herein
and other good and valuable consideration, the receipt and sufficiency of which
are hereby acknowledged, the Parties agree to all the terms and conditions in
this Agreement:
ARTICLE I
DEFINITIONS
1.1 DEFINITIONS. Unless otherwise provided in this Agreement, each
capitalized term in this Agreement has the meaning given to it IN THIS Article.
All defined terms include the singular and the plural. All references to
Articles refer to Articles in this Agreement, and all references to Exhibits and
Schedules refer to the Exhibits and Schedules which are attached to and by this
reference are made a part of this Agreement. When a term is defined as one part
of speech (e.g., noun), any other part of speech (e.g., verb) with respect to
the term has a comparable meaning.
"AAA" has the meaning given it in Article 18.1.
"ACCOUNTING REFEREE" means the accounting firm of Deloitte & Touche,
LLP or any other nationally recognized United States based accounting firm on
which the Parties agree.
"ADJUSTED PURCHASE PRICE" has the meaning given it in Article 2.2,
"AFFILIATE" means any entity that, directly or indirectly, through one
or more intermediaries, controls or is controlled by or is under common control
with the entity specified. For the purpose of this definition, the term
"CONTROL" means ownership of fifty percent (50%) or more of voting rights (stock
or otherwise) or ownership interest or the power to direct or cause the
direction of the management and policies of the entity in question.
"AGREEMENT" has the meaning given it in the introductory paragraph of
this Agreement and includes all Exhibits and Schedules hereto, as the same may
be amended from time to time by the Parties.
"ALLEGED ADVERSE CONDITION" means an individual environmental condition
131
associated with the Properties that: (a) was not disclosed to Buyer in the
electronic data room Seller established with Merrill Corporation for the
Properties (the "DATA ROOM"), (b) is asserted by Buyer in accordance with
Article 5.2, (c) is not in compliance with Environmental Laws in effect as of
the Effective Time, and (d) requires an expenditure to remedy exceeding two
hundred fifty thousand dollars (US $250,000) net to Seller's interests in the
Property affected by such individual condition.
"ALLEGED TITLE DEFECT" means an individual Title Defect that is not
disclosed on Exhibit "C" and that is (a) is asserted by Buyer in accordance with
Article 4.2, and (b) requires an expenditure to cure or has a value (whichever
is less) exceeding fifty thousand dollars (US $50,000) net to Seller's interests
in the Properties affected by such individual Title Defect.
"ARBITRABLE DISPUTE" means, except as set forth below, any and all
disputes, claims, counterclaims, demands, causes of action, controversies and
other matters in question arising out of or relating to this Agreement or the
alleged breach hereof, or in any way relating to matters that are the subject of
this Agreement or the transactions contemplated hereby or the relationship
between the Parties created by this Agreement, regardless of whether (a)
allegedly extra-contractual in nature, (b) sounding in contract, tort or
otherwise, (c) provided for by Law or otherwise, or (d) seeking damages or any
other relief, whether at Law, in equity or otherwise; provided, however, that
the term "ARBITRABLE DISPUTE" does not include disputes that by the terms of
this Agreement (i) will be determined by the Accounting Referee, or (ii) relate
to breach of confidentiality obligations, or (iii) concern either Party's right
to terminate this Agreement.
"ASSUMED OBLIGATIONS" has the meaning given it in Article 12.3.
"BUSINESS DAY" means between 8:00 a.m. Central Time and 4:00 p.m.,
Central Time, on a Day when federally chartered banks in the State of Texas
generally are open for business.
"BUYER" has the meaning set forth in the introductory paragraph of this
Agreement.
"BUYER GROUP" means each and all of: (a) Buyer and its members,
partners, officers, directors, agents, consultants and employees, and (b)
Buyer's Affiliates and their members, partners, officers, directors, agents,
consultants and employees.
"CASUALTY LOSS" means physical damage to the Properties that (a) occurs
between execution of this Agreement and Closing, (b) is not the result of normal
wear and tear, mechanical failure or gradual structural deterioration of
materials, equipment, and infrastructure, downhole failure (including (i)
failures arising or occurring during drilling or completing operations, (ii)
junked or lost holes, or (iii) sidetracking or deviating a well) or reservoir
changes, and (c) has an adverse effect on the value of the affected Properties
in an amount that exceeds two hundred fifty thousand dollars (US $250,000).
"CERTIFICATE" means a document in the form of Exhibit "E".
"CHARGES" means with respect to the Properties:
132
(a) to the extent attributable to services performed or provided during
the time period specified: (i) invoices and bills received under contracts,
including joint interest billings, in the ordinary course of business, (ii)
other ordinary course of business charges for operating and maintaining
material, equipment, other personal property and fixtures, leases, easements,
rights-of-way, servitudes, subsurface leases, licenses and permits, (iii)
charges for utilities and insurance, and (iv) field personnel salaries, wages
and employee benefits;
(b) charges for the acquisition of materials, equipment, other personal
property and fixtures, leases, easements, rights-of-way servitudes, subsurface
leases, licenses and permits (in each case) to the extent that such items were
acquired during the time period specified;
(c) producing, drilling, construction, marketing and overhead costs
charged by Third Parties under joint interest billings or otherwise to the
extent attributable to services performed or provided during the time period
specified; and
(d) taxes and similar assessments of governmental authorities (other
than income taxes, and Sales Tax, if any, on the transactions contemplated by
this Agreement) to the extent attributable to the time period specified;
provided that Charges do not include (1) royalties (including overriding
royalties and other burdens on production); (2) costs and expenses relating to
Imbalances or Suspense Funds; or (3) any costs and expenses incurred outside of
the ordinary course of business in connection with the performance of services
(such as costs and expenses attributable to personal injuries, environmental
liabilities and/or property damages).
"CLAIM NOTICE" means a notice of Third Party Claim or Loss provided in
accordance with Article 8.7.
"CLAIMANT" has the meaning set forth in Article 18.1.
"CLOSE" or CLOSING" means consummation of the transactions contemplated
by this Agreement, including execution and delivery of all documents and other
consideration as provided in this Agreement.
"CLOSING DATE" means (a) October 2, 2006, or (b) any other date agreed
by the Parties.
"CLOSING STATEMENT" refers to the document described in Article 16.1.
"COMPUTED INTEREST" means simple interest at a rate per annum equal to
the lesser of (i) three percent (3%) per annum using a 365 Day year or (ii) the
maximum rate of interest allowed by Law.
"CONFIDENTIALITY AGREEMENT" means the Confidentiality Agreement dated
May 31, 2006, between Seller and Buyer, as the same may be amended from time to
time.
"DATA ROOM" has the meaning given it in the definition of Alleged
Adverse Condition.
133
"DAY" means a calendar day consisting of twenty-four
(24) hours from midnight to midnight.
"DEED, ASSIGNMENT AND BILL OF SALE" means a document substantially in
the form of Exhibit "D".
"DEFENSIBLE TITLE" means such title to the Properties held by Seller
that (except for the Permitted Encumbrances):
(a) with respect to the leases, contractual interests,
overriding royalty interests, units or wells set forth on Exhibit
"A" or "A-l", as applicable, entitles Seller to receive, as of the
Effective Time, not less than the Net Revenue Interest (NRI) for
such lease, contractual interest, overriding royalty interest, well
or unit set forth on Exhibit "A" or "A-1", as applicable, except
decreases resulting from operations where Seller is a non-consenting
party and decreases required to allow other working interest owners
to make up past underproduction or pipelines to make up past
under-deliveries;
(b) with respect to the leases, contractual interests, units
or wells set forth on Exhibit "A" or "A- 1", as applicable,
obligates Seller to bear, as of the Effective Time, not greater than
the Working Interest (WI) for such well or unit set forth on Exhibit
"A" or "A-l", as applicable, unless there is a corresponding
increase in the associated Net Revenue Interest (NRI), or such
increase results from contribution requirements with respect to
defaulting co-owners; and
(c) is free of liens and other encumbrances.
"EFFECTIVE TIME" as to each Property, means April 1, 2006, at 7:00
a.m., local time where the Properties are located.
"ENVIRONMENTAL CLAIMS" means all Third Party Claims based on a
violation of Environmental Laws with respect to the Properties; provided that
only with respect to Third Party Claims for which Seller owes an obligation of
indemnity to Buyer, the term "ENVIRONMENTAL CLAIMS" is limited to Third Party
Claims based on a violation of Environmental Laws as such Laws were in effect at
the Effective Time.
"ENVIRONMENTAL LAWS" means any and all Laws that relate to (a)
prevention of pollution or environmental damage, (b) removal or remediation of
pollution or environmental damage, or (c) protection of the environment, public
health or safety.
"EXCLUDED PROPERTIES" means the items, properties and matters that are
set forth in Exhibit "B" or that are otherwise excepted, reserved or retained by
Seller under the terms of this Agreement.
"FINAL ACCOUNTING SETTLEMENT" means the post-Closing accounting
activities conducted in accordance with Article 6 which shall be conducted in
accordance with generally accepted accounting principles, as applied by Seller
with respect to the Properties on the date the Final Accounting Statement is
prepared.
134
"FINAL ACCOUNTING STATEMENT" means a statement prepared by Seller and
delivered to Buyer in accordance with Article 6.5 setting forth the adjustments
applicable to the period between the Effective Time and the Closing Date.
"HSR ACT" means the Hart-Scott-Rodino Antitrust improvements Act of
1976, as amended.
"IMBALANCE" means over-production or under-production or
over-deliveries or under-deliveries with respect to hydrocarbons produced from
or allocated to the Properties, regardless of whether such over-production or
under-production, or over-deliveries or under-deliveries arise at the platform,
wellhead, pipeline, gathering system, transportation or other location and
regardless of whether the same arise under contract or by operation of Law.
"INCLUDING", whether or not capitalized, means including without
limitation.
"INDEMNIFIED PARTY" has the meaning set forth in Article 8.7.
"INDEMNIFYING PARTY" has the meaning set forth in Article 8.7.
"INTERIM PERIOD" means the period between the date of this Agreement
and the Closing Date.
"KNOWLEDGE" (whether or not capitalized) means, in the case of Seller,
the actual knowledge of Seller's Disposition Team.
"LAWS" means any and all applicable laws, statutes, codes,
constitutions, ordinances, permits, licenses, authorizations, agreements,
decrees, orders, judgments, rules or regulations (including, for the avoidance
of doubt, Environmental Laws) that are promulgated, issued or enacted by a
governmental or tribal entity or authority having appropriate jurisdiction of
the Properties or the Parties.
"LETTERS-IN-LIEU" means a document in the form of Exhibit "F" in
connection with oil production from the Properties which shall be prepared by
Seller, signed by the Parties and delivered to purchasers of production from the
Properties at such time as is mutually agreed by the Parties.
"LOSS" means any and all claims of any kind or character, including
demands, suits, causes of action, rights of action, suits, legal or
administrative proceedings, regulatory actions, losses, risk of losses,
impairment of rights, damages, liabilities, subordinations, fines, or penalties
and all expenses and costs (including interest, attorneys' fees, costs of
litigation and court costs) associated therewith, whether known or unknown,
direct or indirect, excluding Third Party Claims.
"MATERIAL ADVERSE EFFECT" means an event or circumstance that,
135
individually or in the aggregate with all other events and circumstances,
results in a material adverse effect on the ownership, operations, or value of
the Properties, taken as a whole and as currently operated as of the date of
this Agreement or a material adverse effect on the ability of Seller to
consummate the transactions contemplated by this Agreement; provided, however,
that none of the following shall be deemed to constitute a Material Adverse
Effect: (i) any effect resulting from changes in general market, economic,
financial or political conditions in the area in which the Properties are
located, the United States or worldwide, or any outbreak of hostilities or war,
(ii) any effect resulting from a change in Laws; (iii) any changes in the prices
of hydrocarbons; and/or (iv) natural declines in well performance.
"NET REVENUE INTEREST" or ~ with respect to any Property that is a
lease, unit or well, means the interest in and to all oil, gas and associated
liquids and gaseous hydrocarbons produced, saved, and sold from such unit or
well, after giving effect to all royalties, overriding royalties, production
payments, carried interests, net profits interests, reversionary interests, and
other burdens upon, measured by, or payable out of production therefrom.
"NON-ENVIRONMENTAL CLAIMS" means all Third Party Claims, except for
Environmental Claims.
"NON-FOREIGN CERTIFICATE" means a document in the form of Exhibit "G".
"NORM" means naturally occurring radioactive materials.
"OPERATING REVENUES" means sales proceeds for oil, gas and other
hydrocarbons produced from the Properties, net of royalties, excise, severance
and other production taxes and marketing costs (which include for purposes of
this definition, costs of gathering, treating, processing, compression, and
transportation), to the extent such items are not treated as "CHARGES" under
Article 6, and all other operating revenues attributable to the Properties,
excluding producing, drilling and construction overhead receipts Seller receives
under operating agreements with Third Parties and further excluding proceeds in
cash or from sale of production in settlement of Imbalances prior to the Closing
Date.
"PARTIES" has the meaning given it in the introductory paragraph of
this Agreement.
"PARTY" has the meaning given it in the introductory paragraph of this
Agreement.
"PERFORMANCE DEPOSIT" HAS THE MEANING given it IN Article 2.3.
"PERMITTED ENCUMBRANCES" MEANS any and all:
(a) royalties, overriding royalties, sliding scale royalties,
production payments, reversionary interests, convertible interests, net
profits interests and similar burdens encumbering any Property to the
extent the net cumulative effect of such burdens does not operate to
reduce the Net Revenue interest of such Property, as of the Effective
Time to less than the Net Revenue Interest (NRI) for such Property set
forth in Exhibit "A" "A- 1", as applicable, or increase the Working
136
Interest of such Property, as of the Effective Time, above the Working
interest (WI) for such Property set forth in Exhibit "A" or "A-l", as
applicable, without a corresponding and proportionate increase in the
associated Net Revenue interests for such Property;
(b) consents to assignment and similar contractual provisions
affecting the Properties; (c) preferential rights to purchase and
similar contractual provisions affecting the Properties;
(c) preferential rights to purchase and similar contractual
provisions affecting the Properties;
(d) rights to consent by, required notices to, and filings
with a governmental entity or authority associated with the conveyance
of the Properties;
(e) rights reserved to or vested in a governmental or tribal
entity or authority having jurisdiction to control or regulate the
Properties in any manner whatsoever, and all Laws of such governmental
entities or authorities;
(f) easements, rights-of-way, servitudes, surface leases,
grazing rights, logging rights, ponds, lakes, waterways, canals,
ditches, reservoirs, equipment, pipelines, utility lines, railways,
streets, roads and structures on, over, under and through the
Properties;
(g) the terms and conditions of unitizations,
communitizations, poolings, agreements, instruments, licenses and
permits affecting the Properties;
(h) liens for taxes or assessments not yet delinquent or, if
delinquent, are being contested by Seller in good faith;
(i) liens of operators relating to obligations not yet
delinquent or, if delinquent, are being contested by Seller;
(j) matters that would otherwise be Alleged Title Defects but
that do not meet the individual threshold and aggregate deductible
amounts set forth in the definition of Alleged Title Defect and in
Article 4.2, respectively, or that Buyer waives in accordance with
Article 4.3, or for which a Purchase Price adjustment is made or
another remedy provided pursuant to Article 4.2;
(k) matters that would otherwise be Alleged Adverse Conditions
but that do not meet the individual threshold and aggregate deductible
amounts set forth in the definition of Alleged Adverse Conditions and
in Article 5.2, respectively, or that Buyer waives in accordance with
Article 5.3, or for which a Purchase Price adjustment is made or
another remedy provided pursuant to Article 5.2;
(l) Imbalances;
(m) Suspense Funds;
(n) any rights of ingress and egress or other access rights
137
reserved by or granted to Seller and/or its Affiliates under this
Agreement;
(o) matters that Buyer waives in writing;
(p) terms and conditions of governmental licenses and permits
affecting the Properties;
(q) matters specifically listed on Exhibit "A" or "A-1" or
otherwise disclosed on a Schedule to this Agreement; and
(r) such defects or irregularities in the title to the
Properties that do not materially interfere with the ownership,
operation, or use of the Properties affected thereby as such Properties
were owned, operated or used as of the Effective Time.
"PLUGGING AND ABANDONMENT" means all decommissioning activities and
obligations as are required by Laws, contracts associated with the Properties,
this Agreement (expressly including, such activities described and defined as of
the Effective Time and as may be amended thereafter, in 30 Code of Federal
Regulations 250.1700 et seq.) and further including all well plugging,
replugging and abandonment; facility dismantlement and removal; pipeline and
flowline removal; dismantlement and removal of any and all platforms and other
property of any kind related to or associated with operations or activities
conducted on the Properties; and site clearance, site restoration and site
remediation.
"PPR" means a preferential right to purchase any Property arising out
of an agreement covering such Property.
"PROCESS SAFETY MANAGEMENT" means Process Safety Management of Highly
Hazardous Chemicals; Explosives and Blasting Agents (29 CFR 1910), as amended,
that is associated with the Properties.
"PROPERTIES" means all of Seller's right, title and interests (real,
personal, mixed, contractual or otherwise) in, to and under or derived from the
following, excluding the Excluded Properties:
(a) all oil and gas leasehold interests, royalty
interests, overriding royalty interests, production payments,
reversionary interests, options, carried working interests,
beneficial interests and net profits interests that are attributable
to the interests described in Exhibit "A" or "A-1", and the
production of oil, gas and other hydrocarbon substances attributable
thereto;
(b) all unitization, communitization and pooling
declarations, orders and agreements (including all units formed by
voluntary agreement and those formed under the rules, regulations,
orders or other official acts of any governmental entity or
authority having jurisdiction) to the extent they relate to any of
the interests described in Exhibit "A" or "A-l", or the production
of oil, gas or other hydrocarbon substances attributable thereto;
138
(c) to the extent assignable, all product sales contracts,
processing contracts, gathering contracts, transportation contracts,
easements, rights-of-way, servitudes, surface leases, farm-in and
farm-out contracts, areas of mutual interest, operating agreements,
balancing contracts, permits, licenses and other files, contracts,
agreements and instruments to the extent they relate to any of the
interests described in Exhibit "A" or "A-l", or the production of
oil, gas or other hydrocarbon substances attributable thereto;
(d) all (i) tangible personal property, improvements,
fixtures and other appurtenances, to the extent situated upon and
exclusively used, or situated upon and held exclusively for use, by
Seller (or the Operator of the Property) in connection with the
ownership, operation, maintenance or repair of the interests
described on Exhibit "A" or "A-1" or the production of oil, gas or
other hydrocarbon substances attributable thereto, including all
gathering and processing systems, platforms, buildings, compressors,
meters, tanks, equipment, machinery and tools and; (ii) wells
(whether producing, shut-in, injection, disposal, water supply,
temporarily abandoned, plugged and abandoned or otherwise) and
pipelines (whether or not in use);
(e) all partnerships (tax, state law or otherwise)
affecting any Properties;
(f) all Imbalances; and
(g) all Suspense Funds.
"PURCHASE PRICE" has the meaning set forth in Article 2.2.
"RECORDS" means, except as excluded in Exhibit "B" or otherwise
excluded or retained by Seller under the terms of this Agreement, an original or
a copy (hard copy, electronic or otherwise) of Seller's books, records, data
(including, without limitation, technical and digital data) and files to the
extent primarily related to the Properties.
"RESPONDENT" has the meaning set forth in Article 18.1.
"SALES TAX" means any and all transfer, sales, gross receipts,
compensating use, use or similar taxes, and any associated penalties and
interest.
"SELLER" has the meaning set forth in the introductory paragraph of
this Agreement.
"SELLER GROUP" means each and all of: (a) Seller and its officers,
directors, agents, consultants and employees, and (b) Seller's Affiliates and
their members, partners, officers, directors, agents, consultants and employees.
"SELLER'S DISPOSITION TEAM" means Steve Choate (Project Manager,
Mergers and Acquisitions), Hal Bogdanski (Senior Negotiator -- Business
Development), Hodge Walker (Resource Manage -- Gulf Coast), and Johnathan Wengel
(HSSE Business Development Support Manager).
139
"SHARED SYSTEMS IP" has the meaning given to it in Exhibit "J".
"SUSPENSE FUNDS" means proceeds of production and associated penalties
and interest in respect of any of the Properties that are payable to Third
Parties and are being held in suspense by Seller as the operator of such
Properties.
"SYSTEMS IP LICENSE" means a document in the form of Exhibit "K".
"THIRD PARTY CLAIMS" means any and all claims of any kind or character,
including demands, suits, causes of action, rights of action, regulatory
actions, losses, risk of losses, impairment of rights, damages, liabilities,
subordinations, fines, or penalties and all expenses and costs (including
attorneys' fees, costs of litigation and court costs) associated therewith,
whether known or unknown, direct or indirect, and whether an Environmental Claim
or a Non-Environmental Claim, that are brought by, on behalf of or owed to a
Third Party.
"THIRD PARTY-OWNED TECHNOLOGY" means technology, including software,
licensed from a Third Party for use in connection with the Properties or the
operation thereof.
"TITLE BENEFIT" means any right, circumstance or condition that
operates to (i) increase the Net Revenue Interest (NRI) of Seller in any
Property above that set forth in Exhibit "A" or "A-1", as applicable, without
causing a greater than proportionate increase in the Working Interest (WI) above
that shown in Exhibit "A" or "A-1", as applicable, or (ii) decrease the Working
Interest (WI) of Seller in a Property below that set forth in Exhibit "A" or
"A-1", as applicable, without decreasing the Net Revenue Interest (NRI) for such
Property below that shown in Exhibit "A" or "A-1", as applicable.
"TITLE DEFECT" means an individual defect in Seller's title to one or
more Properties that would cause Seller not to have Defensible Title to such
Property or Properties, and notwithstanding anything in this Agreement to the
contrary, does not include the failure of a Party to obtain regulatory approval
to conduct a drilling operation, including the right to drill an increased
density or infill well.
"TRANSITION AGREEMENT" means a document in the form of Exhibit "H".
"TRANSITION PERIOD" means the period beginning on the Closing Date and
ending on the date on which the Transition Agreement terminates.
"WORKING INTEREST" or "~" with respect to any Property that is a lease,
unit or well, the interest in and to such unit or well that is burdened with the
obligation to bear and pay costs and expenses of maintenance, development and
operations on or in connection with such lease. unit or well, but without regard
to the effect of any royalties, overriding royalties, production payments, net
profits interests and other similar burdens upon, measured by, or payable out of
production therefrom.
140
ARTICLE II
SALE OF PROPERTIES
2.1 SALE AND PURCHASE. On the Closing Date, but effective as of the
Effective Time, and upon the terms and conditions of this Agreement: (a) Seller
shall sell and assign the Properties to Buyer, and (b) Buyer shall purchase and
accept the Properties from Seller; provided, however, that Seller expressly
excepts, reserves and retains, unto itself and its Affiliates, successors and
assigns, the Excluded Properties.
2.2 PURCHASE PRICE. The total consideration for the Properties, subject
to adjustments as described below, is (a) the payment by Buyer to Seller of One
Hundred Seventy-Five Million Two Hundred Thousand no/100 United States Dollars
(US $175,200,000.00) ("PURCHASE PRICE"), payable in full at Closing in
immediately available funds, and (b) Buyer's assumption of the Assumed
Obligations. The Purchase Price shall be adjusted as follows:
2.2.1 increased by Computed interest on the Purchase
Price for the period from the Effective Time through the Closing Date;
2.2.2 decreased by the amount of the Performance
Deposit, paid by Buyer to Seller, together with Computed Interest on the
Performance Deposit calculated from the date of deposit with Seller
through the Closing Date;
2.2.3 decreased by the amount of Operating Revenues
to which Buyer is entitled under Article 6.2 but which are collected and
retained by Seller, together with Computed Interest thereon, calculated
from the date of receipt of such revenues by Seller through the Closing
Date;
2.2.4 increased by the amount set forth in Article
6.2.2 per month (pro-rated on a daily basis for any partial month) from
the Effective Time through the Closing Date;
2.2.5 increased by the amount of Charges for which
Buyer is responsible under Article 6.2 but which are paid by Seller;
2.2.6 decreased by the amount of Charges for which
Seller is responsible under Article 6.2 but which are paid by Buyer;
2.2.7 increased by amounts to which Seller is
entitled pursuant to Article 6.1;
2.2.8 increased by the amount of taxes and
assessments for which Buyer is responsible under Article 6.3 but which
are paid by Seller;
2.2.9 decreased by the amount of taxes or assessments
for which Seller is responsible under Article 6.3 but which are paid by
Buyer;
141
2.2.10 decreased by the agreed or arbitrated net
adjustment, if any, for Alleged Title Defects pursuant to Article 4.2,
and increased by the agreed or arbitrated net adjustment, if any, for
Title Benefits pursuant to Article 4.4;
2.2.11 decreased by the agreed or arbitrated net
adjustment, if any, to which Buyer is entitled for Alleged Adverse
Conditions pursuant to Article 5.2 and decreased or increased, as
appropriate, by any adjustments made for Properties excluded pursuant to
Article 5.2.1;
2.2.12 decreased or increased, as appropriate,
by any adjustments made for Properties excluded pursuant to Article 3.1;
2.2.13 decreased for any agreed reduction in value
pursuant to Article 7.2;
2.2.14 increased by the amount of all capital
expenditures incurred (or the obligation to incur the capital
expenditures was undertaken) by Seller which expenditures have been
disclosed to Buyer in respect of the Properties within six (6) months
prior to the Effective Time; and
2.2.15 increased or decreased, as the case may be,
by any other amount mutually agreed to by the Parties in writing.
The Purchase Price, as so adjusted, is the "ADJUSTED PURCHASE PRICE."
2.3 PERFORMANCE DEPOSIT. UPON EXECUTION OF THIS AGREEMENT AND PRIOR TO
ITS DELIVERY TO BUYER, BUYER SHALL DEPOSIT WITH SELLER CASH EQUAL TO TEN PERCENT
(10%) OF THE UNADJUSTED PURCHASE PRICE ("PERFORMANCE DEPOSIT"), PROVIDED
HOWEVER, THAT IF THIS AGREEMENT IS EXECUTED ON A DAY OTHER THAN A BUSINESS DAY,
BUYER SHALL DELIVER THE PERFORMANCE DEPOSIT TO SELLER ON THE NEXT BUSINESS DAY.
2.4 FINANCIAL ASSURANCES. If, no later than seven (7) Days prior to the
date of execution of this Agreement, Seller provided Buyer a written
notification requiring Buyer to provide a parent guaranty, letter of credit or
other assurances of Buyer's performance under this Agreement or of Buyer's
financial capability to undertake its obligations under this Agreement
("ASSURANCE"), then upon execution of this Agreement and prior to its delivery
to Buyer, Buyer shall provide Seller with the Assurance, in form and substance
satisfactory to Seller in Seller's sole discretion.
ARTICLE III
PREFERENTIAL RIGHTS
3.1 PREFERENTIAL RIGHTS TO PURCHASE. Seller shall use Buyer's good
faith allocation of the Purchase Price set forth in Exhibit "A" or "A-1", as
applicable, to provide any required preferential right to purchase notifications
in connection with the transactions contemplated hereby, using a Preference
Purchase Right Notice Letter substantially in the form attached as Exhibit "I".
If ,as of the Closing Date, (a) a holder of a preferential purchase right
142
("PPR") has notified Seller that it elects to exercise its PPR with respect to
the Properties to which its PPR applies (in accordance with the agreement in
which the PPR arises, as determined by Seller) or (b) the time for exercising
such PPR has not expired, then the Properties covered by that PPR will not be
sold to the Party originally executing this Agreement as "Buyer" (subject to the
remaining provisions in this Article), and the Purchase Price will be reduced by
the value allocated to such Properties in Exhibit "A" or "A-1", as applicable.
In accordance with the terms of this Agreement, Buyer remains obligated to
purchase the remainder of the Properties not affected by an exercised PPR or a
PPR for which the time to exercise has expired prior to Closing,
3.1.1 After the Closing, if for any reason the purchase and
sale of the Properties covered by the PPR is not or cannot be
consummated with the holder of the PPR that exercised its PPR or if the
time for exercising the PPR expires without exercise by any holder of
the PPR, Seller may so notify Buyer and within ten (10) Business Days
after Buyer's receipt of such notice or after such expiration, Seller
shall sell, assign and convey to Buyer and Buyer shall purchase and
accept from Seller such Properties pursuant to the terms of this
Agreement and for the value allocated to such Properties in Exhibit "A"
or "A-1", as applicable (except the Closing Date with respect to such
Properties will be the date of assignment of such Properties from
Seller to Buyer).
3.1.2 Any PPR must be exercised subject to all the terms and
conditions of this Agreement.
ARTICLE IV
TITLE REVIEW
4.1 REVIEW OF TITLE RECORDS. After execution and delivery of this
Agreement, Seller shall make available (during Seller's regular business hours
and at their current location(s)) for Buyer's review, Records in Seller's and
its Affiliates' possession relating to title to the Properties. If Buyer
requests copies of title Records, Seller shall use its commercially reasonable
efforts to provide the requested copies to Buyer at Buyer's expense. Buyer shall
conduct its review of Records in accordance with the terms of the
Confidentiality Agreement.
4.2 ALLEGED TITLE DEFECTS.
4.2.1 As soon as reasonably practicable (and on an ongoing
basis), but no later than the earlier of (i) four (4) Business Days
before the Closing Date or (ii) thirty (30) Days after the date the
Parties execute this Agreement, Buyer shall notify Seller in writing of
any Title Defects. Buyer's notice asserting Title Defects must include
a description and full explanation (including any and all supporting
documentation) of each Title Defect claimed, the Properties affected
thereby, and the value Buyer in good faith attributes to the Title
Defect. Buyer and Seller shall meet from time to time to attempt to
agree on resolution with respect to Alleged Title Defects, including
any Purchase Price adjustment with respect thereto.
4.2.2 Seller shall have the right, but not the obligation, to
attempt, at Seller's sole cost, to cure or remove on or before the
143
Closing Date any Alleged Title Defects of which it has been advised by
Buyer. If prior to Closing, Seller has commenced curing the Alleged
Title Defect and pursues such effort diligently, then Seller may, by
notice to Buyer prior to Closing, continue attempting to cure such
defect to completion for up to one hundred eighty (180) Days after the
Closing Date. If Seller does not cure an Alleged Title Defect prior to
Closing and fails to provide notice that it shall continue attempting
to cure such Alleged Title Defect after Closing, or if such notice is
provided but such Alleged Title Defect is not cured on or before one
hundred eighty (180) Days following Closing, then within thirty (30)
Days following Seller's receipt of written notice from Buyer of such
failure or non-completion and either (i) Seller's and Buyer's agreement
upon the existence and value of the Alleged Title Defect or (ii) a
resolution by binding arbitration in accordance with Article 18.1 of
any dispute regarding the existence or value of the uncured Alleged
Title Defect, Seller shall pay to Buyer an amount equal to the value if
any of such Alleged Title Defect, as so agreed or as determined in
arbitration.
4.2.3 The cumulative adjustments and payments associated with
the Alleged Title Defects may not exceed the value allocated to the
affected Property in Exhibit "A" or "A-1", as applicable, but
notwithstanding the foregoing, if an Alleged Title Defect is reasonably
susceptible of being cured, the adjustments or payments with respect to
that Alleged Title Defect shall not exceed the reasonable costs of
cure. If the Parties are unable to agree on a resolution associated
with any Alleged Title Defects raised by Buyer before Closing, the
Parties shall Close without Purchase Price adjustment; provided,
however, that within thirty (30) Days after the Closing Date, either
Party may initiate binding arbitration in accordance with the
provisions set forth in Article 1 8.1 to resolve the dispute.
4.2.4 Any claim with respect to an Alleged Title Defect not
referred to arbitration within thirty (30) Days following Closing as
provided in Article 4.2.3 (or, with respect to any Alleged Title Defect
for which Seller provides notice that it will continue attempting to
cure after Closing, within thirty (30) Days after the one hundred
eighty (180) Day period cure period following Closing has expired)
shall be deemed waived by Buyer for all purposes.
4.2.5 Notwithstanding anything contained in this Agreement to
the contrary, Buyer shall not be entitled to an adjustment or other
remedy relating to an Alleged Title Defect unless and until the
aggregate value of all Alleged Title Defects not cured or indemnified
against by Seller exceeds one percent (1%) of the Purchase Price, and
then only to the extent such aggregate value exceeds one percent (1%)
of the Purchase Price, and Buyer shall be solely responsible for and
bear all costs and expenses associated with any and all Alleged Title
Defects up to one percent (1%) of the Purchase Price. No payment shall
be due with respect to any Alleged Title Defect for which Seller, at
its option, delivers to Buyer an indemnity agreement in favor of Buyer
with respect to such Alleged Title Defect.
4.3 WAIVER. BUYER (ON BEHALF OF BUYER GROUP AND THEIR SUCCESSORS AND
ASSIGNS) HEREBY WAIVES FOR ALL PURPOSES ALL OBJECTIONS AND DEFECTS (WHETHER
KNOWN OR UNKNOWN) ASSOCIATED WITH THE TITLE TO THE PROPERTIES (INCLUDING ALLEGED
TITLE DEFECTS) EXCEPT FOR: (A) BUYER'S RIGHTS WITH RESPECT TO SELLER'S
144
REPRESENTATION SET FORTH IN SECTION 10.1.6, AND (B) ALLEGED TITLE DEFECTS RAISED
BY BUYER TO SELLER BY PROPER NOTICE WITHIN THE APPLICABLE TIME PERIOD SPECIFIED
IN, AND AS OTHERWISE REQUIRED by, ARTICLE 4.2, EXCEPT TO THE EXTENT SUCH ALLEGED
TITLE DEFECTS ARE SETTLED BY WRITTEN AGREEMENT OF THE PARTIES OR BY ARBITRATION,
AS PROVIDED IN ARTICLE 4.2.
4.4 TITLE BENEFITS. If Buyer or Seller discovers any Title Benefit on
or before Closing, such Party, as soon as practicable, but in any event prior to
Closing, shall deliver to the other Party a notice including a specific
description of the Title Benefit, and the Properties affected, and a value such
Party in good faith attributes to, the Title Benefit.
4.4.1 With respect to each Property affected by Title Benefits
reported under Article 4.4 above (or of which Buyer had knowledge and
should have reported under Article 4.4), then, if, prior to Closing,
Seller and Buyer have agreed upon the existence and value of the Title
Benefit or any disputes regarding the existence or the value of the
Title Benefit have been resolved by binding arbitration in accordance
with Article 18.1, the Purchase Price at Closing shall be increased by
an amount equal to the increase in the Exhibit "A" or "A-1", as
applicable, allocation for such Property caused by such Title Benefits.
4.4.2 If prior to Closing the Parties are unable to agree on a
resolution associated with any Title Benefit, the Parties shall Close
without Purchase Price adjustment; provided however, that within thirty
(30) Days after the Closing Date, either Party may initiate binding
arbitration in accordance with the provisions set forth in Article 18.1
to resolve the dispute. Within five (5) Days following the earlier to
occur of (i) Seller's and Buyer's agreement upon the existence and
value of the Title Benefit or (ii) resolution of any dispute regarding
the existence or value of the Title Benefit by binding arbitration in
accordance with Article 18.1, Buyer shall pay to Seller an amount equal
to the value of the Title Benefit, if any, as so agreed or determined
in arbitration.
ARTICLE V
CONDITION OF THE PROPERTIES
5.1 CONDITION OF THE PROPERTIES. AFTER EXECUTION AND DELIVERY OF THIS
AGREEMENT, SELLER SHALL PROVIDE BUYER ACCESS (DURING SELLER'S REGULAR BUSINESS
HOURS) TO SELLER-OPERATED PROPERTIES, AND SELLER WILL REQUEST PERMISSION FOR
BUYER TO GAIN ACCESS TO THIRD PARTY-OPERATED PROPERTIES, TO CONDUCT A VISUAL
INSPECTION OF THE SAME. As part of the visual inspection of each of the
Seller-operated Properties, Buyer or its agents and consultants may request
information and ask questions regarding the condition of the Properties and
Seller will attempt to provide the requested information and answer such
questions, although not necessarily during the site visit. Buyer may review all
pertinent Records of Seller to the extent pertaining to the Properties for the
purpose of detecting the presence of hazardous or toxic substances, pollutants
or other contaminants, environmental hazards, naturally occurring radioactive
material (NORM), and produced water or hydrocarbons contamination of the surface
or subsurface. The time(s) of review of such Records shall be mutually agreed by
the Parties and the place(s) for the review will be specified by Seller to
Buyer.
145
5.1.1 Such inspection shall be conducted in accordance with
the terms of the Confidentiality Agreement and subject to any releases
or other agreements required by the operator of the Properties. Buyer
may not operate equipment or conduct testing or sampling of materials
during such inspection unless Seller and Buyer otherwise agree in
writing. Buyer shall be responsible for arranging, at its own cost,
transportation to and from the Properties.
5.1.2 Buyer's access to the Properties shall be at Buyer's
sole risk and expense; and Buyer hereby releases Seller Group from and
shall fully indemnify, defend, protect and hold Seller Group harmless
from and against any and all Losses and Third Party Claims directly or
indirectly arising out of or connected with Buyer's inspection of the
Properties or travel to or from or presence on the Properties in
connection with the transactions contemplated by this Agreement To the
extent there is any conflict between this indemnity (including Article
19.14) and the indemnity in Section 10 of the Confidentiality
Agreement, the provisions of this indemnity prevail.
5.2 ALLEGED ADVERSE CONDITIONS. As soon as reasonably practical (and on
an ongoing basis), but no later than the earlier of (i) four (4) Business Days
before the Closing Date, or (ii) thirty (30) Days after the Parties have
executed this Agreement, Buyer shall notify Seller of any conditions that might
constitute Alleged Adverse Conditions. Buyer's notice of such conditions must
include (i) a complete description of each individual condition to which Buyer
takes exception (including any and all supporting documentation) and (ii) an
estimate of the costs Buyer in good faith attributes to bringing such condition
into compliance with applicable Environmental Laws. Seller and Buyer shall meet
from time to time to attempt to agree on a resolution of Alleged Adverse
Conditions.
5.2.1 If the Parties are unable to agree on resolution of any
Alleged Adverse Conditions on or before three (3) Days before the
Closing Date, Seller has the option, in its sole discretion, to either
(a) exclude the affected Properties from this Agreement and reduce the
Purchase Price by the positive value allocated to such Properties in
Exhibit "A" or "A-1", as applicable, if any, or increase the Purchase
Price by the negative value allocated to such Properties in Exhibit "A"
or "A- 1", applicable, if any, as applicable; (b) bring the Alleged
Adverse Condition into compliance with Environmental Laws (as in effect
as of the Effective Time); or (c) indemnify Buyer against such Alleged
Adverse Condition.
5.2.2 If Seller elects on or before the Closing Date to
attempt, at its sole cost, to bring any Alleged Adverse Condition into
compliance with Environmental Laws (as in effect as of the Effective
Time), Seller may, by notice to Buyer prior to Closing, elect to
continue attempting to remediate such condition to completion for up to
one hundred eighty (180) Days after the Closing Date. If Seller does
not remediate an Alleged Adverse Condition prior to Closing and fails
to provide notice that Seller elects to continue attempting to
remediate such Alleged Adverse Condition after Closing, or if such
146
notice is provided but such Alleged Adverse Condition is not remediated
on or before one hundred eighty (180) Days following Closing, Buyer
shall give Seller written notice of such failure or non-completion and
within five (5) Business Days following the earlier to occur of the
date that (i) Seller and Buyer agree in writing on the existence and
value of the Alleged Adverse Condition or (ii) resolution by binding
arbitration in accordance with Article 18.1 of any dispute regarding
the existence or value of the Alleged Adverse Condition, Seller shall
pay to Buyer an amount equal to the value of such Alleged Adverse
Condition, if any, as so agreed or determined in arbitration.
5.2.3 The cumulative adjustments and payments associated with
Alleged Adverse Conditions may not exceed the value allocated to the
affected Property in Exhibit "A" of "A-1", as applicable, but
notwithstanding the foregoing, if an Alleged Adverse Condition can be
remediated, the adjustments or payments with respect to that Alleged
Adverse Condition shall not exceed the reasonable costs of remediation.
If the Parties are unable to agree on a resolution associated with any
Alleged Adverse Conditions raised by Buyer before Closing, the Parties
shall Close without a Purchase Price adjustment; provided, however,
that within thirty (30) Days after the Closing Date, either Party may
initiate binding arbitration in accordance with the provisions set
forth in Article 18.1 to resolve the dispute.
5.2.4 Any claim with respect to an Alleged Adverse Condition
not referred to arbitration within thirty (30) Days after the Closing
Date as provided in Article 5.2.3 (or, with respect to any Alleged
Adverse Condition for which Seller provides notice that it will
continue attempting to cure after Closing, within thirty (30) Days
after the one hundred eighty (180) Day period cure period following
Closing has expired) shall be deemed waived for all purposes by Buyer.
5.2.5 Notwithstanding anything contained in this Agreement to
the contrary, Buyer shall not be entitled to an adjustment or other
remedy relating to any Alleged Adverse Condition unless and until the
aggregate costs associated with remedying all Alleged Adverse
Conditions so raised that are not remediated or indemnified against by
Seller exceeds two and one half percent (2.5%) of the Purchase Price,
and then only to the extent such aggregate cost exceeds two and one
half percent (2.5%) of the Purchase Price; and Buyer shall be solely
responsible for and bear all costs and expenses associated with any and
all Alleged Adverse Conditions up to two and one half percent (2.5%) of
the Purchase Price. No payment shall be due with respect to any Alleged
Adverse Condition for which Seller, at its option, delivers to Buyer an
indemnity agreement in favor of Buyer with respect to such Alleged
Adverse Condition.
5.3 WAIVER. BUYER (ON BEHALF OF BUYER GROUP AND THEIR SUCCESSORS AND
ASSIGNS) WAIVES FOR ALL PURPOSES ALL OBJECTIONS AND CLAIMS (WHETHER KNOWN OR
UNKNOWN) ASSOCIATED WITH ENVIRONMENTAL, PHYSICAL, CONTRACTUAL AND ANY OTHER
CONDITIONS (WHETHER SIMILAR OR DISSIMILAR) ON, AFFECTING OR PERTAINING TO THE
PROPERTIES (INCLUDING ALLEGED ADVERSE CONDITIONS) EXCEPT FOR (A) BUYER'S RIGHTS
WITH RESPECT TO SELLER'S INDEMNITY UNDER ARTICLE 8.4, (B) ALLEGED ADVERSE
CONDITIONS BUYER RAISED TO SELLER BY PROPER NOTICE WITHIN THE APPLICABLE TIME
PERIOD SPECIFIED IN, AND AS OTHERWISE REQUIRED BY, ARTICLE 5.2, OTHER THAN TO
THE EXTENT THAT SUCH ALLEGED ADVERSE CONDITIONS ARE SETTLED BY WRITTEN AGREEMENT
OF THE PARTIES OR BY ARBITRATION AS PROVIDED IN ARTICLE 5.2.2.
147
ARTICLE VI
ACCOUNTING
6.1 PRODUCTS. Merchantable oil and liquid hydrocarbon substances
associated with the Properties and stored in tanks and vessels will be gauged to
the bottom of the unloading flange as of the Effective Time. Buyer shall
purchase from Seller at Closing, all such oil and liquid hydrocarbon substances,
all at a price equal to the average price received by Seller from sales during
the month of March, 2006, for comparable oil and liquid hydrocarbon substances
from each field that is part of the Properties from which such substances were
produced, net of royalties, excise, severance and other production taxes, and
marketing costs (which include for purposes hereof, among other things, costs of
gathering, treating, processing, compression, and transportation), to the extent
such items are not treated as Charges under this Article 6. Oil and liquid
hydrocarbon substances in treating and separation equipment upstream of pipeline
connections, as of the Effective Time, will not be considered merchantable and
will become the property of Buyer at Closing. Actual amounts shall be accounted
for in the Final Accounting Settlement.
6.2 REVENUES, EXPENSES AND CAPITAL EXPENDITURES. Except as expressly
provided otherwise in this Agreement:
6.2.1 Seller is entitled to all its share of Operating
Revenues attributable to the Properties for the period prior to the
Effective Time and is responsible for all its share of Charges
attributable to the Properties for the period prior to the Effective
Time;
6.2.2 Seller also is entitled to a sum per month of One
Hundred Fifty Thousand Dollars (US $150,000) (prorated on a daily basis
for any partial month) as an agreed reimbursement in lieu of Seller's
actual overhead attributable to the Properties, including Seller's
personnel salaries, wages and employee benefits for the period from the
Effective Time through the Closing Date with such amount allocated to
the Properties as set forth on Schedule 6.2.2; and
6.2.3 Buyer is entitled to all Operating Revenues (except
producing, drilling and overhead charges payable to Seller or its
Affiliates where applicable and the sum per month specified in Article
6.2.2) attributable to the Properties for the period on and after the
Effective Time and is responsible for all Charges attributable to the
Properties for the period on and after the Effective Time.
Actual amounts, including any adjustments for Imbalances owed pursuant to
Article 12.7.2 shall be accounted for in the Final Accounting Settlement, unless
previously accounted for under the Transition Agreement. Whether Charges and
Operating Revenues are attributable to periods before or after the Effective
Time shall be determined in accordance with United States generally accepted
accounting principles (as published by the Financial Accounting Standards Board)
and Council of Petroleum Accountants Societies (COPAS) standards, based on the
accrual method of accounting. Notwithstanding anything contained in this
148
Agreement to the contrary, Buyer shall assume and be solely responsible for any
and all capital expenditures associated with the Properties that were disclosed
to Buyer prior to the date of this Agreement to the extent such capital
expenditures were incurred (or the obligation to incur the capital expenditures
was undertaken) by Seller within six (6) months prior to the Effective Time, and
the Final Accounting Statement shall include a reimbursement of Seller for any
such capital expenditures paid by Seller.
6.3 TAXES. Seller shall bear all taxes and assessments, including
excise taxes, severance or other production taxes, ad valorem taxes and any
other federal, state or local taxes or assessments attributable to ownership or
operation of the Properties prior to the Effective Time; and all deductions,
credits or refunds pertaining to the aforementioned taxes and assessments, no
matter when received, belong to Seller. Provided that Closing has occurred,
Buyer shall bear all taxes and assessments, including sales taxes, excise taxes,
severance or other production taxes, ad valorem taxes and any other federal,
state or local taxes and assessments attributable to ownership or operation of
the Properties on and after the Effective Time (excluding Seller's income taxes
from the Effective Time through Closing); and all deductions, credits and
refunds pertaining to the aforementioned taxes and assessments, no matter when
received, belong to Buyer. Ad valorem or property or other taxes based on
revenue from the Properties shall apply to the tax year for which the tax
rendition is issued and shall be prorated based on the percentage of the
assessment period occurring before and after the Effective Time. Actual amounts
shall be accounted for in the Final Accounting Settlement. Buyer shall be
responsible for and pay any and all Sales Tax on the transactions contemplated
by this Agreement. Each Party is responsible for filing any tax returns and
handling payment of any tax due under Law during the period when it holds title
to the Properties.
6.4 CREDITS. Provided Closing has occurred, Buyer shall reimburse
Seller for any and all prepaid insurance premiums, utility charges, rentals,
deposits and any other prepays (excluding taxes) applicable to the period on and
after the Effective Time that are attributable to the Properties. Actual amounts
shall be accounted for in the Final Accounting Settlement.
6.5 FINAL ACCOUNTING SETTLEMENT. As soon as reasonably practicable, but
no later than one hundred fifty (150) Days after the end of the Transition
Period, Seller shall deliver the Final Accounting Statement to Buyer. Buyer will
have reasonable access to supporting documentation as necessary to evaluate the
Final Accounting Statement, as Buyer shall reasonably request.
6.5.1 As soon as reasonably practicable, but no later than
thirty (30) Days after Buyer receives the Final Accounting Statement,
Buyer may deliver to Seller a written report containing any changes
Buyer proposes to such statement. Any adjustments covered by the Final
Accounting Statement as delivered by Seller to which Buyer fails to
object in the written report within the thirty (30) Day time period
shall be deemed correct and are final and binding on the Parties and
not subject to further review, audit or arbitration.
6.5.2 As soon as reasonably practicable, but no later than
thirty (30) Days after Seller receives Buyer's written report, the
Parties shall meet to attempt to agree on any adjustments to the Final
Accounting Statement. If the Parties fail to agree on final adjustments
within that thirty (30) Day period, either Party may submit the
149
disputed items to the Accounting Referee. The Parties shall direct the
Accounting Referee to resolve the disputes within thirty (30) Days
after its receipt of relevant materials pertaining to the dispute (and
the Parties agree to use their respective reasonable efforts to deliver
such materials promptly to the Accounting Referee).
6.5.3 The Final Account Statement, whether as agreed between
the Parties or as determined by a decision of the Accounting Referee,
shall be binding on and non-appealable by the Parties. The Accounting
Referee shall act as an expert for the limited purpose of determining
the specific disputed adjustments submitted by either Party and may not
award damages or penalties to either Party with respect to any matter.
Seller and Buyer shall share equally the Accounting Referee's fees and
expenses.
6.5.4 Any amounts owed by one Party to the other under the
Final Accounting Settlement shall be paid within thirty (30) Days after
the earlier of: (i) the date that the amounts are agreed by the
Parties, and (ii) the date that the Parties receive the Accounting
Referee's decision; and the revenues and expenses included in the Final
Accounting Settlement (including any and all Operating Revenues and
Charges received and booked by Seller prior to Seller's delivery of the
Final Accounting Statement to Buyer) shall be final and binding on the
Parties and not subject to further review, audit or arbitration.
6.6 POST-FINAL ACCOUNTING SETTLEMENT REVENUES.
6.6.1 Buyer shall pay Seller any and all Operating Revenues
received by Buyer (to the extent not accounted for in the Final
Accounting Settlement or the Transition Agreement) for the period prior
to the Effective Time, and
6.6.2 Seller shall pay Buyer any and all Operating Revenues
received by Seller (to the extent not accounted for in the Final
Accounting Settlement or the Transition Agreement) for the period after
the Effective Time, except producing, drilling and overhead payable to
Seller or its Affiliates and the sum per month specified in Article
6.2.2 both of which are to be retained by Seller.
6.6.3 The Party responsible for making payment in Article
6.6.1 or Article 6.6.2 shall make full payment to the other Party
within thirty (30) Days after receipt of the Operating Revenues in
question.
6.7 POST-FINAL ACCOUNTING SETTLEMENT EXPENSES.
6.7.1 Seller shall reimburse Buyer for any and all Charges
paid by Buyer (to the extent not accounted for in the Final Accounting
Settlement or the Transition Agreement) prior to the Effective Time;
and
150
6.7.2 Buyer shall reimburse Seller for any and all Charges
paid by Seller (to the extent not accounted for in the Final Accounting
Settlement or the Transition Agreement) after the Effective Time.
6.7.3 The Party responsible for making payment in Article
6.7.1 or Article 6.7.2 shall make full payment to the other Party
within thirty (30) Days after receipt of an applicable invoice and
proof that such invoice was paid for the Charges in question.
6.8 JOINT INTEREST AUDITS. Seller is entitled (at Seller's expense) to
resolve all joint interest audits or other contractual audits (whether or not be
conducting as of the Effective Time) that are applicable to any periods or
amounts for which Seller is responsible under this Agreement and to pay or
receive (as applicable) any amounts due or receivable attributable to Seller's
operation of, or current interest in, the Properties that are subject to such
audits.
ARTICLE VII
LOSS, CASUALTY AND CONDEMNATION
7.1 NOTICE OF LOSS. Seller shall promptly notify Buyer of all instances
of Casualty Loss that occur and become known to Seller between the date of this
Agreement and Closing.
7.2 CASUALTY LOSS. If, prior to Closing, any Properties are impacted by
a Casualty Loss, Seller and Buyer shall meet to attempt to agree on an
adjustment to the Purchase Price reflecting the reduction in value of the
Properties because of such Casualty Loss. For this purpose "reduction in value"
is based on the principle that Seller should generally bear the costs of
repairing the Properties to the state existing immediately prior to the Casualty
Loss, and if such repair results in equipment or facilities that are newer than
or upgraded from that which existed immediately prior to the Casualty Loss,
Buyer should bear a portion of such costs as is equitable, given the benefit to
Buyer of such newer or upgraded equipment or facilities. No adjustment
associated with a Casualty Loss will exceed the value allocated to the affected
Property in Exhibit "A" or "A-1 ", as applicable.
7.2.1 If the Parties are unable to agree on resolution of a
Casualty Loss, the Parties shall Close without a Purchase Price
adjustment; provided, however, that within thirty (30) Days after the
Closing Date, either Party may initiate binding arbitration in
accordance with Article 18.1 to resolve the dispute. ANY CLAIM WITH
RESPECT TO a Casualty LOSS NOT REFERRED TO ARBITRATION WITHIN THIRTY
(30) DAYS FOLLOWING CLOSING (OR, WITH RESPECT TO ANY CASUALTY LOSS FOR
WHICH SELLER PROVIDES NOTICE THAT IT WILL CONTINUE ATTEMPTING TO CURE
AFTER CLOSING, WITHIN THIRTY (30) DAYS AFTER THE ONE HUNDRED EIGHTY
(180) DAY PERIOD CURE PERIOD FOLLOWING CLOSING HAS EXPIRED) SHALL BE
DEEMED WAIVED BY BUYER FOR ALL PURPOSES.
7.2.2 Notwithstanding the foregoing, if the aggregate Casualty
Losses exceed fifty percent (50%) of the Purchase Price, either Party
may, by notice to the other at least one Business Day prior to Closing,
elect to terminate this Agreement under Article 17.1.6.
7.2.3 All insurance proceeds and other payments associated
with or attributable to any Casualty Losses shall be payable to the
Party that ultimately bears the costs for the repair of the damages for
which such insurance proceeds or payments are attributable.
151
ARTICLE VIII
ALLOCATION OF RESPONSIBILITIES AND INDEMNITIES
8.1 OPPORTUNITY FOR REVIEW. Each Party represents that it has had an
adequate opportunity to review all waiver, release, indemnity and defense
provisions in this Agreement, including the opportunity to submit the same to
legal counsel for review and advice. Based on the foregoing representation, the
Parties agree to the provisions set forth below.
8.2 SELLER'S NON-ENVIRONMENTAL INDEMNITY OBLIGATION. SUBJECT TO THE
LIMITATIONS SET FORTH IN THIS AGREEMENT, SELLER SHALL PROTECT, DEFEND, INDEMNIFY
AND HOLD BUYER GROUP HARMLESS FROM AND AGAINST ALL NON-ENVIRONMENTAL CLAIMS TO
THE EXTENT RELATING TO, ARISING OUT OF, OR CONNECTED WITH, DIRECTLY OR
INDIRECTLY, SELLER'S OWNERSHIP OR OPERATION OF THE PROPERTIES OR ANY PART
THEREOF PRIOR TO THE EFFECTIVE TIME, INCLUDING NON-ENVIRONMENTAL CLAIMS RELATING
TO: (A) INJURY OR DEATH OF ANY PERSONS WHOMSOEVER, (B) PAYMENT OF ROYALTIES,
OVERRIDING ROYALTIES OR OTHER BURDENS ON PRODUCTION; (C) DAMAGES TO OR LOSS OF
ANY PROPERTY, (D) BREACH OF CONTRACT, (E) COMMON LAW CAUSES OF ACTION SUCH AS
NEGLIGENCE, STRICT LIABILITY, NUISANCE OR TRESPASS, AND (F) FAULT IMPOSED BY LAW
OR OTHERWISE.
8.2.2 SUBJECT TO THE LIMITATIONS SET FORTH IN THIS AGREEMENT,
SELLER SHALL PROTECT, DEFEND, INDEMNIFY AND HOLD BUYER GROUP HARMLESS
FROM AND AGAINST ALL LOSSES OF BUYER RESULTING FROM ANY BREACH by
SELLER OF (A) ANY OF ITS REPRESENTATIONS AND/OR WARRANTIES SET FORTH IN
ARTICLE 10 OR THE CORRESPONDING REPRESENTATIONS SET FORTH IN THE
CERTIFICATE DELIVERED BY SELLER TO BUYER PURSUANT TO ARTICLE 16.2.2 OR
(B) ITS COVENANTS CONTAINED IN THIS AGREEMENT.
8.2.3 NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS
AGREEMENT, SELLER RETAINS SOLE RESPONSIBILITY AND LIABILITY FOR ALL
MATTERS EXPRESSLY RETAINED BY SELLER PURSUANT TO ARTICLE 12.3, AND
SELLER RELEASES BUYER GROUP FROM AND SHALL PROTECT, DEFEND, INDEMNIFY
AND HOLD BUYER GROUP HARMLESS FROM AND AGAINST ALL NON-ENVIRONMENTAL
CLAIMS AND ENVIRONMENTAL CLAIMS RELATING TO SUCH MATTERS TO THE EXTENT
RELATING TO, ARISING OUT OF, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY,
SUCH MATTERS TO THE EXTENT SUCH MATTERS RELATE TO THE PERIOD PRIOR TO
THE EFFECTIVE TIME. Buyer shall use its reasonable efforts to cooperate
with Seller in all respects in connection Seller's retention and
defense of such matters.
8.3 LIMITATIONS ON SELLER'S NON-ENVIRONMENTAL AND OTHER INDEMNITIES.
NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY, SELLER HAS NO
OBLIGATION UNDER THIS AGREEMENT OR OTHERWISE TO PROTECT, DEFEND, INDEMNIFY, AND
HOLD BUYER GROUP HARMLESS FROM AND AGAINST ANY ONE OR MORE OF THE FOLLOWING:
8.3.1 NON-ENVIRONMENTAL CLAIMS UNDER 8.2.1 FOR WHICH BUYER HAS
NOT PROVIDED SELLER NOTICE IN ACCORDANCE WITH ARTICLE 8.7 WITHIN
TWENTY-FOUR (24) MONTHS AFTER THE CLOSING DATE (AND BUYER ASSUMES AND
IS SOLELY RESPONSIBLE FOR ALL NON-ENVIRONMENTAL CLAIMS NOT SO RAISED
WITHIN SUCH TWENTY-FOUR (24) MONTH PERIOD);
152
8.3.2 LOSSES UNDER ARTICLE 8.2.2 RESULTING FROM SELLER'S
BREACH OF (A) ITS REPRESENTATIONS AND/OR WARRANTIES SET FORTH IN
ARTICLE 10 OR (B) ITS COVENANTS UNDER THIS AGREEMENT, FOR WHICH IN THE
CASE OF (A) AND (B) BUYER HAS NOT PROVIDED SELLER NOTICE IN ACCORDANCE
WITH ARTICLE 8.7 WITHIN THE TIME SPECIFIED IN ARTICLE 19.6; AND
8.3.4 NON-ENVIRONMENTAL CLAIMS AND LOSSES COVERED BY ARTICLE
8.2.1 AND ARTICLE 8.2.2 THAT, IN THE AGGREGATE, DO NOT EXCEED ONE
PERCENT (1%) OF THE PURCHASE PRICE, AND BUYER ASSUMES AND IS SOLELY
RESPONSIBLE FOR ALL NON-ENVIRONMENTAL.
8.4 SELLER'S ENVIRONMENTAL INDEMNITY OBLIGATION. SUBJECT TO THE
LIMITATIONS SET FORTH IN THIS AGREEMENT, SELLER SHALL PROTECT, DEFEND,
INDEMNIFY AND HOLD BUYER GROUP HARMLESS FROM AND AGAINST ALL ENVIRONMENTAL
CLAIMS TO THE EXTENT RELATING TO, ARISING OUT of, OR CONNECTED WITH, DIRECTLY
OR INDIRECTLY, SELLER'S OWNERSHIP OR OPERATION OF THE PROPERTIES OR ANY PART
THEREOF PRIOR TO THE EFFECTIVE TIME.
8.5 LIMITATIONS ON SELLER'S ENVIRONMENTAL INDEMNITIES. NOTWITHSTANDING
ANYTHING IN THIS AGREEMENT TO THE CONTRARY, SELLER HAS NO OBLIGATION UNDER THIS
AGREEMENT OR OTHERWISE TO PROTECT, DEFEND, INDEMNIFY, AND HOLD BUYER GROUP
HARMLESS FROM AND AGAINST ANY ONE OR MORE OF THE FOLLOWING:
8.5.1 ENVIRONMENTAL CLAIMS (EXCEPT FOR ANY SUCH MATTERS
RETAINED BY SELLER PURSUANT TO ARTICLE 12.3) FOR WHICH BUYER HAS NOT
PROVIDED SELLER WITH NOTICE IN ACCORDANCE WITH ARTICLE 8.7 WITHIN
TWELVE (12) MONTHS AFTER THE CLOSING DATE; AND BUYER ASSUMES AND IS
SOLELY RESPONSIBLE FOR ANY AND ALL ENVIRONMENTAL CLAIMS NOT RAISED
WITHIN SUCH TWELVE (12) MONTH PERIOD; AND
8.5.2 ENVIRONMENTAL CLAIMS (EXCEPT FOR ANY SUCH MATTERS
RETAINED BY SELLER PURSUANT TO ARTICLE 12.3) IN AGGREGATE UP TO ONE
PERCENT (1%) OF THE PURCHASE PRICE, AND BUYER ASSUMES AND IS SOLELY
RESPONSIBLE FOR ANY AND ALL ENVIRONMENTAL CLAIMS UP TO ONE PERCENT (1%)
OF THE PURCHASE PRICE.
8.6 BUYER'S INDEMNITY OBLIGATION. EXCEPT AS PROVIDED ELSEWHERE IN THIS
AGREEMENT, BUYER RELEASES SELLER GROUP FROM AND SHALL PROTECT, DEFEND, INDEMNIFY
AND HOLD SELLER GROUP HARMLESS FROM AND AGAINST AND ASSUMES
(i) ALL LOSSES AND THIRD PARTY CLAIMS RELATING TO, ARISING OUT
OF, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY, OWNERSHIP OR OPERATION
OF THE PROPERTIES OR ANY PART THEREOF PRIOR TO THE EFFECTIVE TIME (NO
MATTER WHEN ASSERTED) FOR WHICH SELLER'S INDEMNITY AND DEFENSE
OBLIGATIONS IN ARTICLE 8.2 OR ARTICLE 8.4 HAVE CEASED, TERMINATED (IN
ACCORDANCE WITH ARTICLE 8.3, ARTICLE 8.5 OR OTHERWISE) OR DO NOT
APPLY,
(ii) ALL THIRD PARTY CLAIMS ARISING AGAINST SELLER GROUP FROM
BUYER'S ALLOCATION OF THE PURCHASE PRICE FOR THE PURPOSES OF ARTICLE
3,
153
(iii) ALL LOSSES OF SELLER RESULTING FROM ANY BREACH by BUYER OF
(A) ANY OF ITS REPRESENTATIONS AND/OR WARRANTIES SET FORTH IN ARTICLE
11 OR THE CORRESPONDING REPRESENTATIONS SET FORTH IN THE CERTIFICATE
DELIVERED by BUYER TO SELLER PURSUANT TO ARTICLE 16.3.3 OR (B) ITS
COVENANTS CONTAINED IN THIS AGREEMENT,
(iv) ALL LOSSES AND THIRD PARTY CLAIMS RELATING TO, ARISING OUT
OF, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY, OWNERSHIP OR OPERATION
OF THE PROPERTIES OR ANY PART THEREOF ON AND AFTER THE EFFECTIVE TIME
(NO MATTER WHEN ASSERTED),
AND IN THE CASE OF (i), (ii) (iii) AND (iv) ABOVE, INCLUDING LOSSES OR THIRD
PARTY CLAIMS RELATING TO (A) INJURY OR DEATH OF ANY PERSONS WHOMSOEVER, (B)
PAYMENT OF ROYALTIES, OVERRIDING ROYALTIES OR OTHER BURDENS ON PRODUCTION; (C)
DAMAGES TO OR LOSS OF ANY PROPERTY, (D) BREACH OF CONTRACT, (E) COMMON LAW
CAUSES OF ACTION SUCH AS NEGLIGENCE, STRICT LIABILITY, NUISANCE OR TRESPASS, (F)
FAULT IMPOSED BY LAW OR OTHERWISE AND/OR (G) ENVIRONMENTAL CLAIMS.
8.7 NOTICE OF THIRD PARTY CLAIMS. If a Third Party Claim or Loss is
asserted against a Party for which the other Party may have an obligation of
payment, indemnity and/or defense (whether under this Article 8 or any other
provision of this Agreement), the Party seeking payment or indemnification
("INDEMNIFIED PARTY") shall give the Party from which the Indemnified Party
seeks payment or indemnification ("INDEMNIFYING PARTY") prompt written notice of
the Third Party Claim or Loss, setting forth the particulars associated with the
Third Party Claim or Loss (including a copy of the written Third Party Claim, if
any) as then known by the Indemnified Party ("CLAIM NOTICE").
8.8 DEFENSE OF THIRD PARTY CLAIMS. Within thirty (30) Days after the
Indemnifying Party receives a Claim Notice, the Indemnifying Party shall notify
the Indemnified Party advising whether or not the Indemnifying Party will assume
responsibility for defense (if applicable) and payment of the Third Party Claim
or Loss. In connection with any Third Party Claim, the Indemnified Party is
authorized, prior to and during such thirty (30) day period, to file any motion,
pleading or other answer that it deems necessary or appropriate to protect its
interests, or those of the Indemnifying Party, provided that it is not
prejudicial to the Indemnifying Party. If the Indemnifying Party elects not to
assume responsibility for defense and payment of the Third Party Claim, the
Indemnified Party may defend against, or enter into any settlement with respect
to, the Third Party Claim as it deems appropriate without relieving the
Indemnifying Party of any indemnification obligations the Indemnifying Party may
have with respect to such Third Party Claim. The Indemnifying Party's failure to
respond in writing to a Claim Notice within the thirty (30) Day period shall be
deemed an election by the Indemnifying Party not to assume responsibility for
defense (if applicable) and payment of the Third Party Claim or Loss, as
applicable. If the Indemnifying Party elects to assume responsibility for
defense (if applicable) and payment of the Third Party Claim or Loss, as
applicable: (a) the Indemnifying Party shall defend the Indemnified Party
against the Third Party Claim with counsel of the Indemnifying Party's choice
(reasonably acceptable to Indemnified Party which shall cooperate with the
Indemnifying Party in all reasonable respects in such defense), (b) the
154
Indemnifying Party shall pay any judgment entered or settlement with respect to
such Third Party Claim, (c) the Indemnifying Party shall not consent to entry of
any judgment or enter into any settlement with respect to the Third Party Claim
that (i) does not include a provision whereby the plaintiff or claimant in the
matter releases the Indemnified Party from all liability with respect to the
Third Party Claim or (ii) contains terms that may materially and adversely
affect the Indemnified Party (other than as a result of money damages covered by
the indemnity), (d) the Indemnified Party shall not consent to entry of any
judgment or enter into any settlement with respect to the Third Party Claim
without the Indemnifying Party's prior written consent and (e) pay the
Indemnified Party the costs and expenses resulting from the Loss. In all
instances the Indemnified Party may employ separate counsel and participate in
defense of a Third Party Claim, but the Indemnified Party shall bear all fees
and expenses of counsel employed by the Indemnified Party.
8.9 DUPLICATION OF REMEDIES. In no event shall either Party be entitled
to duplicate compensation or other remedies with respect to any matter
(including any Third Party Claim. Loss or any breach of a representation,
warranty or agreement herein) asserted under the terms of this Agreement or in
connection with the transaction contemplated hereby, even though such matter may
be asserted under more than one provision of this Agreement or otherwise.
8.10 WAIVER OF CERTAIN DAMAGES. EACH PARTY IRREVOCABLY WAIVES AND
AGREES NOT TO SEEK INDIRECT, CONSEQUENTIAL, LOSS OF PROFITS, PUNITIVE OR
EXEMPLARY DAMAGES OF ANY kind IN CONNECTION WITH ANY DISPUTE ARISING OUT OF OR
RELATED TO THIS AGREEMENT (INCLUDING THE BREACH THEREOF) OR THE TRANSACTIONS
CONTEMPLATED HEREBY. FOR THE AVOIDANCE OF DOUBT, THIS ARTICLE 8.10 DOES NOT
DIMINISH OR OTHERWISE AFFECT THE PARTIES' RIGHTS AND OBLIGATIONS TO BE
INDEMNIFIED AGAINST, AND PROVIDE INDEMNITY FOR, INDIRECT, CONSEQUENTIAL, LOSS OF
PROFITS, PUNITIVE OR EXEMPLARY DAMAGES AWARDED TO ANY THIRD PARTY FOR WHICH
INDEMNIFICATION IS PROVIDED IN THIS AGREEMENT OR SELLER'S RIGHT TO RECEIVE
LIQUIDATED DAMAGES, INCLUDING THE PERFORMANCE DEPOSIT, PURSUANT TO THE TERMS OF
ARTICLE 17.2.
8.11 EXCLUSIVE REMEDIES. NOTWITHSTANDING ANYTHING TO THE CONTRARY
CONTAINED IN THIS AGREEMENT, (I) ARTICLES 8.2 AND 8.4 AND (II) ANY INDEMNITY
AGREEMENT GIVEN BY SELLER FOR ANY ALLEGED TITLE DEFECT PURSUANT TO ARTICLE 4.2.5
OR ALLEGED ADVERSE CONDITION PURSUANT TO ARTICLE 5.2.5 SET FORTH BUYER'S
EXCLUSIVE REMEDIES AGAINST SELLER AND ITS AFFILIATES WITH RESPECT TO THE
TRANSACTIONS CONTEMPLATED HEREBY, INCLUDING BREACHES OF THE REPRESENTATIONS,
WARRANTIES, COVENANTS AND AGREEMENTS OF SELLER CONTAINED IN THIS AGREEMENT.
EXCEPT FOR THE REMEDIES CONTAINED IN (A) ARTICLE 8.2 AND 8.4, (B) ANY INDEMNITY
AGREEMENT GIVEN BY SELLER FOR ANY ALLEGED TITLE DEFECT PURSUANT TO ARTICLE 4.2.5
OR ALLEGED ADVERSE CONDITION PURSUANT TO ARTICLE 5.2.5, EFFECTIVE AS OF CLOSING.
BUYER, ON BEHALF OF BUYER GROUP, HEREBY RELEASES, REMISES AND FOREVER DISCHARGES
SELLER GROUP FROM ANY AND ALL LOSSES WHICH BUYER GROUP MIGHT NOW OR SUBSEQUENTLY
MAY HAVE, BASED ON, RELATING TO OR ARISING OUT OF THIS AGREEMENT, THE OWNERSHIP,
USE OR OPERATION OF THE PROPERTIES, OR THE CONDITION, QUALITY, STATUS OR NATURE
OF THE PROPERTIES, INCLUDING RIGHTS TO CONTRIBUTION UNDER THE COMPREHENSIVE
ENVIRONMENTAL RESPONSE, COMPENSATION, AND LIABILITY ACT OF 1980, AS AMENDED,
BREACHES OF STATUTORY OR IMPLIED WARRANTIES, NUISANCE OR OTHER TORT ACTIONS,
RIGHTS TO PUNITIVE DAMAGES, COMMON LAW RIGHTS OF CONTRIBUTION, AND RIGHTS UNDER
INSURANCE MAINTAINED BY SELLER OR ANY OF ITS AFFILIATES, EXCLUDING, HOWEVER, ANY
(I) CONTRACTUAL RIGHTS EXISTING AS OF THE DATE HEREOF (APART FROM THIS
155
AGREEMENT) BETWEEN (A) BUYER OR ANY OF BUYER'S AFFILIATES, ON THE ONE HAND AND
(B) SELLER OR ANY OF SELLER'S AFFILIATES, ON THE OTHER HAND, UNDER CONTRACTS (IF
ANY) BETWEEN THEM RELATING TO THE PROPERTIES AND (II) ANY CONTRACT ENTERED INTO
ON OR AFTER THE CLOSING BETWEEN SUCH PARTIES AND RELATING TO THE PROPERTIES.
8.12 OTHER CONTRACTS BETWEEN THE PARTIES. THE PARTIES ACKNOWLEDGE THAT
BUYER OR AN AFFILIATE OF BUYER CURRENTLY MAY OWN INTERESTS IN CERTAIN OF THE
LANDS, LEASES AND OTHER ASSETS INCLUDED IN THE PROPERTIES. THE ASSUMPTION,
PROTECTION, DEFENSE, INDEMNIFICATION AND RELEASES IN THIS AGREEMENT ARE NOT
INTENDED TO WAIVE OR MODIFY IN ANY MANNER ANY EXISTING CONTRACTUAL RIGHTS OR
OBLIGATIONS BETWEEN ANY MEMBER OF SELLER GROUP AND ANY MEMBER OF BUYER GROUP
UNDER OPERATING AGREEMENTS, UNIT AGREEMENTS, SERVICE CONTRACTS OR OTHER
AGREEMENTS TO THE EXTENT ANY SUCH FOREGOING AGREEMENT IS NOT ENTERED INTO AND
DELIVERED IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED
HEREUNDER, AND THE PROTECTION, DEFENSE, INDEMNIFICATION AND RELEASES IN THIS
ARTICLE 8 SHALL NOT RELEASE OR ELIMINATE ANY OF BUYER'S OBLIGATIONS AS A
CO-OWNER IN ANY LANDS, LEASES AND OTHER ASSETS INCLUDED IN THE PROPERTIES.
ARTICLE IX
DISCLAIMERS
9.1 DISCLAIMERS.
9.1.1 BUYER ACKNOWLEDGES THAT CERTAIN OF THE PROPERTIES HAVE
SUSTAINED HURRICANE DAMAGE AS RECENTLY AS 2005, AND HAS SATISFIED
ITSELF AS TO THE PRESENT CONDITION OF THE PROPERTIES.
9.1.2 EXCEPT AS EXPRESSLY STATED IN ARTICLE 10.1.6 IN THIS
AGREEMENT:
(A) AT CLOSING SELLER SHALL ASSIGN THE PROPERTIES TO BUYER
"AS-IS, WHERE-IS", AND WITH ALL FAULTS AND DEFECTS IN THEIR PRESENT
CONDITION AND STATE OF REPAIR, WITHOUT RECOURSE, EVEN FOR THE RETURN OF
THE PURCHASE PRICE, AND
(B) SELLER DISCLAIMS ANY AND ALL REPRESENTATIONS AND
WARRANTIES WITH RESPECT TO THE PROPERTIES, EXPRESS, STATUTORY, IMPLIED
OR OTHERWISE, INCLUDING ANY WARRANTY AS TO (i) TITLE, (II) COMPLIANCE
WITH LAWS, (III) EXISTENCE OF ANY AND ALL PROSPECTS OR RECOMPLETION
OPPORTUNITIES, (IV) GEOGRAPHIC, GEOLOGIC OR GEOPHYSICAL
CHARACTERISTICS, (V) EXISTENCE, QUALITY, QUANTITY OR RECOVERABILITY OF
HYDROCARBON SUBSTANCES, (VI) ABILITY TO PRODUCE, INCLUDING PRODUCTION
OR DECLINE RATES, (VII) COSTS, EXPENSES, REVENUES, RECEIPTS, PRICES,
ACCOUNTS RECEIVABLE OR ACCOUNTS PAYABLE, (VIII) CONTRACTUAL, ECONOMIC
OR FINANCIAL INFORMATION AND DATA, (IX) CONTINUED FINANCIAL VIABILITY,
INCLUDING PRESENT OR FUTURE VALUE OR ANTICIPATED INCOME OR PROFITS, (X)
ENVIRONMENTAL OR PHYSICAL CONDITION (SURFACE AND SUBSURFACE, (XI)
FEDERAL, STATE, OR LOCAL INCOME OR OTHER TAX CONSEQUENCES, (X) ABSENCE
OF PATENT OR LATENT DEFECTS, (XII) SAFETY, (XIII) STATE OF REPAIR,
(XIV) MERCHANTABILITY, (XV) FITNESS FOR A PARTICULAR PURPOSE AND (XVI)
CONFORMITY TO MODELS OR SAMPLES OF MATERIALS; AND BUYER (ON BEHALF OF
BUYER GROUP AND THEIR SUCCESSORS AND ASSIGNS) IRREVOCABLY WAIVES ANY
156
AND ALL CLAIMS THEY MAY HAVE AGAINST SELLER GROUP ASSOCIATED WITH (I)
THROUGH (XVI) HEREINABOVE, EXCEPT FOR THE BUYER'S RIGHT TO ASSERT THE
EXISTENCE OF ALLEGED ADVERSE CONDITIONS IN ACCORDANCE WITH ARTICLE 5.2
AND BUYER'S RIGHT TO CLAIM BREACH OF REPRESENTATIONS AND WARRANTIES
WITHIN THE TIME PERIOD SPECIFIED IN ARTICLE 19.6.
9.2 DISCLAIMER OF STATEMENTS AND INFORMATION, SELLER EXPRESSLY
DISCLAIMS ANY AND ALL LIABILITY AND RESPONSIBILITY FOR AND ASSOCIATED WITH THE
QUALITY, ACCURACY, COMPLETENESS OR MATERIALITY OF INFORMATION, DATA AND
MATERIALS SHOWN TO OR FURNISHED (ELECTRONICALLY, ORALLY, IN WRITING OR ANY OTHER
MEDIUM AND WHETHER OR NOT SHOWN OR FURNISHED BEFORE OR AFTER EXECUTION OF THIS
AGREEMENT) TO BUYER GROUP AND ASSOCIATED WITH THE PROPERTIES OR THE TRANSACTIONS
CONTEMPLATED BY THIS AGREEMENT; AND BUYER (ON BEHALF OF BUYER GROUP AND THEIR
SUCCESSORS AND ASSIGNS) IRREVOCABLY WAIVES ANY AND ALL CLAIMS THEY MAY HAVE
AGAINST SELLER GROUP ASSOCIATED WITH THE SAME.
ARTICLE X
SELLER'S REPRESENTATIONS AND WARRANTIES
10.1 SELLER'S REPRESENTATIONS AND WARRANTIES. Seller represents and
warrants to Buyer that:
10.1.1 ORGANIZATION AND GOOD STANDING. Seller is a corporation
duly organized, validly existing and in good standing under the Laws of
the State of Delaware and has all requisite corporate power and
authority to own the Properties. Seller is duly licensed or qualified
to do business as a foreign corporation and is in good standing in all
jurisdictions in which the Properties are located.
10.1.2 CORPORATE AUTHORITY; AUTHORIZATION OF AGREEMENT. Seller
has all requisite corporate power and authority to execute and deliver
this Agreement, to consummate the transactions contemplated by this
Agreement and to perform all obligations placed on Seller in this
Agreement. This Agreement, when executed and delivered by Seller,
constitutes the valid and binding obligation of Seller, enforceable
against it in accordance with its terms, except as such enforceability
may be limited by bankruptcy, insolvency or other Laws relating to or
affecting the enforcement of creditors' rights and general principles
of equity (regardless of whether such enforceability is considered in a
proceeding at law or in equity).
10.1.3 No VIOLATIONS. Subject to the receipt of all consents,
approvals and waivers from Third Parties in connection with the
transactions contemplated hereby and assuming compliance with the
provisions of the HSR Act (if required) in connection with such
transactions, Seller's execution and delivery of this Agreement and
consummation of the transactions contemplated by this Agreement will
not:
(a) conflict with or require consent of any person or entity
under any terms, conditions or provisions of Seller's certificate of
incorporation or bylaws;
(b) violate any provision of, or require any consent or
approval under any Law applicable to Seller (except for consents and
approvals of governmental or tribal entities or authorities customarily
obtained subsequent to transfer of title); or
157
(c) result in the creation or imposition of any lien or
encumbrance on any of the Properties;
except as would not have a Material Adverse Effect.
10.1.4 LITIGATION. Except as set forth in Exhibit "C" or
otherwise disclosed to Buyer in writing by Seller before the Closing
Date, there are no litigation, claims, actions or other proceedings by
a Third Party or before any governmental entity or authority that are
pending against Seller or, to Seller's knowledge, threatened against
Seller that would (in either case) have a Material Adverse Effect.
10.1.5 BANKRUPTCY. There are no bankruptcy or receivership
proceedings pending against, being contemplated by or, to Seller's
knowledge, threatened against Seller.
10.1.6 SPECIAL WARRANTY OF TITLE. As of Closing, Seller shall
warrant title to the Properties against adverse claims of title by,
through or under Seller but not otherwise, subject to the Permitted
Encumbrances.
10.1.7 TAXES. To the best of Seller's knowledge, all ad
valorem, property, production, severance, windfall profits, excise and
similar taxes and assessments based on or measured by the ownership of
property or the production of hydrocarbons or the receipt of proceeds
therefrom on the Properties that have become due and payable through
the Effective Date, have been properly paid or are being contested in
good faith.
10.1.8 CALLS. Except as provided herein, no person has any
call upon, option to purchase, or similar rights with respect to any
portion of the production from the Properties.
10.1.9 INFORMATION. Seller either owns or otherwise has the
right to disclose all of the data set forth in the Merrill Corporation
electronic data room created in connection with the transaction
contemplated by this Agreement.
10.1.10 COMPLIANCE WITH LAWS. To the Knowledge of Seller and
with respect to the Properties, Seller is in compliance with all Laws,
except for any failures to comply as would not have a Material Adverse
Effect.
ARTICLE XI
BUYER'S REPRESENTATIONS AND WARRANTIES
11.1 BUYER'S REPRESENTATIONS AND WARRANTIES. Buyer represents and
warrants to Seller that:
11.1.1 ORGANIZATION AND GOOD STANDING. Buyer is a limited
liability company duly organized, validly existing and in good standing
under the Laws of Texas and has all requisite power and authority to
158
own the Properties. Buyer is duly licensed or qualified to do business
as a foreign limited liability company and is in good standing in all
jurisdictions in which the Properties are located.
11.1.2 CORPORATE AUTHORITY: AUTHORIZATION OF AGREEMENT. Buyer
has all requisite [corporate] power and authority to execute and
deliver this Agreement, to consummate the transactions contemplated by
this Agreement and to perform all of the obligations placed on Buyer in
this Agreement. This Agreement, when executed and delivered by Buyer,
constitutes the valid and binding obligation of Buyer, enforceable
against it in accordance with its terms, except as such enforceability
may be limited by bankruptcy, insolvency or other Laws relating to or
affecting the enforcement of creditors' rights and general principles
of equity (regardless of whether such enforceability is considered in a
proceeding at law or in equity).
11.1.3 No VIOLATIONS. Assuming compliance with the provisions
of the HSR Act (if required) in connection with the transactions
contemplated by this Agreement, Buyer's execution and delivery of this
Agreement and consummation of the transactions contemplated by this
Agreement will not:
(a) conflict with or require the consent of any person or
entity under any of the terms, conditions or provisions of Buyer's
certificate of incorporation or bylaws; or
(b) violate any provision of, or require any consent or
approval under any Law applicable to Buyer (except for consents and
approvals of governmental or tribal entities or authorities customarily
obtained subsequent to transfer of title).
11.1.4 SEC DISCLOSURE. Buyer is acquiring the Properties for
its own account for use in its trade or business, and not with a view
toward or for sale associated with any distribution thereof, nor with
any present intention of making a distribution thereof within the
meaning of the Securities Act of 1933, as amended.
11.1.5 LITIGATION. There is no litigation, action or
proceeding pending against Buyer or, to Buyer's knowledge, threatened
against Buyer that would prevent timely consummation of the
transactions contemplated by this Agreement.
11.1.6 INDEPENDENT EVALUATION. Buyer is sophisticated in
evaluation, purchase, ownership and operation of oil and gas properties
and related facilities similar to the Properties, and in making its
decision to enter into this Agreement and to consummate the
transactions contemplated herein, Buyer (a) relied solely on its own
independent investigation and evaluation of the Properties and the
advice of its engineers, contractors, geological and geophysical
advisors, lawyers and accountants and not on any comments, statements,
reports, projections or other documents or materials provided by or for
Seller or its agents, whether before or after execution of this
Agreement, and (b) satisfied itself as to the environmental, physical
and other condition of, and contractual arrangements affecting, the
Properties.
159
11.1.7 BANKRUPTCY. There are no bankruptcy or receivership
proceedings pending against, being contemplated by or, to Buyer's
knowledge, threatened against Buyer.
11.1.8 FINANCIAL ASSURANCES. Buyer has (or as of Closing will
have) available financial resources to discharge all obligations
assumed by Buyer hereunder.
11.1.9 CONSENTS. There are no consents that would be
applicable in connection with the consummation by Buyer of the
transactions contemplated by this Agreement.
ARTICLE XII
ADDITIONAL COVENANTS
12.1 SUBSEQUENT OPERATIONS. SELLER MAKES NO REPRESENTATIONS OR
WARRANTIES TO BUYER AS TO TRANSFERABILITY OR ASSIGNABILITY OF OPERATORSHIP OF
ANY PROPERTIES THAT SELLER CURRENTLY OPERATES. Rights and obligations associated
with operatorship of the Properties are governed by operating and similar
agreements covering the Properties and will be decided in accordance with the
terms of such agreements.
12.2 RIGHTS OF NON-EXCLUSIVE USE. If Closing occurs, Buyer, to the
extent it has the authority to do so, shall grant to Seller (and, if requested
by Seller, to Seller's Affiliates and/or Seller's and its Affiliates'
contractors) from time to time, as requested by Seller a non-exclusive cost-free
right-of-way, surface use or other right on, over, under and through the
Properties (including pipeline, utility and road usage rights, facilities
sharing arrangement and all reasonable rights of use and ingress and egress) as
appropriate or convenient for Seller and its Affiliates (i) to conduct
operations on, over, under and across the Properties in connection with
properties not being conveyed from Seller to Buyer in the transactions covered
by this Agreement and (ii) to exercise Seller's retained rights and retained
obligations under this Agreement. At Seller's request, either at or after
Closing, Buyer shall execute instruments in recordable form that Seller deems
appropriate to further delineate or evidence the rights granted herein.
12.3 BUYER'S ASSUMPTION OF OBLIGATIONS.
If Closing occurs, and subject only to Seller's indemnities in Article
8.2, 8.4 and 19.3.1 and the retention of liability set forth in the next
following sentence, Buyer hereby assumes, shall pay and shall timely perform and
discharge all of Seller's duties and obligations associated with the Properties
arising prior to, on or after the Closing (including any and all contractual
duties and obligations arising therefrom) (collectively, the "ASSUMED
OBLIGATIONS"), and in fulfilling these obligations, Buyer shall comply with all
Laws. In addition to Seller's indemnity obligations under this Agreement, Seller
shall retain sole responsibility for prosecuting or defending, as the case may
be, all litigation matters with respect to the Properties that are pending as of
the date of this Agreement and all liabilities for costs, judgments, settlements
and otherwise associated therewith to the extent the foregoing litigation and
liabilities relate to any period prior to the Effective Time.
160
12.4 ASBESTOS AND NORM. The Properties may currently or have in the
past contained asbestos and NORM, and special procedures associated with
assessment, remediation, removal, transportation or disposal of asbestos and
NORM may be necessary. NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO
THE CONTRARY, INCLUDING ARTICLE 5 AND ARTICLE 8, IF CLOSING OCCURS:
12.4.1 Buyer accepts sole responsibility for and agrees to pay
any and all costs and expenses associated with assessment, remediation,
removal, transportation and disposal of asbestos and NORM associated
with the Properties, and may not claim the fact that assessment,
remediation, removal, transportation or disposal of asbestos and NORM
are not complete or that additional costs and expenses are required in
connection with assessment, remediation, removal, transportation or
disposal of asbestos and NORM as an Alleged Adverse Condition or a
breach of Seller's representations or warranties under this Agreement
or the basis for any other redress against Seller or its Affiliates,
and Buyer (on behalf of Buyer Group and their successors and assigns)
irrevocably waives any and all Losses and Third Party Claims they may
have against Seller Group associated with the same; and
12.4.2 BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY
PROTECT, DEFEND, INDEMNIFY, AND HOLD SELLER GROUP HARMLESS FROM AND
AGAINST ANY AND ALL LOSSES AND THIRD PARTY CLAIMS RELATING TO, ARISING
OUT OF, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY, THE ASSESSMENT,
REMEDIATION, REMOVAL, TRANSPORTATION AND DISPOSAL OF ASBESTOS AND NORM
ASSOCIATED WITH THE PROPERTIES, NO MATTER WHETHER ARISING BEFORE, ON OR
AFTER THE EFFECTIVE TIME.
12.5 PLUGGING AND ABANDONMENT. The Properties may contain wells and
facilities that have been shut in or temporarily or permanently abandoned.
NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY, INCLUDING
ARTICLE 5 AND ARTICLE 8, IF CLOSING OCCURS:
12.5.1 Buyer hereby expressly assumes and accepts sole and
exclusive responsibility for and agrees to pay all costs and expenses
associated with Plugging and Abandonment of all facilities associated
with the Properties, and may not claim the fact that Plugging and
Abandonment operations are not complete or that additional costs and
expenses are required to complete Plugging and Abandonment operations
as an Alleged Adverse Condition or a breach of Seller's representations
or warranties under this Agreement or the basis for any other redress
against Seller or its Affiliates, and Buyer (on behalf of Buyer Group
and their successors and assigns) irrevocably waives any and all Losses
and Third Party Claims they may have against Seller Group associated
with the same; and
12.5.2 BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY
PROTECT, DEFEND, INDEMNIFY, AND HOLD SELLER GROUP HARMLESS FROM AND
AGAINST ANY AND ALL LOSSES AND THIRD PARTY CLAIMS RELATING TO, ARISING
OUT OF, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY, PLUGGING AND
ABANDONMENT OPERATIONS, NO MATTER WHETHER ARISING BEFORE, ON OR AFTER
THE EFFECTIVE TIME.
161
12.5.3 To the extent that Buyer or its assignees discharge any
Third Party Claim for Plugging and Abandonment of the Properties, and
to the maximum extent permitted by Law, Buyer and its successors and
assigns waive all rights of legal subrogation to Third Party Claims
asserted or held by that Third Party against Seller, arising from or
related to the Plugging and Abandonment of the Properties.
12.6 PROCESS SAFETY MANAGEMENT. Buyer acknowledges that Process Safety
Management is an ongoing process. NOTWITHSTANDING ANYTHING CONTAINED IN THIS
AGREEMENT TO THE CONTRARY, INCLUDING ARTICLE 5 AND ARTICLE 8, IF CLOSING OCCURS,
(A) BUYER ACCEPTS SOLE RESPONSIBILITY FOR AND AGREES TO PAY ALL COSTS AND
EXPENSES ASSOCIATED WITH PROCESS SAFETY MANAGEMENT (INCLUDING IDENTIFICATION,
EVALUATION AND REMEDIATION), AND MAY NOT CLAIM THE FACT THAT THE PROCESS SAFETY
MANAGEMENT IS NOT COMPLETE OR THAT ADDITIONAL COSTS AND EXPENSES WILL BE
REQUIRED TO COMPLY WITH OR COMPLETE PROCESS SAFETY MANAGEMENT AS AN ALLEGED
ADVERSE CONDITION OR A BREACH OF SELLER'S REPRESENTATIONS OR WARRANTIES UNDER
THIS AGREEMENT OR THE BASIS FOR ANY OTHER REDRESS AGAINST SELLER; AND BUYER (ON
BEHALF OF THE BUYER GROUP AND THEIR SUCCESSORS AND ASSIGNS) IRREVOCABLY WAIVES
ANY AND ALL LOSSES AND THIRD PARTY CLAIMS THEY MAY HAVE AGAINST SELLER GROUP
ASSOCIATED WITH THE SAME; AND (B) BUYER RELEASES SELLER GROUP FROM AND SHALL
FULLY PROTECT, DEFEND, INDEMNIFY AND HOLD SELLER GROUP HARMLESS FROM AND AGAINST
ANY AND ALL LOSSES AND THIRD PARTY CLAIMS RELATING TO, ARISING OUT OF, OR
CONNECTED WITH, DIRECTLY OR INDIRECTLY, PROCESS SAFETY MANAGEMENT ASSOCIATED
WITH THE PROPERTIES, NO MATTER WHETHER ARISING BEFORE, ON OR AFTER THE EFFECTIVE
TIME.
12.7 IMBALANCES.
12.7.1. Buyer acknowledges that Imbalances may exist on one or
more of the Properties and that all Imbalances (whether for
over-production, over-delivery, under-production or under-delivery)
will pass to Buyer at Closing, and Buyer shall thereupon be entitled to
all rights and obligations with respect to any and all Imbalances.
Notwithstanding anything to the contrary in this Agreement (including
Article 8), except as provided in Article 12.7.2: (i) no amounts shall
be paid to or by either Party to the other as a Purchase Price
adjustment, as part of the Final Accounting Settlement or otherwise,
based on Imbalances; and (ii) from and after Closing:
(a) Buyer accepts sole responsibility for and agrees to pay
all costs and expenses (if any) associated with Imbalances, and Buyer
(on behalf of Buyer Group and their successors and assigns) irrevocably
waives any and all claims it and they may have against Seller Group
associated Imbalances; and Seller agrees that Buyer will receive all
benefits (if any) associated with Imbalances.
(b) BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY PROTECT,
DEFEND, INDEMNIFY AND HOLD SELLER GROUP HARMLESS FROM AND AGAINST ANY
AND ALL CLAIMS RELATING TO, ARISING OUT OF, OR CONNECTED WITH, DIRECTLY
OR INDIRECTLY, IMBALANCES, NO MATTER WHETHER ARISING BEFORE OR AFTER
THE EFFECTIVE TIME. THIS INDEMNITY AND DEFENSE OBLIGATION WILL APPLY
REGARDLESS OF CAUSE OR OF ANY NEGLIGENT ACTS OR OMISSIONS (INCLUDING
162
SOLE NEGLIGENCE, CONCURRENT NEGLIGENCE OR STRICT LIABILITY), BREACH OF
DUTY (STATUTORY OR OTHERWISE), VIOLATION OF LAW, OR OTHER FAULT OF
SELLER GROUP, OR ANY PRE-EXISTING DEFECT.
12.7.2. The following adjustment is the sole adjustment that
will be made between the Parties with respect to Imbalances:
(i) if Seller's Imbalance for an individual Property as of the
Effective Time varies from the amount for such Property as set forth in
Schedule 12.7.2 to the detriment of Buyer (as owner of the Property
after Closing) by more than 10,000 mcf, then Seller shall pay Buyer
S2.50 per mcf for each mcf over the aforesaid variance as part of the
Final Accounting Settlement; or
(ii) if Seller's Imbalance for an individual Property as of
the Effective Time varies from that amount for such Property as set
forth in Schedule 12.7.2 to the benefit of Buyer (as owner of the
Property after Closing) by more than 10,000 mcf, then Buyer shall pay
Seller S2.50 per mcf for each mcf above the aforesaid variance as part
of the Final Accounting Settlement.
EACH PARTY WAIVES ANY REMEDIES FOR UNDER PRODUCTION, UNDER DELIVERY, OVER
PRODUCTION OR OVER DELIVERY VARIANCES, EXCEPT AS STATED IN ARTICLE 12.7.2(i) AND
(ii) AND NO ADJUSTMENTS WILL BE MADE WITH RESPECT TO IMBALANCES AFTER AGREEMENT
TO, OR DETERMINATION BY THE ACCOUNTING REFEREE OF (AS APPLICABLE), THE FINAL
ACCOUNTING SETTLEMENT, EVEN IF SUCH IMBALANCES ARE NOT DISCOVERED UNTIL AFTER
SUCH AGREEMENT OR DETERMINATION.
12.8 SUSPENSE FUNDS. Buyer acknowledges that Suspense Funds may exist
as of the Effective Time. Seller shall transfer at Closing any Suspense Funds
held by Seller as operator of any Properties and the obligations with respect
thereto to Buyer. This transfer shall be accounted for in the Final Accounting
Statement. NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY,
INCLUDING ARTICLE 6 AND ARTICLE 8, IF CLOSING OCCURS:
12.8.1 BUYER ACCEPTS SOLE RESPONSIBILITY FOR AND AGREES TO PAY
ALL COSTS AND EXPENSES ASSOCIATED WITH THE SUSPENSE FUNDS, AND BUYER
(ON BEHALF OF BUYER GROUP AND THEIR SUCCESSORS AND ASSIGNS) IRREVOCABLY
WAIVES ANY AND ALL CLAIMS THEY MAY HAVE AGAINST SELLER GROUP ASSOCIATED
WITH THE SAME; AND
12.8.2 BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY
PROTECT, DEFEND, INDEMNIFY AND HOLD SELLER GROUP HARMLESS FROM AND
AGAINST ANY AND ALL LOSSES AND THIRD PARTY CLAIMS RELATING TO, ARISING
OUT of, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY, THE SUSPENSE FUNDS,
NO MATTER WHETHER ARISING BEFORE, ON OR AFTER THE EFFECTIVE TIME.
12.9 SALES TAX. The Parties agree that this sale is an occasional sale
of assets by Seller in which it does not trade in the ordinary course of
business. The Parties shall take commercially reasonable actions to assert and
establish the occasional sale exemption from Sales Tax associated with the
transactions contemplated hereby. If Sales Tax is due and owing as a result of
Seller's transfer of the Properties to Buyer, Buyer shall be solely responsible
and liable for any and all such Sales Tax. Before the Closing Date, Buyer and
163
Seller shall agree on the value of the tangible personal property being
transferred and Buyer shall provide Seller with documentation detailing the
basis for Buyer's allocation of the Purchase Price to any such Properties that
are subject to Sales Tax. Buyer shall provide Seller with an exemption
certificate for any tangible personal property included in the Properties for
which it claims a Sales Tax exemption. Seller shall invoice, and Buyer shall
pay, any Sales Tax on Buyer's acquisition of all nonexempt tangible personal
property and Seller shall remit the Sales Tax to the applicable governmental
entity or authority. If Seller is later required to pay any additional Sales
Tax, interest, or penalty thereon, Buyer shall reimburse Seller within thirty
(30) Days after receipt of Seller's written notice of the payment.
NOTWITHSTANDING ANYTHING CONTAINED IN THIS AGREEMENT TO THE CONTRARY (INCLUDING
ARTICLE 6 OR ARTICLE 8), BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY
PROTECT, DEFEND, INDEMNIFY AND HOLD SELLER GROUP HARMLESS FROM AND AGAINST ANY
AND ALL LOSSES AND THIRD PARTY CLAIMS (NO MATTER WHEN ASSERTED) RELATING TO,
ARISING OUT OF, OR CONNECTED WITH, DIRECTLY OR INDIRECTLY, SALES TAX RESULTING
FROM OR ASSOCIATED WITH SELLER'S TRANSFER OF PROPERTIES TO BUYER.
12.10 TRANSITION AGREEMENT. Buyer and Seller shall execute and deliver
the Transition Agreement at Closing.
12.11 INTERIM PERIOD. During the Interim Period, Seller shall maintain
and operate the Properties and dispose of production from the Properties in the
ordinary course of business consistent with the Seller's ordinary practices with
respect to the Properties.
12.11.1 Without the consent of Buyer (which shall not be
unreasonably withheld or delayed), during the Interim Period, Seller
shall not, with respect to the Properties:
(a) except with respect to matters, if any, for which Seller
has provided an indemnity to Buyer, waive, compromise or settle any
right or claim which reasonably would be expected to have a Material
Adverse Effect;
(b) incur any obligation in excess of Fifty Thousand Dollars
(US $50,000) with respect to the Properties for which Buyer would be
responsible after Closing, other than in connection with transactions
in the normal, usual and customary manner, of a nature and in an amount
consistent with ordinary practices of Seller with respect to the
Properties and/or in connection with situations believed in good faith
by Seller to constitute an emergency (in which case Seller's obligation
is limited to notifying Buyer as soon as reasonably practicable of such
emergency and obligations);
(c) encumber, sell, lease, or otherwise dispose of any of the
Properties (excluding sales of hydrocarbons therefrom), except to the
extent replaced by equivalent property or to the extent used, consumed
or abandoned in the normal operations of the Properties; or
(d) enter into a contract or commitment for any capital
expenditure or acquisition or construction of fixed assets in either
164
case for which Buyer would be responsible after Closing in an amount
individually in excess of Fifty Thousand Dollars (US $50,000), except
in connection with situations believed in good faith by Seller to
constitute an emergency (in which case Seller's obligation is limited
to notifying Buyer as soon as reasonably practicable of such emergency
and obligations).
12.11.2 Regardless of whether all of the operations conducted
by Seller during the Interim Period with respect to any of the
Properties have been fully completed by Seller prior to Closing, upon
Closing Buyer shall assume full responsibility for the completion of
all such operations applicable to the Properties, subject, however, to
the terms of the Transition Agreement during the Transition Period.
12.11.3 Buyer acknowledges Seller owns undivided interests in
certain of the Properties and that Seller does not operate all of the
Properties, and Buyer agrees that the acts or omissions of Third Party
working interests owners (including Third Party operators) will not
constitute a breach of the provisions of this Article 12.11, nor shall
any action required by a vote of working interest owners constitute
such a breach so long as Seller has voted its interest in a manner that
complies with the provisions of this Article 12.11. Furthermore. Seller
shall not be deemed or held to be in breach of any of Seller's
representations, warranties, covenants or other agreements contained in
this Agreement to the extent that any such breach arises out of or in
connection with the actions of Buyer or Buyer's Affiliates as operators
or co-owners of any of the Properties prior to the Closing.
12.12 CONSENTS TO ASSIGN. Prior to the Closing Date, Seller shall use
its reasonable efforts to obtain consents necessary to assign the Properties to
Buyer at Closing.
12.13 NOTIFICATION OF BREACHES. Until Closing:
12.13.1 Buyer shall notify Seller promptly upon Buyer's
knowledge that any of Seller's representations or warranties in this
Agreement are untrue in any material respect or will be untrue in any
material respect as of the Closing Date or that any covenant or
agreement to be performed or observed by Seller prior to or on the
Closing Date has not been so performed or observed in any material
respect or that any Title Defect or noncompliance with any
Environmental Law exists.
12.13.2 Seller shall notify Buyer promptly upon Seller's
knowledge that any of Buyer's representations or warranties in this
Agreement are untrue in any material respect or will be untrue in any
material respect as of the Closing Date or that any covenant or
agreement to be performed or observed by Buyer prior to or on the
Closing Date has not been so performed or observed in a material
respect.
12.13.3 If any of Buyer's or Seller's representations or
warranties are untrue or will become untrue in any material respect
between the date of execution of this Agreement and the Closing Date,
or if any of Buyer's or Seller's covenants or agreements to be
performed or observed prior to or on the Closing Date shall not have
been so performed or observed in any material respect, but if such
165
breach of representation, warranty, covenant or agreement shall (if
curable) be cured by the Closing, then such breach shall be considered
not to have occurred for all purposes of this Agreement.
12.14 THIRD PARTY-OWNED TECHNOLOGY.
12.14.1 Buyer shall be responsible for the purchase of all
Third Party-Owned Technology that is needed or is appropriate for
Buyer's operation of the Properties as currently operated by Seller.
12.14.2 Seller shall use reasonable efforts to obtain for
Buyer the rights (by seeking and obtaining relevant vendor consents) to
access and use (or permit Seller to access and use on Buyer's behalf)
all Third Party-Owned Technology during the Transition Period only, and
Buyer shall bear all of Seller's costs in so doing as well as all other
costs and fees, if any, to procure such consents and shall reimburse
Seller in the Final Accounting Settlement for any such costs or fees
incurred by Seller in connection therewith.
12.14.3 Buyer acknowledges that Buyer's rights to access and
use Third Party-Owned Technology under Third Party consents so procured
by Seller will expire at the end of the Transition Period, and Buyer
agrees to obtain its own licenses for all Third Party-Owned Technology
that Buyer deems necessary or appropriate in connection with the
operation of the Properties after the Transition Period.
12.14.4 Upon termination of the Transition Period, Buyer shall
certify to Seller in writing that all Third Party-Owned Technology for
which consents were obtained for it by Seller either has been
de-installed or have been licensed by Buyer from the applicable vendor.
Seller shall have the right to confirm, at Seller's expense, that
post-Transition Period use by Buyer of all Third Party-Owned Technology
has either ceased or continues under license(s) Buyer has acquired from
the applicable vendors.
12.15 SHARED SYSTEMS IP LICENSE. The Parties shall sign and deliver the
Shared Systems IP License at Closing.
12.16 FINANCIAL AUDIT FOR SEC FILINGS. In the event required by Buyer,
both prior to and after the Closing, Seller shall provide Buyer with access
during normal business hours to Seller's financial records for the Properties
for the calendar years 2004 and 2005 previously made available to Seller's
auditors for purposes of preparing Seller's annual audited and quarterly
reviewed financial statements for those years with respect to the Properties and
to Seller's corresponding financial records for any portion of 2006 prior to the
Closing, including (in each case) records with respect to direct lease operating
costs with respect to each of the Properties and the gross revenues from such
Properties and such other information relating to the Properties as is needed
for Buyer to make any required filings with the Securities and Exchange
Commission ("SEC") with respect to the Properties and the transactions
contemplated by this Agreement. The cost incurred by Seller and its Affiliates
in providing the financial data to Buyer and assisting Buyer therewith shall be
borne by Buyer. BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY PROTECT,
166
DEFEND, INDEMNIFY AND HOLD SELLER GROUP HARMLESS FROM AND AGAINST ANY AND ALL
CLAIMS, LOSSES AND LIABILITIES RELATING TO, ARISING OUT OF, OR CONNECTED WITH,
DIRECTLY OR INDIRECTLY, FURNISHING ANY SUCH RECORDS TO BUYER, ANY ACTIONS,
REPRESENTATIONS OR CERTIFICATIONS OF SELLER'S AND ITS AFFILIATES' PERSONNEL OR
AUDITORS WITH RESPECT TO THE INFORMATION CONTAINED IN SUCH RECORDS, OR BUYER'S
OR BUYER'S AFFILIATE'S USE OF THE INFORMATION CONTAINED IN SUCH FINANCIAL
RECORDS.
ARTICLE XIII
HSR ACT
13.1 HSR FILINGS. If compliance with the HSR Act is required in
connection with the transactions contemplated by this Agreement, as promptly as
practicable and in any event not more than thirty (30) Days after the date of
this Agreement, both Parties shall file with the Federal Trade Commission and
the Department of Justice, as applicable, the required notification and report
forms and shall as promptly as practicable furnish any supplemental information
that may be requested in connection therewith. Each Party shall take all
reasonable steps to achieve early termination of applicable waiting periods.
Each Party shall bear its own filing and other fees and costs associated with
compliance with the HSR Act.
ARTICLE XIV
PERSONNEL
14.1 EMPLOYEE LIST. Seller has no obligation to provide Buyer an
opportunity to interview for employment any individuals who support the
Properties, and Buyer has no obligation to hire any such individuals. Seller has
no obligation to provide Buyer any information about such individuals, including
personnel records.
14.2 RESTRICTION ON SOLICITATION. Buyer may not (without obtaining the
prior written consent of Seller), for a period of twelve (12) months after the
Closing Date, solicit employment of or contact (except for such contact as may
be necessary in respect to litigation, claims or other business matters
unrelated to the solicitation of employment) any of Seller's employees directly
or indirectly engaged in operation of the Properties as of the date hereof and
as of the Closing Date or engaged in the negotiation or Closing of the
transactions contemplated by this Agreement. For purposes of this Article 14.2,
a general published solicitation or advertisement for employment (whether in
print or on-line) shall not be a breach hereof.
ARTICLE XV
CONDITIONS PRECEDENT TO CLOSING
15.1 CONDITIONS PRECEDENT TO SELLER'S OBLIGATION TO CLOSE. Seller
shall, subject to satisfaction or waiver of the conditions to Closing in Article
15.3, consummate the sale of the Properties on the Closing Date, provided the
following conditions precedent have been satisfied or have been waived in
writing by Seller:
15.1.1 all of Buyer's representations and warranties given in
this Agreement are true and correct in all material respects with the
167
same force and effect as though such representations and warranties had
been made or given on and as of the Closing Date;
15.1.2 Buyer shall have complied in all material respects with
all of Buyer's material obligations, covenants and conditions in this
Agreement to be performed or complied with prior to Closing;
15.1.3 Buyer shall have provided Seller evidence satisfactory
to Seller that Buyer is as of Closing in full compliance with all
governmental requirements for ownership and operation of the
Properties, if any (except consents by governmental or tribal entities
or authorities customarily obtained subsequent to transfer of title);
and
15.1.4 Buyer shall have provided Seller with copies of any
other necessary or appropriate consents, permits, insurance, approvals,
authorizations and similar items required of Buyer to purchase,
receive, own and/or operate the Properties as of the Closing and to
otherwise transact business in the applicable jurisdiction and in
accordance with contracts assigned to Buyer at Closing.
15.2 CONDITIONS PRECEDENT TO BUYER'S OBLIGATION TO CLOSE. Buyer shall,
subject to satisfaction or waiver of the conditions to Closing set forth in
Article 15.3, consummate the purchase of the Properties contemplated by this
Agreement on the Closing Date, provided the following conditions precedent have
been satisfied or have been waived in writing by Buyer:
15.2.1 all of Seller's representations and warranties given in
this Agreement are true and correct in all material respects with the
same force and effect as though such representations and warranties had
been made or given on and as of the Closing Date; and
15.2.2 Seller shall have complied in all material respects
with all of Seller's material obligations, covenants and conditions in
this Agreement to be performed or complied with prior to Closing.
15.3 CONDITIONS PRECEDENT TO OBLIGATION OF EACH PARTY TO CLOSE. The
Parties shall, subject to waiver or satisfaction of the conditions to Closing
set forth in Articles 15.1 and 15.2, consummate the sale and purchase of the
Properties on the Closing Date, provided the following conditions precedent have
been satisfied or have been waived in writing by both Parties:
15.3.1 if applicable, consummation of the transactions
contemplated by this Agreement is not prevented by (and the required
waiting period, if any, has expired under) the HSR Act and the rules
and regulations of the Federal Trade Commission and the Department of
Justice;
15.3.2 no injunction, order or award restraining, enjoining or
otherwise prohibiting consummation of or granting material damages
associated with the transactions contemplated by this Agreement or sale
of any one or more of the Properties has been issued by any court,
governmental entity or authority or an arbitrator of competent
168
jurisdiction, and no suits, actions or other proceedings are pending
before any such court, governmental entity or arbitrator in which a
Third Party seeks to restrain, enjoin or otherwise prohibit
consummation of or obtain material damages associated with the
transactions contemplated by this Agreement or sale of any one or more
of the Properties; nor to either Party's knowledge are there any
pending investigations by a governmental entity or authority that would
be likely to result in any a suit, action or other proceedings to
restrain, enjoin or otherwise prohibit consummation of the transactions
contemplated by this Agreement or sale of any one or more of the
Properties; provided that if such an injunction, order, award, suit,
action or other proceeding applicable to some (but not all) of the
Properties is pending on the Closing Date, Closing with respect to the
unaffected Properties shall proceed and the Parties shall conduct a
second closing for the affected Properties if and when the
above-referenced condition to Closing is removed. If the
above-referenced condition to Closing is not removed as to the affected
Properties within one hundred twenty (120) Days after the Closing Date,
the affected Properties (automatically and without need for amendment
of this Agreement) shall be removed from this Agreement, and Buyer
shall not be obligated to make payment to Seller for that portion of
the Purchase Price allocated to such Properties in Exhibit "A" or
"A-1", as applicable, and the Parties shall have no further obligations
to each other with respect to the same;
15.3.3 all material consents and approvals (except for
consents and approvals of governmental entities or authorities
customarily obtained subsequent to transfer of title) have been
obtained; provided, however, if on the Closing Date material consents
applicable to some (but not all) of the Properties have not been
obtained, Closing with respect to the unaffected Properties shall
proceed, and the Parties shall conduct one or more subsequent closings
to convey the affected Properties, if and when the above-referenced
condition to Closing is removed. If the above-referenced condition to
Closing is not removed as to an affected Property within one hundred
eighty (180) Days after the Closing Date, that affected Property
(automatically and without need for amendment of this Agreement) shall
be removed from this Agreement, and Buyer shall not be obligated to
make payment to Seller for that portion of the Purchase Price allocated
to such Property in Exhibit "A" or "A-1", as applicable, and the
Parties shall have no further obligations to each other with respect to
the same; and
15.3.4 PPRs applicable to the Properties either have been
exercised or waived or the time to exercise such PPRs has expired, and
Properties exercised upon have been excluded from the Closing in
accordance with Article 3.1.
ARTICLE XVI
THE CLOSING
16.1 CLOSING. No later than three (3) Business Days prior to the
Closing Date, Seller shall provide Buyer a statement setting forth the Adjusted
Purchase Price ("CLOSING STATEMENT"). Seller also shall provide Buyer wiring
instructions designating the account(s) to which Buyer shall deliver the
Purchase Price. Closing shall be held on the Closing Date in Seller's office at
200 WestLake Park Boulevard, Houston, Texas 77079 or such other place as Seller
may notify Buyer before the Closing Date. Seller shall furnish to Buyer with the
Closing Statement a copy of the applicable authorizations for expenditure or
169
other customary documentation as reasonably necessary for Buyer to confirm the
amounts of any capital expenditures that are reflected in the cash flows set
forth in the Closing Statement.
16.2 SELLER'S OBLIGATIONS AT CLOSING. At Closing, Seller shall deliver
to Buyer, unless waived by Buyer, the following:
16.2.1 a document substantially in the form of the Deed,
Assignment and Bill of Sale, assigning all of Seller's right, title and
interests in the Properties, executed by an Attorney-in-Fact of Seller
and acknowledged, in four (4) multiple originals (or such greater
number as the Parties agree);
16.2.2 four (4) originals of the Certificate executed by an
authorized officer or an Attorney-in-Fact of Seller;
16.2.3 four (4) originals of the Non-Foreign Certificate
executed by an Attorney-in-Fact of Seller;
16.2.4 four (4) originals of a Secretary's Certificate or
Assistant Secretary's Certificate certifying as to the due
authorization of Seller's signatory to the documents signed at Closing;
16.2.5 four (4) originals of the Transition Agreement
executed by an Attorney-in-Fact of Seller, if applicable;
16.2.6 State of Louisiana change of operator forms for the
Properties of which Seller is the operator in such number as required
by the government plus additional copies as the Parties agree;
16.2.7 four (4) originals of the Shared Systems IP License
executed by an authorized officer or an Attorney-in-Fact of Seller; and
16.2.8 any other instruments and agreements (including
ratification or joinder instruments required to transfer Properties
from Seller to Buyer and deeds) as are necessary or appropriate to
comply with Seller's obligations under this Agreement.
16.3 BUYER'S OBLIGATIONS AT CLOSING. At Closing, Buyer shall deliver to
Seller, unless waived by Seller, the following:
16.3.1 the Adjusted Purchase Price, as set forth on the
Closing Statement, by wire transfer of immediately available funds to
the account(s) designated by Seller in accordance with this Agreement;
16.3.2 the documents referred to in Articles 16.2.1, 16.2.5,
16.2.6,16.2.7, and 16.2.8, executed by an authorized officer or an
Attorney-in-Fact of Buyer and acknowledged;
170
16.3.3 four (4) originals of the Certificate executed by an
authorized officer or an Attorney-in-Fact of Buyer;
16.3.4 four (4) originals of (i) certificates of the
appropriate governmental authorities, dated as of a date not earlier
than two (2) Business Days prior to the Closing Date, evidencing
Buyer's existence and good standing in the States of Texas and
Louisiana, and (ii) certificates of the Secretary or Assistant
Secretary of Buyer, dated on the Closing Date, certifying (A) that a
true and correct copy of the resolutions of Buyer's board of directors
authorizing this Agreement and the transactions contemplated hereby are
attached thereto have been duly adopted and are in full force and
effect; (B) that true and correct copies of the articles of
incorporation, all amendments thereto and bylaws of Buyer are attached
thereto; and (C) as to the incumbency and authorization of Buyer's
signatory executing on behalf of Buyer this Agreement and the other
documents executed in connection herewith;
16.3.5 evidence that Buyer is at Closing in full compliance
with all governmental requirements for posting plugging and other
applicable bonds and filings related to the Properties or their
operation, if any;
16.3.6 the sales tax exemption certificate referred to in
Article 12.9; and
16.3.7 any other instruments and agreements (including
ratification or joinder instruments required to transfer the Properties
from Seller to Buyer and deeds) as necessary or appropriate to comply
with Buyer's obligations under this Agreement.
ARTICLE XVII
TERMINATION
17.1 GROUNDS FOR TERMINATION. This Agreement may be terminated (except
for the individual provisions specifically referenced in Article 17.2 below) at
any time prior to Closing (unless another date is stated below):
17.1.1 by the Parties' mutual written agreement;
17.1.2 by either Party, if consummation of the transactions
contemplated by this Agreement would violate any non-appealable final
order, decree or judgment of any state or federal court or agency
enjoining, restraining, prohibiting or awarding substantial damages in
connection with (a) Seller's proposed sale of Properties to Buyer, or
(b) consummation of the transactions contemplated by this Agreement;
17.1.3 by Seller, if Buyer refuses or fails for any reason to
give Seller the Performance Deposit in accordance with and at the time
specified in Article 2.3;
17.1.4 by either Party, if such Party becomes aware that any
condition precedent to a Party's obligation to Close cannot be
satisfied prior to the Closing Date, provided, however, that the
terminating Party shall have given the other Party at least five (5)
171
Business Days ("CURE PERIOD") to cure the situation and at the end of
such cure period, the relevant condition precedent remains unsatisfied
prior to the Closing Date;
17.1.5 notwithstanding anything contained in this Agreement to
the contrary, by Seller, if Closing has not occurred on or before
October 31, 2006; or
17.1.6 by either Party, pursuant to Section 7.2.2.
17.2 EFFECT OF TERMINATION. Except as otherwise provided in this
Article 17.2, this Agreement is terminated in accordance with Article 1 7.1,
such termination is without liability to either Party, except performance of
obligations in this Article 17.2, Articles 5.1.2, 14.2, 17.3, 17.4, 18.1, 19.1,
19.3, 19.7, 19.8, 19.9, 19, 10, 19.12, 19.13,19.14, 19.15, 19.16, 19.17, 19.18,
19.19, 19.21 and 19.22, all of which provisions survive termination of this
Agreement.
17.2.2 If Closing does not occur, Seller shall refund the
Performance Deposit together with Computed Interest to Buyer unless
Closing did not occur because of (i) Buyer's breach of this Agreement
or (ii) Buyer's failure or refusal to Close that is not permitted by
the terms of this Agreement, and in the case of either (i) or (ii)
hereinabove Seller is entitled to retain the Performance Deposit
together with all interest earned thereon as liquidated damages and not
a penalty. The foregoing remedies are the sole remedies for either
Party in connection with failure of Closing to occur, except in the
case of willful breach of a Party, in which case the other Party has
any remedies available to it at law or in equity.
17.3 DISPUTE OVER RIGHT TO TERMINATE. If there is a dispute over the
right of a Party to terminate this Agreement, Closing shall not occur on the
Closing Date, and the Party that disputes the right of the other Party to
terminate is entitled, within thirty (30) Business Days after the Closing Date,
to initiate litigation to resolve the dispute. If the Party that disputes the
other Party's right to terminate this Agreement does not initiate litigation
within the thirty (30) Business Day period, this Agreement shall be deemed
properly terminated as of the original date of termination (without prejudice to
Seller's right to retain the Performance Deposit together with any interest
earned thereon pursuant to Article 17.2.2), AND THE PARTY THAT DISPUTES OR HAS a
RIGHT TO DISPUTE TERMINATION OF THIS AGREEMENT, ON BEHALF OF ITSELF, ITS
AFFILIATES, AND THE OFFICERS, DIRECTORS, AGENTS, EMPLOYEES, SUCCESSORS AND
ASSIGNS OF ITSELF AND ITS AFFILIATES, IRREVOCABLY WAIVES ANY AND ALL CLAIMS IT
AND THEY MAY HAVE AGAINST THE TERMINATING PARTY FOR TERMINATION OF THIS
AGREEMENT.
17.4 CONFIDENTIALITY. Notwithstanding the termination of this Agreement
or any other provision of this Agreement to the contrary, the terms of the
Confidentiality Agreement remain in full force and effect, provided that if and
when Closing occurs and effective on the Closing Date, the Confidentiality
Agreement shall terminate to the extent (and only to the extent) it applies to
the Properties conveyed to Buyer at Closing and shall remain in full force and
effect as to all Excluded Properties and other assets, properties or information
of Seller Group not conveyed to Buyer pursuant to this Agreement.
172
ARTICLE XVIII
ARBITRATION
18.1 ARBITRATION. Arbitrable Disputes must be resolved through use of
binding arbitration using three (3) arbitrators, in accordance with the
Commercial Arbitration Rules of the American Arbitration Association (the "AAA")
as in effect on the date of this Agreement, as supplemented to the extent
necessary to determine any procedural appeal questions by the Federal
Arbitration Act (Title 9 of the United States Code). If there is any
inconsistency between this Article and the Commercial Arbitration Rules or the
Federal Arbitration Act, this Article shall control. Arbitration must be
initiated within the applicable time limits set forth in this Agreement and not
thereafter or if no time limit is given, within the time period allowed by the
applicable statute of limitations. Arbitration, if initiated, must be initiated
by a Party ("CLAIMANT") serving written notice on the other Party ("RESPONDENT")
that the Claimant elects to refer the Arbitrable Dispute to binding arbitration.
Claimant's notice initiating arbitration must identify the arbitrator Claimant
has appointed. The Respondent shall respond to Claimant within thirty (30) Days
after receipt of Claimant's notice, identifying the arbitrator Respondent has
appointed. If the Respondent does not name an arbitrator within the thirty (30)
Day period, the Houston office of the AAA will name the arbitrator for
Respondent's account. The two (2) arbitrators so chosen shall select a third
arbitrator within thirty (30) Days after the second arbitrator has been
appointed. If the Party-appointed arbitrators cannot reach agreement upon the
third arbitrator within the thirty (30) Day period, the Houston office of the
AAA shall appoint an independent arbitrator. The Parties each shall pay one-half
of the compensation and expenses of the arbitrators. All arbitrators must (a) be
neutral persons who have never been officers, directors, employees, or
consultants or had other business or personal relationships with the Parties or
any of their Affiliates, officers, directors or employees, and (b) have not less
than seven (7) years experience in the U.S. oil and gas industry. The hearing
will be conducted in Houston, Texas, and commence within thirty (30) Days after
the selection of the third arbitrator. The Parties and the arbitrators should
proceed diligently and in good faith so that the award can be made as promptly
as possible. Except as provided in the Federal Arbitration Act, the decision of
the arbitrators shall be binding on and non-appealable by the Parties. The
arbitrators shall have no right or authority to grant or award indirect,
consequential, punitive or exemplary damages of any kind.
ARTICLE XIX
MISCELLANEOUS
19.1 NOTICES. All notices and other communications required or desired
to be given hereunder must be in writing and sent (properly addressed as set
forth below) by (a) certified or registered U.S. mail, return receipt requested,
with all postage and other charges fully prepaid, (b) hand or courier delivery,
or (c) facsimile transmission. Date of service by mail and delivery is the date
on which such notice is received by the addressee and by facsimile is the date
sent (as evidenced by fax machine generated confirmation of transmission) if
173
received during normal business hours on a Business Day; provided, however, if
not received during normal business hours on a Business Day, then date of
receipt will be on the next date that is a Business Day. Each Party may change
its address by notifying the other Party in writing of such address change, and
the change will be effective thirty (30) Days after such notification is
received by the other Party.
To Seller:
BP America Production Company
501 WestLake Park Boulevard
Houston, Texas 77079
Facsimile: 281-388-7583
Attn: Assistant General Counsel, Legal Group
To Buyer:
Swift Energy Operating, LLC
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Facsimile: (281) 874-8033
Attn: James P. Mitchell
Senior Vice President -- Commercial Transactions & Land
19.2 COSTS AND POST-CLOSING CONSENTS. Notwithstanding other provisions
of this Agreement, Buyer shall be responsible for recording and filing documents
associated with assignment of the Properties to it and for all costs and fees
associated therewith, including filing the assignments in the appropriate
parishes, provided, however, that Seller shall file with the applicable State of
Louisiana agency the change of operator forms referred to in Article 16.2.6. As
soon as practicable after recording or filing, Buyer shall furnish Seller all
recording data and evidence of all required filings made by Buyer. Buyer shall
be responsible for obtaining all consents and approvals of governmental entities
or authorities customarily obtained subsequent to transfer of title and all
costs and fees associated therewith (provided, however, Seller will exercise
reasonable efforts to assist Buyer, where applicable, at Buyer's sole cost and
expense, in obtaining such consents and approvals). Except as expressly provided
otherwise in this Agreement, all fees, costs and expenses incurred by the
Parties in negotiating this Agreement and in consummating the transactions
contemplated by this Agreement shall be paid in full by the Party that incurred
such fees, costs and expenses.
19.3 BROKERS, AGENTS AND FINDERS.
19.3.1. Neither Seller nor any of its Affiliates has retained
any brokers, agents or finders in connection with the transactions
contemplated hereby for which Buyer or its Affiliates shall have any
liability. Seller releases BUYER GROUP FROM AND SHALL FULLY PROTECT,
INDEMNIFY AND DEFEND BUYER GROUP AND HOLD THEM HARMLESS FROM AND
AGAINST ANY AND ALL CLAIMS RELATING TO, ARISING OUT of, OR CONNECTED
WITH, DIRECTLY OR INDIRECTLY, COMMISSIONS, FINDERS' FEES OR OTHER
REMUNERATION DUE TO ANY AGENT, BROKER OR FINDER CLAIMING BY, THROUGH OR
UNDER SELLER OR its AFFILIATES.
19.3.2 Neither Buyer nor any of its Affiliates retained any
agents, brokers or finders for Buyer associated with the transactions
contemplated hereby for which Seller or any of its Affiliates shall
174
have any liability. BUYER RELEASES SELLER GROUP FROM AND SHALL FULLY
PROTECT, INDEMNIFY AND DEFEND SELLER GROUP AND HOLD THEM HARMLESS FROM
AND AGAINST ANY AND ALL CLAIMS RELATING TO, ARISING OUT of, OR
CONNECTED WITH, DIRECTLY OR INDIRECTLY, COMMISSIONS, FINDERS' FEES OR
OTHER REMUNERATION DUE TO ANY AGENT, BROKER OR FINDER CLAIMING BY,
THROUGH OR UNDER BUYER OR ITS AFFILIATES.
19.4 RECORDS.
19.4.1. At Closing, Seller shall grant Buyer reasonable access
to the Records. As soon as reasonably practicable after Closing, and in
any even within sixty (60) Days after the end of the Transition Period
or if there is no Transition Period, within ninety (90) Days after the
Closing Date, (except as provided below), Seller shall furnish Buyer
the Records that are maintained by Seller; provided, however, Seller
may retain: originals or copies of any or all Records, including
originals of (i) any Records associated with litigation or other
proceedings pending or threatened by or against Seller Group, (ii) tax
records, (iii) Records in connection with the Final Accounting
Settlement until payments made thereunder have been agreed and paid in
full, (iv) Records required in connection with any Transition Period
activities (until the end of the Transition Period), and (v) Records
associated with any properties not conveyed to Buyer pursuant to this
Agreement.
19.4.2. Seller is not obligated to create any Records for
Buyer or to provide them in a form or format other than the form or
format in which they exist as of the date hereof. Seller shall use all
reasonable efforts to provide Records in the priority designated in
writing to Seller by Buyer. If Buyer desires copies of Records prior to
the time by which Seller is obligated to deliver the Records to Buyer
hereunder, Seller will use reasonable efforts to cause the copies
requested by Buyer to be made and delivered to Buyer, provided,
however, that Seller shall have no obligation to provide Buyer Records
prior to Closing and if Seller is willing to provide any such Records,
Buyer shall reimburse Seller for all costs of copying and provision of
such Records to Buyer
19.4.3 Buyer shall maintain the Records received from Seller
for seven (7) years after the Closing Date, and afford Seller full
access to the Records and a right to copy the Records at Seller's
expense as reasonably requested by Seller. If Buyer desires to destroy
the Records, it shall notify Seller prior to such destruction, and
provide Seller an opportunity to take possession of them at Seller's
sole cost. In addition, Buyer shall afford Seller full access to
records and data produced after the Closing Date and reasonably
requested by Seller in connection with any claim by Buyer for indemnity
or breach of Seller's representations, warranties or covenants under
this Agreement (excluding, however, attorney work product and
attorney-client communications entitled to legal privilege), and a
right to copy such records and data at Seller's sole cost.
19.5 FURTHER ASSURANCES. After Closing and on an on-going basis:
19.5.1 Buyer shall execute and deliver or use reasonable
efforts to cause to be executed and delivered any other instruments of
175
conveyance and take any other actions as Seller reasonably requests to
more effectively put Seller in possession of any property that was not
intended to be (i) a Property or (ii) conveyed or was conveyed in error
(including reassignment at Seller's cost from Buyer to Seller of any
Properties that were conveyed in violation of valid preferential
purchase rights or material consents to assignment), or to implement
Buyer's assumption of obligations pursuant to Article 12.3; and
19.5.2 Seller shall execute and deliver or use reasonable
efforts to cause to be executed and delivered any other instruments of
conveyance and take any other actions as Buyer reasonably requests to
more effectively put Buyer in possession of the Properties conveyed or
intended to have been conveyed in accordance with the terms of this
Agreement.
19.6 SURVIVAL OF CERTAIN OBLIGATIONS. The representations and
warranties of the Parties in Articles 10 and 11 (except Articles 11.1.4, 11.1.6
and 11.1.8) and the covenants and agreements of the Parties to be fully
performed prior to the Closing (including the covenants and agreements in
Article 12.11) shall survive the Closing for a period of twelve (12) months.
Subject to the foregoing and as set forth in Article 19.6.1, the remainder of
this Agreement (including Articles 5.1.2, 8. 11.1.4, 11.1.6, 11.1.8, 12.3, 12.4,
12.5, 12.6, 12.7, 12.8 and 19.3) shall survive the Closing without time limit.
Representations, warranties, covenants and agreements shall be of no further
force and effect after the date of their expiration, provided that there shall
be no termination of any bona fide claim that was asserted in accordance with
this Agreement with respect to such a representation, warranty, covenant or
agreement prior to its expiration date.
19.6.1 The indemnities in Articles 8.2 and 8.4 shall terminate
as of the termination dates set forth in Article 8.3 and 8.5
(respectively) or, if no termination date is set forth in those
Articles, then as of the termination date of each representation,
warranty, covenant or agreement that is subject to indemnification
thereunder, except in each case as to matters for which a specific
Claim Notice has been delivered to the Indemnifying Party on or before
such termination date. Buyer's indemnities in Articles 8.6, 12.4, 12.5,
12.6, 12.8, and 12.9 shall be deemed covenants running with the
Properties (provided that Buyer and its successors and assigns shall
not be released from any of, and shall remain jointly and severally
liable to the Seller Group for the obligations or liabilities of Buyer
under such Articles of this Agreement upon any transfer or assignment
of any Property).
19.7 AMENDMENTS AND SEVERABILITY. No amendments, waivers or other
modifications of terms of this Agreement shall be effective or binding on the
Parties unless they are written and signed by both Parties. Invalidity of any
provisions in this Agreement shall not affect the validity of this Agreement as
a whole, and in case of such invalidity, this Agreement shall be construed as if
the invalid provision had not been included herein.
19.8 SUCCESSORS AND ASSIGNS. Except as expressly provided otherwise in
this Agreement, this Agreement may not be assigned, (in whole or in part),
without the express prior written consent of the non-assigning Party, except
176
that Seller may assign its rights and obligations hereunder to any one or more
of Seller's Affiliates without Buyer's consent and may freely assign its rights
to proceeds hereunder. The non-assigning Party's consent to assign shall not be
unreasonably withheld or delayed. The terms, covenants and conditions contained
in this Agreement are binding upon and inure to the benefit of the Parties and
their permitted successors and assigns. Buyer shall not sell, transfer, convey,
assign or otherwise dispose of the Properties without first obtaining financial
assurances of performance in favor of Seller from such successor in interest in
form and substance reasonably satisfactory to Seller. No assignment of this
Agreement by Buyer shall relieve Buyer of any of its obligations hereunder; and
any assignment made without Seller's written consent is void ab initio.
19.9 HEADINGS. Titles and headings in this Agreement have been included
solely for ease of reference and shall not be considered in interpretation or
construction of this Agreement.
19.10 GOVERNING LAW. THIS AGREEMENT (INCLUDING ADMINISTRATION OF
BINDING ARBITRATION PURSUANT TO ARTICLE 18) IS GOVERNED BY THE LAWS OF THE STATE
OF TEXAS, EXCLUDING ANY CHOICE OF LAW RULES THAT WOULD DIRECT APPLICATION OF
LAWS OF ANOTHER JURISDICTION. ANY ACTION PERMITTED BY THIS AGREEMENT TO BE
COMMENCED IN COURT SHALL BE BROUGHT AND MAINTAINED EXCLUSIVELY IN FEDERAL OR
STATE COURT LOCATED IN HARRIS COUNTY, TEXAS, AND EACH PARTY HEREBY WAIVES ANY
OBJECTION IT MAY HAVE THERETO.
19.11 NO PARTNERSHIP CREATED. It is not the purpose or intention of
this Agreement to create (and it shall not be construed as creating) a joint
venture, partnership or any type of association, and neither Party is authorized
to act as an agent or principal for the other Party with respect to any matter
related hereto.
19.12 PUBLIC ANNOUNCEMENTS. Seller (on behalf of Seller Group) and
Buyer (on behalf of Buyer Group) agree not to issue any public statement or
press release concerning this Agreement or the transactions contemplated by it
(including price or other terms) without the prior written consent of the other
Party, except for public statements that are required by Law to be made in which
case the Party required to make such statement will provide reasonable prior
notice to and consultation with -the other Party before issuing such statement.
19.13 NO THIRD PARTY BENEFICIARIES. Nothing contained in this Agreement
entitles anyone other than Seller or Buyer or their permitted successors and
assigns to any claim, cause of action, remedy or right of any kind whatsoever,
except with respect to waivers and indemnities or other provisions in this
Agreement that expressly provide for waivers or indemnification of Buyer Group
or Seller Group, in which case members of such groups are considered third party
beneficiaries for the sole purposes of those waiver and indemnity provisions.
19.14 INDEMNITIES APPLICABILITY. NOTWITHSTANDING ANYTHING TO THE
CONTRARY CONTAINED IN THIS AGREEMENT, THE RELEASE, DEFENSE, INDEMNIFICATION AND
HOLD HARMLESS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE
WHETHER OR NOT THE CLAIMS, DEMANDS, SUITS, CAUSES OF ACTION, LOSSES, DAMAGES,
LIABILITIES, FINES, PENALTIES AND COSTS (INCLUDING ATTORNEYS' FEES AND COSTS OF
LITIGATION) IN QUESTION AROSE SOLELY OR IN PART FROM THE ACTIVE, PASSIVE OR
CONCURRENT NEGLIGENCE, STRICT LIABILITY, BREACH OF DUTY (STATUTORY OR
OTHERWISE), VIOLATION OF LAW, OR OTHER FAULT OF ANY INDEMNIFIED PARTY, OR FROM
177
ANY PRE-EXISTING DEFECT, BUT SHALL NOT BE APPLICABLE TO THE EXTENT OF ANY GROSS
NEGLIGENCE OR WILLFUL MISCONDUCT ON THE PART OF AN INDEMNIFIED PARTY.
19.15 WAIVER OF CONSUMER RIGHTS. AS PARTIAL CONSIDERATION FOR THE
PARTIES ENTERING INTO THIS AGREEMENT, EACH PARTY CAN AND DOES HEREBY WAIVE THE
PROVISIONS OF THE TEXAS DECEPTIVE TRADE PRACTICES CONSUMER PROTECTION ACT,
ARTICLE 17.41 ET SEQ., TEXAS BUSINESS AND COMMERCE CODE, A LAW THAT GIVES
CONSUMERS SPECIAL RIGHTS AND PROTECTION, AND ALL OTHER CONSUMER PROTECTION LAWS
OF THE STATE OF TEXAS, OR OF ANY OTHER STATE THAT MAY BE APPLICABLE TO THIS
TRANSACTION, THAT MAY BE WAIVED BY SUCH PARTY. IT IS NOT THE INTENT OF EITHER
PARTY TO WAIVE, AND NEITHER PARTY DOES WAIVE, ANY LAW OR PROVISION THEREOF THAT
IS PROHIBITED BY LAW FROM BEING WAIVED. EACH PARTY REPRESENTS THAT IT HAS HAD AN
ADEQUATE OPPORTUNITY TO REVIEW THE PRECEDING WAIVER PROVISION, INCLUDING THE
OPPORTUNITY TO SUBMIT THE SAME TO LEGAL COUNSEL FOR REVIEW AND ADVICE, AND AFTER
CONSULTATION WITH AN ATTORNEY OF ITS OWN SELECTION VOLUNTARILY CONSENTS TO THIS
WAIVER AND UNDERSTANDS THE RIGHTS BEING WAIVED HEREIN.
19.16 REDHIBITION WAIVER. BUYER EXPRESSLY
(i) WAIVES THE WARRANTY OF FITNESS FOR INTENDED PURPOSES AND GUARANTEE
AGAINST HIDDEN OR LATENT REDHIBITORY VICES UNDER LOUISIANA LAW, INCLUDING
LOUISIANA CIVIL CODE ARTICLE 2520 (1870) THROUGH 2548 (1870);
(ii) WAIVES ALL RIGHTS IN REDHIBITION PURSUANT TO LOUISIANA CIVIL CODE
ARTICLE 2420, ET SEQ., INCLUDING THE WARRANTY IMPOSED BY LOUISIANA CIVIL CODE
ARTICLE 2475 (1870);
(iii) ACKNOWLEDGES THAT THIS EXPRESS WAIVER SHALL BE A MATERIAL AND
INTEGRAL PART OF THIS SALE AND THE CONSIDERATION THEREOF; AND (IV) ACKNOWLEDGES
THAT THIS WAIVER HAS BEEN BROUGHT TO THE ATTENTION OF BUYER AND EXPLAINED IN
DETAIL AND THAT BUYER HAS VOLUNTARILY AND KNOWINGLY CONSENTED GENERALLY AND
SPECIFICALLY TO THIS WAIVER OF WARRANTY OF FITNESS AND/OR WARRANTY AGAINST
REDHIBITORY VICES AND DEFECTS FOR THE PROPERTIES.
ALL ASSIGNMENTS TO BE DELIVERED BY SELLER AT CLOSING SHALL EXPRESSLY
SET FORTH THE DISCLAIMERS OF REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS
ARTICLE 19.16.
19.17 UTPCPL WAIVER. TO THE EXTENT APPLICABLE TO THE PROPERTIES OR ANY
PORTION THEREOF, BUYER HEREBY WAIVES THE PROVISIONS OF THE LOUISIANA UNFAIR
TRADE PRACTICES AND CONSUMER PROTECTION LAW (LA. R.S. 51-1402, ET SEQ.). BUYER
WARRANTS AND REPRESENTS THAT BUYER (i) IS EXPERIENCED AND KNOWLEDGEABLE WITH
RESPECT TO THE OIL AND GAS INDUSTRY GENERALLY AND WITH TRANSACTIONS OF THIS TYPE
SPECIFICALLY, (ii) POSSESSES AMPLE KNOWLEDGE, EXPERIENCE AND EXPERTISE TO
EVALUATE INDEPENDENTLY THE MERITS AND RISKS OF THE TRANSACTIONS HEREIN
CONTEMPLATED, AND (iii) IS NOT IN A SIGNIFICANTLY DISPARATE BARGAINING POSITION.
19.18 NOT TO BE CONSTRUED AGAINST DRAFTER. EACH PARTY HAS HAD AN
ADEQUATE OPPORTUNITY TO REVIEW EACH AND EVERY PROVISION OF THIS AGREEMENT AND TO
SUBMIT THE SAME TO LEGAL COUNSEL FOR REVIEW AND ADVICE. BASED ON THE FOREGOING,
178
THE RULE OF CONSTRUCTION, IF ANY, THAT A CONTRACT is CONSTRUED AGAINST THE
DRAFTER SHALL NOT APPLY TO INTERPRETATION OR CONSTRUCTION OF THIS AGREEMENT.
19.19 CONSPICUOUSNESS OF PROVISIONS. THE PARTIES AGREE THAT PROVISIONS
OF THIS AGREEMENT IN "BOLD" OR ALL CAPITALIZED TYPE SATISFY ANY REQUIREMENT OF
THE "EXPRESS NEGLIGENCE RULE" AND OTHER REQUIREMENT AT LAW OR IN EQUITY THAT
PROVISIONS BE CONSPICUOUSLY MARKED OR HIGHLIGHTED.
19.20 POSSIBLE EXCHANGE. Seller reserves the right to structure the
transactions contemplated under the terms of this Agreement as a
non-simultaneous like-kind exchange pursuant to Section 1031 of the Internal
Revenue Code of 1986, as amended. If Seller elects to so structure this
transaction, the Parties shall execute all documents reasonably necessary for
Seller to effectuate the non-simultaneous like-kind exchange.
19.21 EXECUTION IN COUNTERPARTS. This Agreement may be executed in
counterparts, that when taken together constitute one valid and binding
agreement.
19.22 ENTIRE AGREEMENT. This Agreement (including the agreements, once
completed and executed, attached hereto as Exhibits) and the Confidentiality
Agreement supersede all prior and contemporaneous negotiations, understandings,
letters of intent, understandings and agreements (whether oral or written)
between the Parties or their Affiliates relating to the terms of purchase and
sale of the Properties and constitute the entire understanding and agreement
between the Parties with respect to the sale, assignment and conveyance of the
Properties and other transactions contemplated by this Agreement.
The Parties have caused this Agreement to be executed by their duly
authorized representatives on the day and year first set forth above.
SELLER BUYER
BP AMERICA PRODUCTION COMPANY SWIFT ENERGY OPERATING, LLC
By: /s/ Thalia R. Gelbs By: /s/ Bruce H. Vinent
--------------------------- ---------------------------
Name: Thalia R. Gelbs Name: Bruce H. Vincent
Title: Attorney-in-Fact Title: President
179
Exhibit 12
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
2002 2003 2004 2005 2006
------------- ------------- ------------- ------------- -------------
GROSS G&A 26,074,408 29,803,405 37,850,281 51,676,164 72,400,642
NET G&A 10,564,849 14,097,066 17,787,125 22,176,362 31,316,644
INTEREST EXPENSE, NET 23,274,969 27,268,524 27,643,108 24,873,401 23,581,663
RENTAL & LEASE EXPENSE 1,923,451 2,173,313 2,375,598 2,964,611 2,637,345
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 18,408,289 50,739,178 101,440,242 178,439,551 262,286,165
CAPITALIZED INTEREST 6,973,480 6,835,983 6,489,763 7,199,069 9,210,883
CALCULATED DATA
---------------------------------------------
EXPENSED OR NON-CAPITAL G&A (%) 40.52% 47.30% 46.99% 42.91% 43.25%
NON-CAPITAL RENT EXPENSE 779,345 1,027,981 1,116,374 1,272,236 1,140,774
1/3 NON-CAPITAL RENT EXPENSE 259,782 342,660 372,125 424,079 380,258
FIXED CHARGES 30,508,231 34,447,167 34,504,996 32,496,549 33,172,804
EARNINGS 41,943,040 78,350,362 129,455,475 203,737,031 286,248,086
1.37 2.27 3.75 6.27 8.63
============= ============= ============= ============= ============
180
Exhibit 21
Swift Energy Company - Significant Subsidiaries
Swift Energy International, Inc.
Swift Energy New Zealand Limited
Southern Petroleum (NZ) Exploration Limited
Swift Energy Operating, LLC
181
Exhibit 23.1
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of
references to H.J. Gruy and Associates, Inc. and to the inclusion of and
references to our report, or information contained therein, dated January 23,
2007, prepared for Swift Energy Company in the Annual Report on Form 10-K of
Swift Energy Company for the filing dated on or about February 28, 2006.
H.J. GRUY AND ASSOCIATES, INC.
by: /s/ Robert Rasor
-----------------
Robert Rasor, P.E.
Executive Vice President
Engineering Manager
Houston, Texas
February 28, 2007
182
Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the following Registration
Statements (Form S-3 Nos. 333-112041 and 333-12831) and related Prospectuses of
Swift Company Energy Company and subsidiaries, and on the following Registration
Statements on form S-8:
Form S-8 No. Pertaining to:
-------------------------------------------------------------------------------
333-134807 Swift Energy Company 2005 Stock Compensation Plan
333-130548 Swift Energy Company 2005 Stock Compensation Plan
333-112042 Swift Energy Company 2001 Omnibus Stock Compensation Plan
333-67242 Swift Energy Company 2001 Omnibus Stock Compensation Plan
Swift Energy Company 1990 Stock Compensation Plan
333-45354 Swift Energy Company 1990 Stock Compensation Plan
Swift Energy Company 1990 Nonqualified Stock Option Plan
Swift Energy Company Employee Savings Plan
033-80228 Swift Energy Company Employee Stock Purchase Plan
of our reports dated February 27, 2007, with respect to the consolidated
financial statements of Swift Energy Company and subsidiaries, Swift Energy
Company management's assessment of the effectiveness of internal control over
financial reporting, and the effectiveness of internal control over financial
reporting of Swift Energy Company and subsidiaries, included in the Annual
Report (Form 10-K) for the year ended December 31, 2006.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2007
183
Exhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Annual Report on Form 10-K for the period ended December
31, 2006 of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the
registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such
internal control over financial reporting, to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: February 28, 2007 /s/ Terry E. Swift
-----------------------------------
Terry E. Swift
Chief Executive Officer
184
Exhibit 31.2
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this Annual Report on Form 10-K for the period ended December
31, 2006 of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the
registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such
internal control over financial reporting, to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: February 28, 2007 /s/ Alton D. Heckaman, Jr.
-----------------------------------
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
185
Exhibit 32
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Annual Report on Form 10-K for the period
ended December 31, 2006 (the "Report") of Swift Energy Company ("Swift") as
filed with the Securities and Exchange Commission on February 28, 2007, the
undersigned, in his capacity as an officer of Swift, hereby certifies pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of Swift.
Dated: February 28, 2007
/s/ Alton D. Heckaman, Jr.
-----------------------------------
Alton D. Heckaman, Jr.
Executive Vice President &
Chief Financial Officer
Dated: February 28, 2007
/s/ Terry E. Swift
-----------------------------------
Terry E. Swift
Chairman of the Board &
Chief Executive Officer
186
Exhibit 99.1
H.J. GRUY AND ASSOCIATES, INC.
--------------------------------------------------------------------------------
333 Clay Street, Suite 3850, Houston, Texas 77002 o TEL. (713) 739-1000
o FAX (713) 739-6112
January 23, 2007
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Year-End 2006 R
Reserves Audit
Gentlemen:
At your request, we have independently audited the estimates of oil, natural
gas, and natural gas liquid reserves and future net cash flows as of December
31, 2006, that Swift Energy Company (Swift) attributes to net interests owned by
Swift. Based on our audit, we consider the Swift estimates of net reserves and
net cash flows to be in reasonable agreement, in the aggregate, with those
estimates that would result if we performed a completely independent evaluation
effective December 31, 2006.
The Swift estimated net reserves, future net cash flow, and discounted future
net cash flow are summarized below:
Domestic and International
Proved Reserves
--------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
-----------------------------------------------------------------------------------
Oil, NGL, & Discounted
Condensate Gas Not at 10%
(Barrels) (Mcf) Discounted Per Year
------------- ------------- -------------------- --------------------
Proved Developed 34,956,469 151,276,834 $ 1,972,358,040 $ 1,381,206,352
Proved Undeveloped 47,162,615 172,854,583 $ 2,193,155,963 $ 1,326,549,183
Total Proved 82,119,084 324,131,417 $ 4,165,514,003 $ 2,707,755,535
187
Domestic
Proved Reserves
--------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
----------------------------------------------------------------------------------
Oil, NGL, & Discounted
Condensate Gas Not at 10%
(Barrels) (Mcf) Discounted Per Year
------------- ------------- -------------------- --------------------
Proved Developed 33,345,567 133,815,108 $ 1,875,382,590 $ 1,306,385,013
Proved Undeveloped 40,118,964 135,845,683 $ 1,873,638,977 $ 1,137,113,084
Total Proved 73,464,531 269,660,791 $ 3,749,021,567 $ 2,443,498,097
New Zealand
Proved Reserves
--------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
----------------------------------------------------------------------------------
Oil, NGL, & Discounted
Condensate Gas Not at 10%
(Barrels) (Mcf) Discounted Per Year
------------ ------------- -------------------- --------------------
Proved Developed 1,610,902 17,461,726 $ 96,975,450 $ 74,821,339
Proved Undeveloped 7,043,650 37,008,900 $ 319,516,986 $ 189,436,099
New Zealand Total 8,654,552 54,470,626 $ 416,492,436 $ 264,257,438
The discounted future net cash flows summarized in the above tables are computed
using a discount rate of 10 percent per annum. Proved reserves are estimated in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). The reserves discussed herein are estimates only
and should not be construed as exact quantities. Future economic or operating
conditions may affect recovery of estimated reserves and cash flows, and
reserves of all categories may be subject to revision as more performance data
become available.
Swift represents that the future net cash flows discussed herein were computed
using prices received for oil, natural gas, and natural gas liquids as of
December 31, 2006. Domestic oil and condensate prices are based on a year-end
2006 reference price of $61.05 per barrel. Natural gas price is based on a
188
year-end 2006 reference price of $6.299 per MMBtu. New Zealand oil and
condensate prices are based on a year-end 2006 reference price of $65.57 per
barrel. The New Zealand gas prices are based on existing contract prices. The
sales price for natural gas liquids is based on a reference price of $1.45 per
gallon adjusted as necessary for existing local market contracts. A differential
is applied to the oil, condensate, natural gas, and natural gas liquids
reference prices to adjust for transportation, geographic property location, and
quality or energy content. Product prices, direct operating costs, and future
capital expenditures are not escalated and therefore remain constant for the
projected life of each property. Swift represents that the provided product
sales prices and operating costs are in accordance with Securities and Exchange
Commission guidelines.
This audit has been conducted according to the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information approved by the Board
of Directors of the Society of Petroleum Engineers, Inc. Our audit included
examination, on a test basis, of the evidence supporting the reserves discussed
herein. In conducting our audit, we investigated each property to the level of
detail that we deem reasonably appropriate to form the judgements expressed
herein. We recognize the methods and procedures employed by Swift to accumulate
and evaluate the necessary information and to document and reconcile reserves,
annual production, and ownership interests are effective and are in accordance
with generally accepted practices.
Based on our investigations, it is our judgement that Swift used appropriate
engineering, geologic, and evaluation principles and methods that are consistent
with practices generally accepted in the petroleum industry. Reserve estimates
are based on extrapolation of established performance trends, material balance
calculations, volumetric calculations, analogy with the performance of
comparable wells, or a combination of these methods. Reserve estimates from
volumetric calculations or from analogies may be less certain than reserve
estimates based on well performance obtained over a period during which a
substantial portion of the reserve was produced.
Estimates of net cash flow and discounted net cash flow should not be
interpreted to represent the fair market value for the audited reserves. The
estimated reserves and cash flows discussed herein have not been adjusted for
uncertainty.
Future net cash flow as presented herein is defined as the future cash inflow
attributable to the evaluated interest less, if applicable, future operating
costs, ad valorem taxes, and future capital expenditures. Future cash inflow is
defined as gross cash inflow less, if applicable, royalties and severance taxes.
Future cash inflow and future net cash flow stated in this report exclude
consideration of state or federal income tax. Future costs of facility and well
abandonments and the restoration of producing properties to satisfy
environmental standards are not deducted from cash flow.
In conducting this audit, we relied on data supplied by Swift. The extent and
character of ownership, oil and natural gas sales prices, operating costs,
future capital expenditures, historical production, accounting, geological, and
engineering data were accepted as represented, and we have assumed the
authenticity of all documents submitted. No independent well tests, property
inspections, or audits of operating expenses were conducted by our staff in
conjunction with this work. We did not verify or determine the extent,
character, status, or liability, if any, of production imbalances, hedging
activities, or any current or possible future detrimental environmental site
conditions.
189
In order to audit the reserves and future cash flows estimated by Swift, we have
relied in part on geological, engineering, and economic data furnished by our
client. Although we instructed our client to provide all pertinent data, and we
made a reasonable effort to analyze it carefully with methods accepted by the
petroleum industry, there is no guarantee that the volumes of hydrocarbons or
the cash flows projected will be realized. The reserve and cash flow projections
discussed in this report may require revision as additional data become
available.
If investments or business decisions are to be made in reliance on these
judgements by anyone other than our client, such person, with the approval of
our client, is invited to visit our offices at his expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our opinions are based. This report is for general guidance
only, and responsibility for subsequent decisions resides with the decision
maker.
Any distribution or publication of this work or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES,INC.
Texas Registration Number F-000637
by: /s/ Marilyn Wilson
--------------------
Marilyn Wilson, P.E.
President and Chief Operating Officer
Attachment
MW:pab
190
ATTACHMENT I
191
DEFINITIONS OF PROVED OIL AND GAS RESERVES(1)
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir. ------------------------
(1) Contained in Securities and Exchange Commission Regulation S-X, Rule 4-10
(a)
192