UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 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 Drive, Suite 400
Houston, Texas 77060
(Address of principal executive offices) (Zip Code)
(281) 874-2700
(Registrant's telephone number, including area code)
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 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___
Indicate the number of shares outstanding of
each of the Issuer's classes of common
stock, as of the latest practicable date.
Common Stock 29,527,985 Shares
($.01 Par Value) (Outstanding at October 31, 2006)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets 3
- September 30, 2006 and December 31, 2005
Condensed Consolidated Statements of Income 4
- For the Three month and Nine month periods
ended September 30, 2006 and 2005
Condensed Consolidated Statements of
Stockholders' Equity 5 - For the Nine month
period ended September 30, 2006 and
year ended December 31, 2005
Condensed Consolidated Statements of Cash Flows 6
- For the Nine month periods ended September 30, 2006
and 2005
Notes to Condensed Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition 26
and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk 40
Item 4. Controls and Procedures 41
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 42
Item 1A. Risk Factors 42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders None
Item 5. Other Information None
Item 6. Exhibits 42
SIGNATURES 43
2
Condensed Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
September 30, 2006 December 31, 2005
-------------------- -------------------
ASSET
Current Assets:
Cash and cash equivalents $ 95,117,902 $ 53,004,562
Accounts receivable-
Oil and gas sales 59,980,011 45,518,260
Joint interest owners 1,167,963 1,082,187
Other Receivables 17,701,312 3,795,080
Other current assets 38,394,344 11,655,046
-------------------- -------------------
Total Current Assets 212,361,532 115,055,135
-------------------- -------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties 1,979,294,070 1,731,866,298
Unproved properties 84,541,410 87,553,220
-------------------- -------------------
2,063,835,480 1,819,419,518
Furniture, fixtures, and other equipment 26,701,704 15,313,277
-------------------- -------------------
2,090,537,184 1,834,732,795
Less - Accumulated depreciation, depletion, and amortization (875,819,720) (755,699,056)
-------------------- -------------------
1,214,717,464 1,079,033,739
-------------------- -------------------
Other Assets:
Debt issuance costs 7,130,221 8,026,780
Restricted assets 2,293,895 2,296,968
-------------------- --------------------
9,424,116 10,323,748
-------------------- -------------------
$ 1,436,503,112 $ 1,204,412,622
==================== ===================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 55,293,512 $ 51,973,004
Accrued capital costs 42,974,178 30,073,728
Accrued interest 10,336,338 8,508,196
Undistributed oil and gas revenues 8,948,655 7,866,086
-------------------- -------------------
Total Current Liabilities 117,552,683 98,421,014
-------------------- -------------------
Long-Term Debt 350,000,000 350,000,000
Deferred Income Taxes 196,797,908 129,306,891
Asset Retirement Obligation 20,089,268 19,095,368
Lease Incentive Obligation 1,787,893 271,182
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,
29,727,913 and 29,458,974 shares issued, and 29,300,827
and 29,009,530 shares outstanding, respectively 297,279 294,590
Additional paid-in capital 374,559,260 365,085,695
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 380,597,278 254,302,757
Accumulated other comprehensive income (loss), net of income tax 946,487 (69,469)
-------------------- -------------------
750,275,360 607,318,167
-------------------- -------------------
$ 1,436,503,112 $ 1,204,412,622
==================== ===================
See accompanying notes to condensed consolidated financial statements.
3
Condensed Consolidated Statements of Income
Swift Energy Company and Subsidiaries
Three Months Ended Nine Months Ended
------------------------------ ---------------------------------
09/30/06 09/30/05 09/30/06 09/30/05
------------- -------------- -------------- -------- --------
Revenues:
Oil and gas sales $ 173,368,549 $ 101,007,524 $ 453,315,519 $ 301,451,257
Price-risk management and other, net 90,303 (154,019) 3,489,510 (677,143)
------------- -------------- -------------- -----------------
173,458,852 100,853,505 456,805,029 300,774,114
------------- -------------- -------------- -----------------
Costs and Expenses:
General and administrative, net 8,018,260 5,803,946 23,323,223 15,674,141
Depreciation, depletion and amortization 45,867,715 23,870,287 120,151,446 76,853,296
Accretion of asset retirement obligation 171,545 191,529 665,812 565,531
Lease operating costs 12,926,110 12,221,153 45,843,648 34,835,158
Severance and other taxes 18,489,838 9,670,565 49,210,714 29,582,400
Interest expense, net 5,776,220 6,194,370 17,436,326 18,825,273
------------- -------------- -------------- -----------------
91,249,688 57,951,850 256,631,169 176,335,799
------------- -------------- -------------- -----------------
Income Before Income Taxes 82,209,164 42,901,655 200,173,860 124,438,315
Provision for Income Taxes 31,397,597 15,394,756 73,879,339 43,360,606
------------- -------------- -------------- -----------------
Net Income $ 50,811,567 $ 27,506,899 $ 126,294,521 $ 81,077,709
============= ============== ============== =================
Per Share Amounts
Basic: Net Income $ 1.74 $ .96 $ 4.33 $ 2.86
============= ============== ============== =================
Diluted: Net Income $ 1.68 $ .92 $ 4.20 $ 2.77
============= ============== ============== =================
Weighted Average Shares Outstanding 29,251,945 28,632,895 29,161,278 28,390,120
============= ============== ============== =================
See accompanying notes to condensed consolidated financial statements.
4
Condensed Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
Additional Other
Common Paid-In Treasury Unearned Retained Comprehensive
Stock(1) Capital Stock Compensation Earnings Income(Loss) Total
--------- ------------ ----------- ------------ ------------ ------------- ------------
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
Other Comprehensive Income --- --- --- --- --- (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
(210,738 shares) 2,107 3,615,470 --- --- --- --- 3,617,577
Adoption of SFAS No. 123R --- (5,875,280) --- 5,849,820 --- --- (25,460)
Excess tax benefits from
stock-based awards --- 2,772,329 --- --- --- --- 2,772,329
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 --- 7,576,249 --- --- --- --- 7,576,249
Comprehensive Income:
Net income --- --- --- --- 126,294,521 --- 126,294,521
Other Comprehensive Income --- --- --- --- --- 1,015,956 1,015,956
------------
Total Comprehensive Income 127,310,477
--------- ------------ ----------- ------------ ------------ ------------- ------------
Balance, September 30, 2006 $ 297,279 $374,559,260 $(6,124,944) $ --- $380,597,278 $ 946,487 $750,275,360
========= ============ =========== ============ ============ ============= ============
(1) $.01 Par Value
See accompanying notes to condensed consolidated financial statements.
5
Condensed Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
Nine Months Ended September 30,
------------------------------------
2006 2005
----------------- ----------------
Cash Flows from Operating Activities:
Net income $ 126,294,521 $ 81,077,709
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization 120,151,446 76,853,296
Accretion of asset retirement obligation 665,812 565,531
Deferred income taxes 67,169,122 42,610,606
Stock-based compensation expense 5,057,142 1,005,904
Other (3,678,105) 1,230,677
Change in assets and liabilities-
(Increase) decrease in accounts receivable (14,547,527) 15,162,260
Increase in accounts payable and accrued
liabilities 7,404,437 739,152
Increase in income taxes payable 337,716 87,551
Increase in accrued interest 1,828,142 1,127,146
----------------- ----------------
Net Cash Provided by Operating Activities 310,682,706 220,459,832
----------------- ----------------
Cash Flows from Investing Activities:
Additions to property and equipment (291,308,227) (158,125,266)
Proceeds from the sale of property and equipment 20,336,133 2,387,293
Net cash distributed as operator of oil and gas
properties (4,193,748) (2,183,944)
Net cash received (distributed) as operator of
partnerships and joint ventures 854,672 (467,534)
Other (30,782) 64,480
----------------- ----------------
Net Cash Used in Investing Activities (274,341,952) (158,324,971)
----------------- ----------------
Cash Flows from Financing Activities:
Payments of bank borrowings --- (7,500,000)
Net proceeds from issuances of common stock 4,288,907 6,329,431
Excess tax benefits from stock-based awards 1,483,679 ---
----------------- ----------------
Net Cash Provided by (Used in)Financing 5,772,586 (1,170,569)
Activities
----------------- ----------------
Net Increase in Cash and Cash Equivalents $ 42,113,340 $ 60,964,292
Cash and Cash Equivalents at Beginning of Period 53,004,562 4,920,118
----------------- ----------------
Cash and Cash Equivalents at End of Period $ 95,117,902 $ 65,884,410
================== =================
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts
capitalized $ 14,721,356 $ 16,887,396
Cash paid during period for income taxes $ 6,372,500 $ 750,000
See accompanying notes to condensed consolidated financial statements.
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SWIFT ENERGY COMPANY AND SUBSIDIARIES
(1) General Information
The condensed consolidated financial statements included herein have
been prepared by Swift Energy Company and reflect necessary adjustments,
all of which were of a recurring nature, and are in the opinion of our
management necessary for a fair presentation. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with accounting principles generally accepted in the United
States have been omitted pursuant to the rules and regulations of the
Securities and Exchange Commission. We believe that the disclosures
presented are adequate to allow the information presented not to be
misleading. The condensed consolidated financial statements should be read
in conjunction with the audited financial statements and the notes thereto
included in the latest Annual Report on Form 10-K as filed with the
Securities and Exchange Commission.
(2) Summary of Significant Accounting Policies
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 continues to trade on the New York and
NYSE Arca (formerly the Pacific Stock Exchange) Exchanges. 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 three 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 amended 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.
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 nine months ended September 30, 2006 and 2005, such
internal costs capitalized totaled $20.7 million and $13.4 million,
respectively. Interest costs are also capitalized to unproved oil and gas
properties. For the nine months ended September 30, 2006 and 2005,
capitalized interest on unproved properties totaled $6.6 million and $5.3
million, respectively. Interest not capitalized and general and
administrative costs related to production and general 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.
7
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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
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,
natural 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, held at cost, are
depreciated by the straight-line method at rates based on the estimated
useful lives of the property, which range between two 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
country-by-country 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, the political stability in
the countries in which we have an investment, 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 natural 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 September 30, 2006 consisted of crude oil 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 depreciation,
depletion, and amortization ("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.
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.
8
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Principles of Consolidation
The accompanying consolidated financial statements include the accounts
of Swift Energy Company 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
natural gas processing plants, and investments in oil and gas limited
partnerships where we are the general partner 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.
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 September 30, 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 both September 30, 2006 and December 31, 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. Receivables
related to insurance reimbursement are computed in accordance with
applicable accounting guidance; and we monitor our costs incurred and
their collectibility under our insurance policies and believe all amounts
recorded are recoverable.
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
September 30, 2006 December 31, 2005
(000's) (000's)
------------------ -----------------
Materials, Supplies and Tubulars $ 11,146 $ 8,494
Crude Oil 662 916
------------------ -----------------
Total $ 11,808 $ 9,410
================== =================
9
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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
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 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 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.
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. The effective tax rate for
the nine months ended September 30, 2006 and 2005 was higher than the U.S.
Federal statutory tax rate primarily due to state income taxes, partially
offset by reductions from the New Zealand statutory rate attributable to
the currency effect on the New Zealand deferred tax calculation. As of
September 30, 2006, we believe we have utilized all of our U.S. federal
operating loss carryforwards during the 2006 tax year.
Accounts Payable and Accrued Liabilities
Included in "Accounts payable and accrued liabilities," on the
accompanying balance sheets, at September 30, 2006 and December 31, 2005
are liabilities of approximately $9.8 million and $9.9 million,
respectively, representing the amount by which checks issued, but not
presented to the Company's banks for collection, exceeded balances in the
applicable disbursement bank accounts.
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 September 30, 2006, we
recorded $0.9 million, net of taxes of $0.6 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:
10
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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 (17,520) 6,517 (11,003)
Effect of cash flow hedges settled
during the period 1,632,363 (605,404) 1,026,959
------------------- ----------------- -------------------
Other comprehensive income at September 30, 2006 $ 1,504,749 $ (558,262) $ 946,487
=================== ================= ===================
Total comprehensive income was $52.2 million and $27.7 million for the
third quarters of 2006 and 2005, respectively. Total comprehensive income
was $127.3 and $80.5 million for the first nine months of 2006 and 2005,
respectively.
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 the third quarters of 2006
and 2005, we recognized a net loss of $0.4 million relating to our
derivative activities. During the first nine months of 2006 and 2005, we
recognized a net gain of $1.6 million and a net loss of $0.9 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 September 30, 2006, the Company had recorded $0.9
million, net of taxes of $0.6 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 amount of ineffectiveness reported in "Price-risk management
and other, net" for the first nine months of 2006 and 2005 were 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.
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 oil and 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 oil and 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.
At September 30, 2006, we had in place price floors in effect for
October 2006 through the December 2006 contract month for oil that cover a
portion of our domestic oil production for October 2006 to December 2006.
The oil price floors cover notional volumes of 900,000 barrels with a
weighted average floor price of $63.77 per barrel. Our oil price floors in
place at September 30, 2006 are expected to cover approximately 45% to 50%
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
of our estimated domestic oil production from October 2006 to December
2006. The fair value of these instruments at September 30, 2006, was $2.7
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. The total amount of supervision fees charged to the wells we
operate was $6.4 million and $5.8 million in the first nine months of 2006
and 2005, respectively.
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 upon settlement which is
included in 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. The following provides a roll-forward of our asset
retirement obligation:
2006 2005
---------------- ---------------
Asset Retirement Obligation recorded as of January 1 $ 19,356,367 $ 17,639,136
Accretion expense for the nine months ended September 30 665,812 565,531
Liabilities incurred for new wells and facilities
construction 552,591 63,772
Reductions due to sold, or plugged and abandoned wells (202,902) (360,104)
Decrease due to currency exchange rate fluctuations (21,600) (27,755)
---------------- ---------------
Asset Retirement Obligation as of September 30 $ 20,350,268 $ 17,880,580
---------------- ---------------
At both September 30, 2006 and December 31, 2005, approximately $0.3
million of our asset retirement obligation is classified as a current
liability in "Accounts payable and accrued liabilities" on the
accompanying balance sheets.
New Accounting Pronouncements
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3.
SFAS No. 154 requires voluntary changes in accounting principles to be
applied retrospectively, unless it is impracticable. SFAS No. 154's
retrospective application requirement replaces APB 20's requirement to
recognize most voluntary changes in accounting principle by including in
net income of the period of the change the cumulative effect of changing
to the new accounting principle. If retrospective application for all
prior periods is impracticable, the method used to report the change and
the reason the retrospective application is impracticable are to be
disclosed.
Under SFAS No. 154, retrospective application will be the transition
method in the unusual instance that a newly issued accounting
pronouncement does not provide specific transition guidance. It is
12
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
expected that many pronouncements will specify transition methods other
than retrospective. SFAS No. 154 is effective for accounting changes made
in fiscal years beginning after December 15, 2005, and 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 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 Company has not yet determined what
impact, if any, this Interpretation will have 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 Interpretation will have on its financial position or
results of operations.
(3) Share-Based Compensation
We have various types of share-based compensation plans. Refer to Note
6 of our consolidated financial statements in our Annual Report on Form
10-K for the fiscal year ended December 31, 2005, for additional
information related to these share-based compensation plans.
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 nine
months ended September 30, 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
three months ended September 30, 2006, were $0.7 million, $0.6 million,
$0.02, and $0.02 lower, respectively, than if we had continued to account
for share-based compensation under APB Opinion No. 25 for our stock option
grants. For the nine months ended September 30, 2006, income before taxes,
net income and basic and diluted earnings per share were $2.7 million,
$2.2 million, $0.07, and $0.07 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 condensed
consolidated statements of operations.
13
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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 condensed 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 $0.6 million and $1.5 million for the three and
nine months ended September 30, 2006, respectively.
Net cash proceeds from the exercise of stock options were $3.6 million
for the nine months ended September 30, 2006. The actual income tax
benefit realized from stock option exercises was $2.0 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 condensed consolidated statements
of income, and was $1.8 million and $0.6 million for the quarter ended
September 30, 2006 and 2005, respectively. Stock compensation expense for
the nine months ended September 30, 2006, and 2005 was $5.1 million and
$1.0 million. 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 following table illustrates the effect on September 30, 2005
operating results and per share information had the Company accounted for
share-based compensation in accordance with SFAS No. 123R. Our net income
and earnings per share would have been adjusted to the following pro forma
amounts:
Three Months Nine Months
Ended Ended
September 30, September 30,
2005 2005
--------------- -------------
Net Income: As Reported $27,506,899 $81,077,709
Stock-based employee compensation
expense determined under fair value
method for all awards, net of tax (995,399) (2,968,488)
--------------- -------------
Pro Forma $26,511,500 $78,109,221
Basic EPS: As Reported $.96 $2.86
Pro Forma $.93 $2.75
Diluted EPS: As Reported $.92 $2.77
Pro Forma $.89 $2.67
14
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -----------------------
2006 2005 2006 2005
------------------------- -----------------------
Dividend yield 0% 0% 0% 0%
Expected volatility 39.1% 41.2% 39.5% 42.5%
Risk-free interest rate 4.8% 3.9% 4.9% 3.8%
Expected life of options (in years) 2.6 3.9 5.6 3.5
Weighted-average grant-date fair value $ 12.20 $ 15.92 $ 19.31 $ 10.64
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 September 30, 2006, there was $3.6 million of unrecognized
compensation cost related to stock options which is expected to be
recognized over a weighted-average period of 1.6 years.
The following table represents stock option activity for the nine
months ended September 30, 2006:
September 30, 2006
----------------------------------------
Wtd. Avg. Wtd. Avg.
Shares Exer. Price Contract Life
------------ ----------- -------------
Options outstanding, beginning of period 2,118,179 $ 21.28
Options granted 164,303 $ 43.56
Options canceled (51,578) $ 22.29
Options exercised (239,035) $ 19.97
------------ -------------
Options outstanding, end of period 1,991,869 $ 23.25 5.4 Yrs
============ =============
Options exercisable, end of period 1,182,688 $ 22.71 4.1 Yrs
============ =============
The aggregate intrinsic value of options outstanding at September 30,
2006 was $37.6 million, and the aggregate intrinsic value of options
exercisable was $22.6 million. Total intrinsic value of options exercised
was $5.4 million for the nine months ended September 30, 2006.
Restricted Stock
The plans, as described in Note 6 of our consolidated financial
statements in our Annual Report on Form 10-K for the fiscal year ended
December 31, 2005, allow for the issuance of restricted stock awards that
may not be sold or otherwise transferred until certain restrictions have
lapsed. The unrecognized compensation cost related to these awards is
expected to be expensed over the period the restrictions lapse (generally
one to five years).
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 September 30, 2006,
we have unrecognized compensation expense of approximately $15.0 million
associated with these awards which are expected to be recognized over a
weighted-average period of 2.4 years.
15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
The following table represents restricted stock activity for the nine
months ended September 30, 2006:
September 30, 2006
Wtd. Avg.
Shares Grant Price
------------ ------------
Restricted shares outstanding, beginning of
period 236,950 $ 34.79
Restricted shares granted 310,956 $ 43.25
Restricted shares canceled (21,530) $ 38.90
Restricted shares vested (35,776) $ 24.57
------------
Restricted shares outstanding, end of period 490,600 $ 39.98
============
(4) 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 to employees using the treasury stock method.
Certain of our stock options, that could potentially dilute Basic EPS in
the future, were antidilutive for periods ended September 30, 2006 and
2005, and are discussed below.
The followig is a reconciliation of the numerators and denominators
used in the calculation of Basic and Diluted EPS for the periods ended
September 30, 2006 and 2005:
Three Months Ended September 30,
----------------------------------------------------------------------------------
2006 2005
----------------------------------------- ---------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------- ------------ ------------ ------------ ----------- ------------
Basic EPS:
Net Income and Share Amounts......$ 50,811,567 29,251,945 $ 1.74 $ 27,506,899 28,632,895 $ 0.96
Dilutive Securities:
Restricted Stock ................. --- 130,905 --- 71,815
Stock Options .................... --- 801,025 --- 1,081,254
-------------- ------------ ------------ -----------
Diluted EPS:
Net Income and Assumed Share
Conversions ....................$ 50,811,567 30,183,875 $ 1.68 $ 27,506,899 29,785,964 $ 0.92
------------- ------------ ------------ -----------
Nine Months Ended September 30,
----------------------------------------------------------------------------------
2006 2005
----------------------------------------- ---------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------- ------------ ------------ ----------- ----------- ------------
Basic EPS:
Net Income and Share Amounts......$ 126,294,521 29,161,278 $ 4.33 $ 81,077,709 28,390,120 $ 2.86
Dilutive Securities:
Restricted Stock ................. --- 124,528 --- 37,194
Stock Options .................... --- 777,587 --- 866,822
-------------- ------------ ------------ -----------
Diluted EPS:
Net Income and Assumed Share
Conversions ....................$ 126,294,521 30,063,393 $ 4.20 $ 81,077,709 29,294,136 $ 2.77
------------- ------------ ------------ -----------
16
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Options to purchase approximately 2.0 million shares at an average
exercise price of $23.25 were outstanding at September 30, 2006, while
options to purchase 2.4 million shares at an average exercise price of
$20.24 were outstanding at September 30, 2005. Approximately 1.6 million
and less than 0.1 million stock options and non-vested shares of
restricted stock were not included in the computation of Diluted EPS for
the three-month periods ended September 30, 2006, and 2005, respectively,
and 1.6 million and 0.2 million options and non-vested shares of
restricted stock were not included in the computation of Diluted EPS for
the nine-month periods ended September 30, 2006, and 2005, respectively,
because these options were antidilutive in that the option price was
greater than the average closing market price for the common shares during
those periods.
(5) Long-Term Debt
Our long-term debt, including the current portion, as of September 30,
2006 and December 31, 2005, was as follows (in thousands):
September 30, December 31,
2006 2005
------------------ -------------------
Bank Borrowings .................................. $ --- $ ---
7-5/8% senior notes due 2011 ..................... 150,000 150,000
9-3/8% senior subordinated notes due 2012 ........ 200,000 200,000
------------------ -------------------
Long-Term Debt ............... $ 350,000 $ 350,000
------------------ -------------------
Bank Borrowings
At September 30, 2006, we had no outstanding borrowings under our
$400.0 million credit facility with a syndicate of ten banks that had a
borrowing base of $250.0 million and expires in October 2008. The interest
rate is either (a) the lead bank's prime rate (8.25% at September 30,
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. On October 2, 2006, we increased the
credit facility amount by $100.0 million to $500.0 million, and extended
the expiration date by roughly three years to October 3, 2011 from October
1, 2008, see footnote eight "Subsequent Events."
The terms of our credit facility at September 30, 2006, include, among
other restrictions, a limitation on the level of cash dividends (not to
exceed $5.0 million in any fiscal year), a remaining aggregate limitation
on purchases of our stock of $15.0 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 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 amount is re-determined at least every six months and
was increased by our bank group to $250.0 million effective October 2,
2006, at our request from $150 million. Under the terms of the 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. The next scheduled borrowing base review is on May 1, 2007.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $0.2 million for each of the
three month period ended September 30, 2006 and 2005, and $0.6 million and
$0.8 million for the nine month period ended September 30, 2006 and 2005.
The amount of commitment fees included in interest expense, net was $0.1
million for each of the three month period ended September 30, 2006 and
2005, and $0.4 million for each of the nine months ended September 30,
2006 and 2005.
17
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Senior Notes Due 2011
These notes consist of $150.0 million of 7-5/8% senior notes due 2011,
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 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 $3.0 million for both the
three months ended September 30, 2006 and 2005, respectively, and $8.9
million for each of the nine months ended September 30, 2006 and 2005,
respectively.
Senior Subordinated Notes Due 2012
These notes consist of $200.0 million of 9-3/8% senior subordinated
notes due May 2012, which were issued on April 16, 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 and 7-5/8% senior notes.
Interest on these notes is payable semiannually on May 1 and November 1,
and commenced 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. In addition, prior to May 1, 2005, we could have redeemed up to
33.33% of these notes with the net proceeds of qualified offerings of our
equity at 109.375% of the principal amount of these notes, plus accrued
and unpaid interest. 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.
Interest expense on the 9-3/8% senior subordinated notes due 2012,
including amortization of debt issuance costs totaled $4.8 million for
each of the three month periods ended September 30, 2006 and 2005, and
$14.4 million for each of the nine month periods ended September 30, 2006
and 2005.
The aggregate maturities on our long-term debt are $150 million for
2011 and $200 million for 2012.
We have capitalized interest on our unproved properties in the amount
of $2.2 million and $1.8 million for the three month periods ended
September 30, 2006 and 2005, respectively, and $6.6 million and $5.3
million for the nine month periods ended September 30, 2006 and 2005,
respectively.
18
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
(6) Foreign Activities
As of September 30, 2006, our gross capitalized oil and gas property
costs in New Zealand totaled approximately $340.3 million. Approximately
$324.9 million has been included in the "Proved properties" portion of our
oil and gas properties, while $15.4 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 $266.4 million at September
30, 2006.
(7) Acquisitions and Dispositions
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 2005, we acquired
additional interests in this field. We paid approximately $4.6 million in
cash for these additional interests. After taking into account internal
acquisition costs of $0.6 million, our total cost was $5.2 million. We
allocated $4.9 million of the acquisition price to "Proved properties,"
$0.4 million to "Unproved properties," and recorded a liability for $0.1
million to "Asset retirement obligation" on our accompanying consolidated
balance sheets. 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 of acquisition forward,
however, given the acquisitions were in November and December 2005, these
amounts were immaterial for 2005.
In April 2006, we sold our minority interests in the Brookeland and
Masters Creek 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.
(8) Subsequent Events
In October 2006, we acquired interests in five South Louisiana fields
from BP America Production Company. The total price for these interests
was approximately $169 million. The property interests are located
primarily 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 have recorded $17.5 million in
"Other current assets" at September 30, 2006 related to the deposit for
this acquisition. In addition, we have acquired virtually all of the
outstanding interest in the South Bearhead Creek field, located in
Beauregard Parish, Louisiana, for approximately $4.5 million in November
2006.
In October 2006, we settled all insurance claims with our insurers
relating to hurricanes Katrina and Rita and entered into a confidential
final settlement agreement. The receipt of these amounts is expected to
result in a benefit of $7.7 million in the fourth quarter of 2006, for the
portion of the above referenced settlement, which we have determined to be
non-property damage related claims, based on internal calculations.
On October 2, 2006, we increased the credit facility amount by $100.0
million to $500.0 million, and extended the expiration date by roughly
three years to October 3, 2011 from October 1, 2008. The other terms of
the credit facility, including the borrowing base amount and commitment
amount, stayed substantially the same. Certain of the covenants imposed by
this credit facility were amended with the extension of the facility to be
less restrictive on various corporate actions and are discussed below. 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 which increased from $5.0 million), a remaining aggregate
limitation on purchases of our stock of $50.0 million which increased from
$15.0 million, requirements as to maintenance of certain minimum financial
ratios (principally pertaining to adjusted working capital ratios and
19
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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.
The borrowing base amount is re-determined at least every six months and
was increased by our bank group to $250.0 million effective October 2,
2006, at our request from $150 million.
(9) 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 2). Pursuant to the amendment, 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 amendment, Swift Energy Company was the sole obligor.
The following is condensed consolidating financial information for Swift
Energy Company, Swift Energy Operating, LLC, and significant subsidiaries:
Condensed Consolidating Balance Sheets
(in 000's) September 30, 2006
------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ ------------ ----------------
ASSETS
Current assets $ --- $ 191,681 $ 20,681 $ --- $ 212,362
Property and equipment --- 972,444 242,273 --- 1,214,717
Investment in subsidiaries (equity method) 750,275 --- 544,086 (1,294,361) ---
Other assets --- 41,187 655 (32,417) 9,424
---------------- -------------- ------------ ------------ ----------------
Total assets $ 750,275 $ 1,205,312 $ 807,695 $ (1,326,778) $ 1,436,503
================ ============== ============ ============ ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ --- $ 103,274 $ 14,279 $ --- $ 117,553
Long-term liabilities --- 557,951 43,141 (32,417) 568,675
Stockholders' equity 750,275 544,086 750,275 (1,294,361) 750,275
---------------- -------------- ------------ ------------ ----------------
Total liabilities and
stockholders' equity $ 750,275 $ 1,205,312 $ 807,695 $ (1,326,778) $ 1,436,503
================ ============== ============ ============ ================
20
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
(in 000's) December 31, 2005
------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Eliminations 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
================ ============== ============ ============ ================
Condensed Consolidating Statements of Income
(in 000's) Three Months Ended September 30, 2006
------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ ------------ ----------------
Revenues $ --- $ 153,279 $ 20,179 $ --- $ 173,459
Expenses --- 77,409 13,841 --- 91,250
---------------- - ------------- ------------ ------------ ----------------
Income (loss) before the following: --- 75,871 6,338 --- 82,209
Equity in net earnings of subsidiaries 50,812 --- 46,342 (97,154) ---
---------------- -------------- ------------ ------------ ----------------
Income before income taxes 50,812 75,871 52,681 (97,154) 82,209
Income tax provision (benefit) --- 29,528 1,869 --- 31,398
---------------- -------------- ------------ ------------ ----------------
Net income $ 50,812 $ 46,342 $ 50,812 $ (97,154) $ 50,812
================ =============== ============ ============ ================
21
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
(in 000's) Nine Months Ended September 30, 2006
------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ ------------ ----------------
Revenues $ --- $ 406,080 $ 50,725 $ --- $ 456,805
Expenses --- 218,391 38,241 --- 256,631
---------------- -------------- ------------ ------------ ----------------
Income (loss) before the following: --- 187,690 12,484 --- 200,174
Equity in net earnings of subsidiaries 126,295 --- 116,811 (243,105) ---
---------------- -------------- ------------ ------------ ----------------
Income before income taxes 126,295 187,690 129,295 (243,105) 200,174
Income tax provision (benefit) --- 70,879 3,000 --- 73,879
---------------- -------------- ------------ ------------ ----------------
Net income $ 126,295 $ 116,811 $ 126,295 $ (243,105) $ 126,295
================ ============== ============ ============ ================
(in 000's) Three Months Ended September 30, 2005
------------------------------------------------------------------------------
Swift Energy Co.
(Parent and
Issuer) Subsidiaries Eliminations Swift Energy Co.
----------------- -------------- ------------ ----------------
Revenues $ 81,220 $ 19,633 $ --- $ 100,853
Expenses 46,057 11,895 --- 57,952
---------------- -------------- ------------ ----------------
Income (loss) before the following: 35,163 7,738 --- 42,901
Equity in net earnings of subsidiaries 5,838 --- (5,838) ---
---------------- -------------- ------------ ----------------
Income before income taxes 41,001 7,738 (5,838) 42,901
Income tax provision (benefit) 13,494 1,900 --- 15,394
----------------- -------------- ------------ ----------------
Net income $ 27,507 $ 5,838 $ (5,838) $ 27,507
================ ============== ============ ================
22
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
(in 000's) Nine Months Ended September 30, 2005
----------------------------------------------------------------
Swift Energy Co.
(Parent and Other Swift Energy Co.
Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ ----------------
Revenues $ 246,946 $ 53,830 $ (2) $ 300,774
Expenses 141,940 34,398 (2) 176,336
---------------- -------------- ------------ ----------------
Income (loss) before the following: 105,006 19,432 --- 124,438
Equity in net earnings of subsidiaries 15,346 --- (15,346) ---
---------------- -------------- ------------ ----------------
Income before income taxes 120,352 19,432 (15,346) 124,438
Income tax provision (benefit) 39,274 4,086 --- 43,360
---------------- -------------- ------------ ----------------
Net income $ 81,078 $ 15,346 $ (15,346) $ 81,078
================ ============== ============ ================
Condensed Consolidating Statements of Cash Flows
(in 000's) Nine Months Ended September 30, 2006
------------------------------------------------------------------------------
Swift Energy Co. Swift Energy
(Parent and Operating, LLC Other Swift Energy Co.
Co-obligor) (Co-obligor) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ ------------ ----------------
Cash flow from operations $ --- $ 281,570 $ 29,113 $ --- $ 310,683
Cash flow from investing activities --- (237,602) (46,844) 10,105 (274,342)
Cash flow from financing activities --- 5,773 10,105 (10,105) 5,773
---------------- -------------- ------------ ------------ ----------------
Net increase in cash --- 49,740 (7,627) --- 42,113
Cash, beginning of period --- 44,911 8,094 --- 53,005
---------------- -------------- ------------ ------------ ----------------
Cash, end of period $ --- $ 94,651 $ 467 $ --- $ 95,118
================ ============= ============ ============ ================
(in 000's) Nine Months Ended September 30, 2005
------------------------------------------------------------------------------
Swift Energy Co.
(Parent and Other Swift EnergyCo.
Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- ------------ ----------------
Cash flow from operations $ 184,254 $ 36,206 $ --- $ 220,460
Cash flow from investing activities (129,713) (33,896) 5,284 (158,325)
Cash flow from financing activities (1,171) 5,284 (5,284) (1,171)
---------------- -------------- ------------ ----------------
Net increase (decrease) in cash 53,370 7,594 --- 60,964
Cash, beginning of period 205 4,715 --- 4,920
---------------- -------------- ------------ ----------------
Cash, end of period $ 53,575 $ 12,309 $ --- $ 65,884
================ ============== ============ ================
23
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
(10) Segment Information
The Company has two reportable segments, one domestic and one foreign,
both of which are in the business of 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, and
interest expense, net. Our reportable segments are managed separately
based on their geographic locations. Financial information by operating
segment is presented below:
Three Months Ended September 30,
----------------------------------------------------------------------------------------------
2006 2005
-------------------------------------------- -----------------------------------------------
Domestic New Zealand Total Domestic New Zealand Total
------------- ------------- -------------- -------------- ------------- --------------
Oil and gas sales $ 153,754,146 $ 19,614,403 $ 173,368,549 $ 81,692,754 $ 19,314,770 $ 101,007,524
Costs and Expenses:
Depreciation,
depletion and amortization 37,619,396 8,248,319 45,867,715 17,328,183 6,542,104 23,870,287
Accretion of asset
retirement obligation 133,846 37,699 171,545 157,442 34,087 191,529
Lease operating costs 9,620,102 3,306,008 12,926,110 8,903,988 3,317,165 12,221,153
Severance and other taxes 17,251,643 1,238,195 18,489,838 8,438,368 1,232,197 9,670,565
------------- ------------- -------------- -------------- ------------- --------------
Income from oil and gas
operations $ 89,129,159 $ 6,784,182 $ 95,913,341 $ 46,864,773 $ 8,189,217 $ 55,053,990
Price-risk management
and other, net 90,303 (154,019)
General and
administrative, net 8,018,260 5,803,946
Interest expense, net 5,776,220 6,194,370
-------------- --------------
Income Before Income Taxes $ 82,209,164 $ 42,901,655
============== ==============
24
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Nine Months Ended September 30,
-----------------------------------------------------------------------------------------------
2006 2005
--------------------------------------------- -----------------------------------------------
Domestic New Zealand Total Domestic New Zealand Total
-------------- ------------- -------------- -------------- ------------- --------------
Oil and gas sales $ 403,128,509 $ 50,187,010 $ 453,315,519 $ 248,399,764 $ 53,051,493 $ 301,451,257
Costs and Expenses:
Depreciation,
depletion and amortization 97,613,811 22,537,635 120,151,446 57,560,343 19,292,953 76,853,296
Accretion of asset
retirement obligation 555,002 110,810 665,812 465,465 100,066 565,531
Lease operating costs 36,341,501 9,502,147 45,843,648 25,651,928 9,183,230 34,835,158
Severance and other taxes 45,957,658 3,253,056 49,210,714 26,197,345 3,385,055 29,582,400
-------------- ------------- -------------- -------------- ------------- --------------
Income from oil and gas
Operations $ 222,660,537 $ 14,783,362 $ 237,443,899 $ 138,524,683 $ 21,090,189 $ 159,614,872
Price-risk management
and 3,489,510 (677,143)
other, net
General and
administrative, net 23,323,223 15,674,141
Interest expense, net 17,436,326 18,825,273
Income Before Income Taxes $ 200,173,860 $ 124,438,315
-------------- --------------
Total Assets $1,197,620,135 $ 238,882,977 $1,436,503,112 $ 886,525,732 $ 239,968,842 $1,126,494,574
============== ============== ============== ============== ============= ==============
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SWIFT ENERGY COMPANY AND SUBSIDIARIES
ITEM 2.
You should read the following discussion and analysis in conjunction
with our financial information and our condensed consolidated financial
statements and notes thereto included in this report and our Annual Report
on Form 10-K for the year ended December 31, 2005. The following
information contains forward-looking statements. For a discussion of
limitations inherent in forward-looking statements, see "Forward-Looking
Statements" on page 39 of this report.
Overview
Swift Energy had record net income, revenues, and production for the
third quarter 2006. Net income increased 85% to $50.8 million, revenues
increased 72% to $173.5 million, and production increased 39% to 18.8
Bcfe, all as compared to the hurricane-affected third quarter 2005 levels.
For the nine months ended September 30, 2006, net income increased 56% to
$126.3 million, revenues increased 52% to $456.8 million, and production
increased 15% to 51.6 Bcfe, all as compared to the same period in 2005.
The continued strong crude oil prices, increases in our domestic
production, and our recovery from the hurricanes of 2005 contributed to
these record increases. As a result of our domestic production increases,
71% of our third quarter production was liquid hydrocarbons, of which 64%
was crude oil and 7% was natural gas liquids.
New Zealand produced 3.5 Bcfe in the third quarter of 2006, a 19%
decrease from the same period in 2005. During the third quarter of 2006,
we were successful on one of three wells drilled in New Zealand and
suspended operations on another.
Our production in the Lake Washington Field averaged more than 18,500
net barrels of oil per day during the third quarter of 2006, achieving our
year-end exit rate goal ahead of plan. We successfully completed 11 of 14
wells in the third quarter of 2006, including 9 of 11 domestic development
wells drilled for a success rate of 82% for the quarter. As a result of
activity-to-date, as well as our recent Louisiana acquisitions, we are
increasing our 2006 annual production guidance to a range of 70.0 to 71.0
Bcfe from our previous guidance range of 68.8 to 70.5 Bcfe.
Our overall costs and expenses continued to increase during the third
quarter of 2006, as have costs across our sector due to tight industry
conditions. These increases were in line with our expectations, excluding
the insurance reimbursements as a result of the settlement during the
third quarter of our insurance claims due to Hurricanes Katrina and Rita,
the proceeds of which have not all been received. These costs also
increased as a result of our workforce expansion and expensing of stock
compensation. We expect cost pressures to continue to affect the industry
for the remainder of 2006.
A primary focus this year has been capitalizing on the geologic and
geophysical efforts that have become evident with some of our recent
successes, particularly at the Newport area in Lake Washington. We expect
the first set of our pre-stack depth migration of our Lake Washington 3-D
data to be completed in the fourth quarter of 2006, which will help us
understand Newport's deeper potential as well as the deeper horizons in
Lake Washington. We are widening our focus on activity at Bay de Chene and
Cote Blanche Island, which helps confirm our seismic interpretation and
should also help further define similar opportunities in other fault
blocks surrounding the salt feature in Bay De Chene. The 3-D seismic shoot
in Cote Blanche Island was completed early in the third quarter of 2006
and is now being processed. We expect to begin benefiting from this new
data with our drilling program in Cote Blanche Island during the second
half of 2007.
Very early in the fourth quarter of 2006, we closed on several
strategic acquisitions of interests in five additional fields in South
Louisiana and the consolidation of almost 100% of the working interests in
our South Bearhead Creek Field for approximately $169 million and $4.5
million, respectively. We believe these transactions add strategic anchor
assets in a very productive fairway that should benefit us and our
stakeholders for many years to come.
Since the end of the third quarter, we have accessed our line of credit
under our credit facility to help fund acquisition activity, along with
cash on hand. Early in the fourth quarter of 2006, we also increased our
credit facility to $500 million from $400 million and extended it about
three years to October 3, 2011.
26
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Our drilling program for the remainder of 2006 is to drill 4 additional
wells in the Lake Washington area, 5 additional wells in Bay de Chene,
with at least 2 wells in Bay de Chene being potential high impact
exploration wells with results expected in 2007. In New Zealand, plans are
underway to complete the Goss well in the Tikorangi formation for testing
and evaluation. We are in the midst of our 2007 capital planning and are
using a conservative price deck relative to commodity prices with the
continued goal of conducting operations within our cash flow. Crude oil
and natural gas prices have receded somewhat from the record highs earlier
in 2006 but still remain strong, particularly with respect to crude oil.
This year is shaping up to be a year of accomplishment for Swift
Energy. We have strengthened our balance sheet. We have built a large
regional 3-D seismic database that has enabled us to create the most
significant portfolio of prospects in Swift Energy's history. Our staff
has been executing and delivering on our strategic plan, which has led to
significant production growth. In the fourth quarter of 2006, our South
Louisiana drilling program will continue to target potentially high impact
exploration prospects and the Company will begin integrating the
additional five fields we acquired in South Louisiana, all of which are
covered by our 3-D seismic database. As Swift Energy concludes the
execution of our 2006 plan, we believe our activity and results will lead
to further visible value creation for our shareholders.
Results of Operations - Three Months Ended September 30, 2006 and 2005
Revenues. Our revenues in the third quarter of 2006 increased by 72%
compared to revenues in the same period in 2005, due primarily to an
increase in commodity prices and the production increase principally from
our Lake Washington field and reduced third quarter of 2005 volumes as a
result of the hurricanes. Revenues from our oil and gas sales comprised
substantially all of net revenues for the third quarter of 2006 and 2005.
In the third quarter of 2006, oil production made up 64% of total
production, natural gas made up 29%, and NGL represented 7%. In the third
quarter of 2005, oil production made up 47% of total production, natural
gas made up 44%, and NGL represented 9%. The percentage of our total
production from oil increased as Lake Washington production, which is
predominantly oil, increased over third quarter of 2005 levels.
Our third quarter 2006 weighted average prices increased 24% to $9.24
per Mcfe from $7.48 in the third quarter of 2005, with oil prices
appreciating 17% to $69.62 from $59.66, natural gas prices decreasing 8%
to $4.87 from $5.29, and NGL prices rising 14% to $36.18 from $31.84.
27
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes for the
periods ended September 30, 2006 and 2005:
Three Months Ended September 30,
--------------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
---- --------------------------------- -------------------------------------
2006 2005 2006 2005
---- ---- ---- ----
AWP Olmos .................... $ 13.4 $ 16.5 1.9 2.0
Brookeland ................... 4.7 6.5 0.6 0.8
Lake Washington .............. 116.1 46.6 10.5 4.9
Masters Creek ................ 3.3 4.5 0.4 0.5
Other ........................ 16.3 7.6 1.8 0.9
---------------- -------------- --------------- ----------------
Total Domestic ....... $ 153.8 $ 81.7 15.2 9.1
---------------- -------------- --------------- ----------------
Rimu/Kauri ................... 12.1 11.3 1.7 2.2
TAWN ......................... 7.5 8.0 1.8 2.2
---------------- -------------- --------------- ----------------
Total New Zealand ... $ 19.6 $ 19.3 3.5 4.4
---------------- -------------- --------------- ----------------
Total ........................ $ 173.4 $ 101.0 18.8 13.5
================ ============== =============== ================
The following table provides additional information regarding our quarterly
oil and gas sales:
Sales Volume Average Sales Price
------------ -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
---------- --------- --------- ----------- ----------- ---------- ----------
2006
----
Three Months Ended September 30:
Domestic ..................... 1,824 159 3.3 15.2 $69.54 $42.37 $6.07
New Zealand .................. 168 61 2.2 3.5 $70.49 $20.09 $3.04
---------- --------- --------- -----------
Total .................. 1,992 220 5.5 18.8 $69.62 $36.18 $4.87
========== ========= ========= ===========
2005
----
Three Months Ended September 30:
Domestic ..................... 925 119 2.8 9.1 $59.44 $40.58 $7.68
New Zealand .................. 134 85 3.1 4.4 $61.23 $19.50 $3.08
---------- --------- --------- -----------
Total .................. 1,059 204 5.9 13.5 $59.66 $31.84 $5.29
========== ========= ========= ===========
In the third quarter of 2006, our $72.4 million increase in oil, NGL,
and natural gas sales resulted from:
oPrice variances that had a $18.5 million favorable impact on sales, of
which $19.8 million was attributable to the 17% increase in
average oil prices received, $1.0 million was attributable to the
14% increase in average NGL prices received, offset by $2.3
million of decreases attributable to the 8% decrease in average
gas prices received; and
oVolume variances that had a $53.9 million favorable impact on sales,
with $55.7 million of increases coming from the 933,000 Bbl
increase in oil sales volumes, $0.5 million of increases
attributable to the 16,000 Bbl increase in NGL sales volumes,
offset by $2.3 million of decreases due to the 0.4 Bcf decrease in
gas sales volumes.
28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Costs and Expenses. Our expenses in the third quarter of 2006 increased
$33.3 million, or 57%, compared to expenses in the same period of 2005.
The increase was due to a $22.0 million increase in DD&A as our production
and depletable oil and gas property base increased, an $8.8 million
increase in severance and other taxes due to increased production volumes
and higher commodity prices in the third quarter of 2006, and a $2.2
million increase in net general and administrative expenses.
Our third quarter 2006 general and administrative expenses, net,
increased $2.2 million, or 38%, from the level of such expenses in the
same 2005 period. This increase was primarily due to an expansion of our
workforce and an increase in stock compensation expense resulting from the
adoption of SFAS No. 123R. Our stock compensation expense recorded in
general and administrative, net, increased by $1.2 million, net of
capitalized amounts, over third quarter of 2005 levels. For the third
quarters of 2006 and 2005, our capitalized general and administrative
costs, including capitalized stock compensation, totaled $8.1 million and
$4.6 million, respectively. Our capitalized general and administrative
expenses increased due to the expansion of our workforce and the
capitalization of stock compensation related to the geological and
geophysical workforce. Our net general and administrative expenses per
Mcfe produced were $0.43 per Mcfe in the third quarters of both 2006 and
2005. The portion of supervision fees recorded as a reduction to general
and administrative expenses was $2.2 million for the third quarter of 2006
and $2.0 million for the 2005 period.
DD&A increased $22.0 million, or 92%, in the third quarter of 2006 from
the level of those expenses in the same period of 2005. Domestically, DD&A
increased $20.3 million in the third quarter of 2006 due to increases in
the depletable oil and gas property base, including future development
costs and higher production in the 2006 period. In New Zealand, DD&A
increased by $1.7 million in the third quarter of 2006 due to increases in
the depletable oil and gas property base and lower reserves volumes,
partially offset by lower production in the 2006 period. Our DD&A rate per
Mcfe of production was $2.45 and $1.77 in the third quarters of 2006 and
2005, respectively.
We recorded $0.2 million of accretions to our asset retirement
obligation in both the third quarters of 2006 and 2005.
Our lease operating costs in the third quarter of 2006 increased $0.7
million, or 6%, over the level of such expenses in the same 2005 period.
Almost all of the increase was related to our domestic operations, which
increased primarily due to higher production from our South Louisiana area
and higher insurance costs. Offsetting the increase in costs and reducing
the lease operating cost per Mcfe, was recording of a reduction in lease
operating expense of $2.8 million related to the settlement of insurance
claims from hurricanes Katrina and Rita in the third quarter of 2006. Our
lease operating costs in New Zealand were $3.3 million in both the third
quarters of 2006 and 2005, respectively. Our lease operating costs per
Mcfe produced were $0.69 in the third quarter of 2006 and $0.91 in the
third quarter of 2005. Higher production volumes in the third quarter of
2006 over the third quarter of 2005 decreased the cost per Mcfe in the
2006 period.
In the third quarter of 2006, severance and other taxes increased $8.8
million, or 91%, over levels in the third quarter of 2005. The increase
was due primarily to higher commodity prices and increased Lake Washington
production. 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 10.7% and
9.6% in the third quarters of 2006 and 2005, respectively.
Our total interest cost in the third quarter of 2006 was $8.0 million,
of which $2.2 million was capitalized. Our total interest cost in the
third quarter of 2005 was also $8.0 million, of which $1.8 million was
capitalized. We capitalize a portion of interest related to unproved
properties. The decrease of interest expense in the third quarter of 2006
was primarily attributable to higher capitalized costs.
Our overall effective tax rate was 38.2% in the third quarter of 2006
and 35.9% in the third quarter of 2005. The effective income tax rate for
the third quarter of 2006 was higher than the U.S. statutory rate
29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
primarily due to state income taxes, an unfavorable rate impact for
non-deductible stock compensation, and was partially offset by reductions
from the New Zealand statutory rate attributable to the currency effect on
the New Zealand deferred tax calculation. The third quarter of 2005 rate
is lower due to a favorable correction in the New Zealand basis of oil and
gas properties.
Net Income. For the third quarter of 2006, our net income of $50.8
million was 85% higher, and Basic EPS of $1.74 was 81% higher, than our
third quarter of 2005 net income of $27.5 million and Basic EPS of $0.96.
Our Diluted EPS in the third quarter of 2006 of $1.68 was 82% higher than
our third quarter 2005 Diluted EPS of $0.92. These higher amounts are due
to our increased oil and gas revenues, which in turn were higher due to
continued strong commodity prices and increased production during the
third quarter of 2006.
Results of Operations - Nine Months Ended September 30, 2006 and 2005
Revenues. Our revenues in the first nine months of 2006 increased by
52% compared to revenues in the same period in 2005, due primarily to an
increase in commodity prices and the production increase principally from
our Lake Washington field. Revenues from our oil and gas sales comprised
substantially all of net revenues for the first nine months of 2006 and
2005. In the first nine months of 2006, oil production made up 61% of
total production volumes, natural gas made up 33%, and NGL represented 6%.
In the first nine months of 2005, oil production made up 51% of total
production volumes, natural gas made up 41%, and NGL represented 8%. The
percentage of our total production from oil increased as Lake Washington
production, which is predominantly oil, increased over 2005 levels.
Our first nine months of 2006 weighted average prices increased 31% to
$8.78 per Mcfe from $6.71 in the first nine months of 2005, with oil
prices appreciating 29% to $66.92 from $51.99, natural gas prices
increasing 6% to $5.02 from $4.73, and NGL prices rising 20% to $32.69
from $27.15.
30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes for the nine
months ended September 30, 2006 and 2005:
Nine Months Ended September 30,
-------------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
---- ---------------------------------- --------------------------------------
2006 2005 2006 2005
---- ---- ---- ----
AWP Olmos ..................... $ 42.0 $ 40.7 5.6 5.7
Brookeland .................... 12.3 14.6 1.6 2.2
Lake Washington ............... 300.7 160.1 28.3 19.5
Masters Creek ................. 10.8 13.6 1.3 2.0
Other ......................... 37.3 19.4 4.3 2.6
--------------- ----------------- ---------------- ---------------------
Total Domestic ........ $ 403.1 $ 248.4 41.1 32.0
--------------- ----------------- ---------------- ---------------------
Rimu/Kauri .................... 29.6 33.1 5.0 6.5
TAWN .......................... 20.6 20.0 5.5 6.4
--------------- ----------------- ---------------- ---------------------
Total New Zealand .... $ 50.2 $ 53.1 10.5 12.9
--------------- ----------------- ---------------- ---------------------
Total ......................... $ 453.3 $ 301.5 51.6 44.9
=============== ================= ================ =====================
The following table provides additional information regarding our oil
and gas sales for the nine months ended September 30, 2006 and 2005:
Sales Volume Average Sales Price
------------ -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
---------- --------- --------- ----------- ----------- ---------- ----------
2006
----
Nine Months Ended September 30:
Domestic ..................... 4,866 319 10.0 41.1 $66.75 $41.29 $6.53
New Zealand .................. 373 191 7.1 10.5 $69.13 $18.29 $2.92
---------- --------- --------- -----------
Total .................. 5,239 510 17.1 51.6 $66.92 $32.69 $5.02
========== ========= ========= ===========
2005
Nine Months Ended September 30:
Domestic ..................... 3,448 381 9.1 32.0 $51.65 $32.66 $6.38
New Zealand .................. 358 255 9.2 12.9 $55.25 $18.90 $3.10
---------- --------- --------- -----------
Total .................. 3,806 636 18.3 44.9 $51.99 $27.15 $4.73
========== ========= ========= ===========
In the first nine months of 2006, our $151.9 million increase in oil,
NGL, and natural gas sales resulted from:
oPrice variances that had a $86.2 million favorable impact on sales, of
which $78.3 million was attributable to the 29% increase in
average oil prices received, $5.1 million was attributable to the
6% increase in average gas prices received, and $2.8 million was
attributable to the 20% increase in average NGL prices received;
and
oVolume variances that had a $65.7 million favorable impact on sales,
with $74.5 million of increases coming from the 1,433,000 Bbl
increase in oil sales volumes, offset by $5.4 million of decreases
due to the 1.1 Bcf decrease in gas sales volumes, and $3.4 million
of decreases attributable to the 126,000 Bbl decrease in NGL sales
volumes.
31
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Costs and Expenses. Our expenses in the first nine months of 2006
increased $80.3 million, or 46%, compared to expenses in the same period
of 2005. The increase was due to a $43.3 million increase in DD&A as our
production and depletable oil and gas property base increased, a $19.6
million increase in severance and other taxes due to increased production
volumes and higher commodity prices in 2006, and an $11.0 million increase
in lease operating costs due to higher production and hurricane repair
costs.
Our first nine months of 2006 general and administrative expenses, net,
increased $7.6 million, or 49%, from the level of such expenses in the
same 2005 period. This increase was primarily due to an expansion of our
workforce and an increase in stock compensation expense resulting from the
adoption of SFAS No. 123R. Our stock compensation expense recorded in
general and administrative, net, increased by $3.9 million, net of
capitalized amounts, over the first nine months of 2005. For the nine
months of 2006 and 2005, our capitalized general and administrative costs,
including capitalized stock compensation, totaled $20.7 million and $13.4
million, respectively. Our capitalized general and administrative expenses
increased due to the expansion of our workforce and the capitalization of
stock compensation related to the geological and geophysical workforce.
Our net general and administrative expenses per Mcfe produced increased to
$0.45 per Mcfe in the first nine months of 2006 from $0.35 per Mcfe in the
same 2005 period. The portion of supervision fees recorded as a reduction
to general and administrative expenses was $6.4 million for the first nine
months of 2006 and $5.8 million for the 2005 period.
DD&A increased $43.3 million, or 56%, in the first nine months of 2006
from the level of those expenses in the same period of 2005. Domestically,
DD&A increased $40.1 million in the first nine months of 2006 due to
increases in the depletable oil and gas property base, including future
development costs, and higher production in the 2006 period. In New
Zealand, DD&A increased by $3.2 million in the first nine months of 2006
due to increases in the depletable oil and gas property base and lower
reserves volumes, partially offset by lower production in the 2006 period.
Our DD&A rate per Mcfe of production was $2.33 and $1.71 in the first nine
months of 2006 and 2005, respectively.
We recorded $0.7 million and $0.6 million of accretions to our asset
retirement obligation in the first nine months of 2006 and 2005,
respectively.
Our lease operating costs in the first nine months of 2006 increased
$11.0 million, or 32%, over the level of such expenses in the same 2005
period. Almost all of the increase was related to our domestic operations,
which increased primarily due to higher production from our South
Louisiana area and higher insurance costs. Our lease operating costs in
New Zealand increased in the first nine months of 2006 by $0.3 million due
to planned maintenance work. Our lease operating costs per Mcfe produced
were $0.89 in the first nine months of 2006 and $0.78 in the first nine
months of 2005.
In the first nine months of 2006, severance and other taxes increased
$19.6 million, or 66%, over levels in the first nine months of 2005. The
increase was due primarily to higher commodity prices and increased Lake
Washington production. 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% and 9.8% in the first nine months of 2006 and 2005,
respectively.
Our total interest cost in the first nine months of 2006 was $24.0
million, of which $6.6 million was capitalized. Our total interest cost in
the first nine months 2005 was $24.1 million, of which $5.3 million was
capitalized. We capitalize a portion of interest related to unproved
properties. The decrease of interest expense in the first nine months of
2006 was primarily attributable to higher capitalized costs.
Our overall effective tax rate was 36.9% and 34.8% in the first nine
months of 2006 and 2005, respectively. The effective income tax rate for
the first nine months of 2006 was higher than the U.S. statutory rate
primarily due to state income taxes, an unfavorable rate impact for
32
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
non-deductible stock compensation, and was partially offset by
reductions from the New Zealand statutory rate attributable to the
currency effect on the New Zealand deferred tax calculation. For the first
nine months of 2005, the rate was lower due to a favorable correction in
the New Zealand basis of oil and gas properties.
Net Income. For the first nine months of 2006, our net income of $126.3
million was 56% higher, and Basic EPS of $4.33 was 52% higher, than our
first nine months of 2005 net income of $81.1 million and Basic EPS of
$2.86. Our Diluted EPS in the first nine months of 2006 of $4.20 was 52%
higher than our first nine months of 2005 Diluted EPS of $2.77. These
higher amounts are due to our increased oil and gas revenues, which in
turn were higher due to continued strong commodity prices and increased
production during the first nine months of 2006.
Share-Based Compensation
Effective January 1, 2006, the Company adopted SFAS No. 123R,
"Share-Based Payment" utilizing the modified prospective approach. Prior
to the adoption of SFAS No. 123R, we accounted for stock option grants in
accordance with APB No. 25, "Accounting for Stock Issued to Employees"
(the intrinsic value method), and accordingly, recognized no compensation
expense for employee stock option grants. The adoption of SFAS No. 123R
will increase our compensation expense related to employee stock option
grants over prior period levels.
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 in the nine
months ended September 30, 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
three months ended September 30, 2006, were $0.7 million, $0.6 million,
$0.02, and $0.02 lower, respectively, than if we had continued to account
for share-based compensation under APB Opinion No. 25 for our stock option
grants. For the nine months ended September 30, 2006, income before taxes,
net income and basic and diluted earnings per share were $2.7 million,
$2.2 million, $0.07, and $0.07 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 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 condensed consolidated statements
of operations.
We continue to 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.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -----------------------
2006 2005 2006 2005
------------------------- -----------------------
Dividend yield 0% 0% 0% 0%
Expected volatility 39.1% 41.2% 39.5% 42.5%
Risk-free interest rate 4.8% 3.9% 4.9% 3.8%
Expected life of options (in years) 2.6 3.9 5.6 3.5
Weighted-average grant-date fair value $ 12.20 $ 15.92 $ 19.31 $ 10.64
33
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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 analysis of all
relevant factors use a three-year period to estimate expected volatility
of our stock option grants. 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.
At September 30, 2006, there was $3.6 million of unrecognized
compensation cost related to stock options, which are expected to be
recognized over a weighted-average period of 1.6 years, and unrecognized
compensation expense of $15.0 million related to restricted stock awards
which are expected to be recognized over a weighted-average period of 2.4
years. The compensation expense for restricted stock awards was determined
based on the market price of our stock at the date of grant applied to the
total numbers of shares that were anticipated to fully vest.
Contractual Commitments and Obligations
We had no material changes in our contractual commitments and
obligations from December 31, 2005 amounts referenced under "Contractual
Commitments and Obligations" in Management's Discussion and Analysis" in
our Annual Report on form 10-K for the period ending December 31, 2005.
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
declined in September 2006 from levels earlier in the year; however, it is
currently significantly higher when compared to longer-term historical
prices. Factors such as worldwide supply disruptions, worldwide economic
conditions, weather conditions, actions taken by OPEC, and fluctuating
currency exchange rates can cause wide fluctuations in the price of oil.
Domestic natural gas prices continue to remain higher 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. Such factors are beyond our control.
Income Tax Regulations
As of September 30, 2006, we believe we have utilized all of our U.S.
federal operating loss carryforwards during the 2006 tax year.
The tax laws in the jurisdictions in which we operate continuously
change and professional judgments regarding such tax laws can differ. On
May 18, 2006 the State of Texas enacted a new tax bill that significantly
changes the state's franchise tax, effective January 1, 2007 for calendar
year taxpayers. The old franchise tax was computed on both "earned
surplus" (based on income and director and officer compensation) and
taxable capital. The new franchise tax is computed on "gross margin"
(generally based on revenue less costs of goods sold). The Company
accounts for the earned surplus portion of the old franchise tax as an
income tax. The Company will continue to account for the new franchise tax
as an income tax.
The Company has recomputed its Texas income tax expense by applying the
franchise tax rules to its current income tax expense and has recalculated
its cumulative deferred income tax following the new franchise tax rules.
This change did not result in a significant adjustment to the Company's
tax rate or its cumulative deferred tax liability.
34
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
Liquidity and Capital Resources
During the first nine months of 2006, we relied upon our net cash
provided by operating activities of $310.7 million and proceeds from the
sale of property and equipment of $20.3 million to fund capital
expenditures of $291.3 million. During the first nine months of 2005, we
relied upon our net cash provided by operating activities of $220.5
million to fund capital expenditures of $158.1 million and to pay down our
bank borrowings by $7.5 million.
Acquisitions
In October 2006, we acquired interests in five South Louisiana fields
from BP America Production Company. The total price for these interests
was approximately $169 million. The property interests are located
primarily 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. In addition, we have acquired
virtually all of the outstanding interest in the South Bearhead Creek
field, located in Beauregard Parish, Louisiana, for $4.5 million in
November 2006.
Net Cash Provided by Operating Activities. For the first nine months of
2006, our net cash provided by operating activities was $310.7 million,
representing a 41% increase as compared to $220.5 million generated during
the same 2005 period. The $90.2 million increase in the first nine months
of 2006 was primarily due to an increase of $151.9 million in oil and gas
sales, attributable to higher commodity prices and production, offset in
part by higher lease operating costs due to higher production and
insurance costs and higher severance taxes due to higher oil and gas
revenues.
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 September 30, 2006 and December
31, 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.
Receivables related to insurance reimbursement are computed in accordance
with applicable accounting guidance; and we monitor our costs incurred and
their collectibility under our insurance policies and believe all amounts
recorded are recoverable.
In October 2006, we settled all insurance claims with our insurers
relating to hurricanes Katrina and Rita and entered into a confidential
final settlement agreement. Based on an internal calculation, the property
damage related amount of the settlement was applied first to offset the
previously established insurance accounts receivable and then as a
reduction to the appropriate capital and expense categories. The receipt
of these amounts in the fourth quarter of 2006 is also expected to result
in a benefit of $7.7 million for the portion of the above referenced
settlement, which we have determined to be non-property damage related
claims, based on internal calculations.
Bank Credit Facility. We had no borrowings under our bank credit
facility at September 30, 2006 and December 31, 2005. Our bank credit
facility at September 30, 2006 consisted of a $400.0 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 October 2, 2006. On October 2, 2006, we
increased our revolving line of credit by $100.0 million, to $500.0
million, and extended the expiration date by roughly three years to
October 3, 2011. Also, on October 2, 2006, we requested that the
commitment amount with our bank be increased to $250 million from $150
million. 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, among other
restrictions that changed somewhat as the facility was renewed and
extended, 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.
35
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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 our operations, financial condition, prospects or
properties, and would impair our 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.
Debt Maturities. Our credit facility 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.
Working Capital. Our working capital improved from a surplus of $16.6
million at December 31, 2005, to a surplus of $94.8 million at September
30, 2006. The improvement primarily resulted from an increase in cash
balances, and an increase in our accounts receivable balances, partially
offset by an increase in accrued capital costs due to an increase in our
drilling and facility construction activities from year-end 2005 levels.
Capital Expenditures. In the first nine months of 2006, we relied upon
our net cash provided by operating activities of $310.7 million and
proceeds from the sale of property and equipment of $20.3 million to fund
capital expenditures of $291.3 million. Our total capital expenditures of
approximately $291.3 million in the first nine months of 2006 included:
Domestic expenditures of $244.0 million as follows:
o $189.4 million for drilling and developmental activity costs,
predominantly in our South Louisiana and AWP areas;
o $43.6 million of domestic prospect costs, principally related to
seismic activities, prospect leasehold, and geological costs of
unproved prospects;
o $11.0 million primarily for leasehold improvements in our Houston
office, software, computer equipment, vehicles, furniture, and
fixtures;
New Zealand expenditures of $47.3 million as follows:
o $39.1 million for drilling, developmental activity, and gas
processing plant costs;
o $7.8 million on prospect costs and geological costs of unproved
properties;
o and $0.4 million for computer equipment, software, furniture, and
fixtures.
We successfully completed 35 of 49 wells in the first nine months of
2006, for a success rate of 71%. Domestically, we completed 32 of 42 wells
for a success rate of 76%. A total of 17 wells were drilled in the Lake
Washington area, of which 15 were completed, and 17 wells were drilled in
the AWP Olmos area, of which 11 were completed. Six additional wells were
drilled successfully, three in Cote Blanche Island and one each in Bay de
Chene, South Bearhead Creek, and Brookeland. In Alaska, we drilled an
unsuccessful exploratory well. In New Zealand, we drilled four development
wells, three of which were completed, and drilled three unsuccessful
exploratory wells.
Our current 2006 capital expenditure budget for our drilling and
operations was increased to $391 to $415 million. We expect to spend an
additional $155 to $161 million on the South Louisiana acquisition and the
South Bearhead Creek acquisition of interests, net of approximately $20 to
$25 million in dispositions. The $20 to $25 million of dispositions relate
36
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
to non-core properties and is inclusive of the $20 million sale of our
minority interest in the Brookeland and Masters Creek natural gas
processing plants. Approximately 85% of the 2006 budget is targeted for
domestic activities, with about 15% planned for activities in New Zealand.
We plan to spend $250 to $270 million in our South Louisiana region, which
includes Lake Washington, Bay de Chene and Cote Blanche Island. We expect
that our 2006 capital expenditures to approximate our cash flows provided
from operating activities during 2006, as was the case in 2005. Our
acquisitions are not budgeted and are being funded through cash on hand,
cash flow and bank borrowings. For 2006, we have increased our production
growth target to 70 to 71 Bcfe, from the previous range of 68 to 70.5 Bcfe
and maintained our 5% to 8% targeted increase for proved reserves, over
the 2005 levels.
For the last three months of 2006, we expect to make capital
expenditures of approximately $282 to $314 million, which includes
property acquisitions of $174 to $179 million. These estimated 2006
amounts include an increase due to higher drilling and services costs over
prior year levels. Capital expenditures for 2005 totaled $236 million.
Our 2006 capital expenditures continue to be focused on developing and
producing long-lived reserves in South Louisiana, AWP Olmos, Rimu/Kauri,
and TAWN areas, along with property acquisitions in the South Louisiana
area. We expect our 2006 total production to increase over 2005 levels,
primarily from our South Louisiana area. Our production in the AWP Olmos
area is expected to remain relatively flat. We expect production in our
other core areas to decrease as a limited amount of new drilling is
currently budgeted to offset the natural production decline of these
properties.
In New Zealand, we signed a natural gas supply agreement in July 2006
that covers production from our Rimu and Kauri wells until December 31,
2009. The benefits of the new agreement are to increase our sales price
from the current price, termination of our existing sales agreements which
called for lower sales prices on our natural gas production, and the
ability to separately market production from new Rimu/Kauri wells with our
purchaser retaining a right of first negotiation.
New Accounting Pronouncements
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3.
SFAS No. 154 requires voluntary changes in accounting principles to be
applied retrospectively, unless it is impracticable. SFAS No. 154's
retrospective application requirement replaces APB 20's requirement to
recognize most voluntary changes in accounting principle by including in
net income of the period of the change the cumulative effect of changing
to the new accounting principle. If retrospective application for all
prior periods is impracticable, the method used to report the change and
the reason the retrospective application is impracticable are to be
disclosed.
Under SFAS No. 154, retrospective application will be the transition
method in the unusual instance that a newly issued accounting
pronouncement does not provide specific transition guidance. It is
expected that many pronouncements will specify transition methods other
than retrospective. SFAS No. 154 is effective for accounting changes made
in fiscal years beginning after December 15, 2005, and 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 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 Company has not yet determined
what, if any, impact this interpretation will have on its financial
position or results of operations.
37
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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 Interpretation will have on its financial position or
results of operations.
38
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY AND SUBSIDIARIES
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 and 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
the uncertainty of finding, replacing, developing or acquiring reserves;
fluctuations in crude oil, natural gas and natural gas liquids prices or
demand; adequate availability of skilled personnel, services and supplies;
the uncertainty of drilling results; potential failure or delays in
achieving reserve or production levels from existing and future oil and
gas development projects due to operating hazards, drilling risks and the
inherent uncertainties in predicting oil and gas reserves and oil and gas
reservoir performance; 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 herein, and set forth from time to time
in our other public reports, filings and public statements. Also, because
of the volatility in oil and gas prices and other factors, interim results
are not necessarily indicative of those for a full year.
39
Item 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
Our major market risk exposure is the volatile 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 derivative
instruments (such as futures, forward contracts, swaps, and option
contracts such as floors and collars) to mitigate price risk associated
with fluctuations in oil and natural gas prices. Below is a description of
the derivative instruments we have utilized to hedge our exposure to price
risk.
oPrice Floors - At September 30, 2006, we had in place price floors in
effect through the December 2006 contract month for oil, which are
expected to cover approximately 45% to 50% of our domestic oil
production for October 2006 through December 2006. The oil floors cover
notional volumes of 900,000 barrels, and expire at various dates from
October 2006 to December 2006, with a weighted average floor price of
$63.77 per barrel.
oNew Zealand Gas Contracts - All of our current 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.
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 that the loss of any single oil or
gas customer would have a material adverse effect on our financial
position or results of operations.
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, natural
gas and NGL sales contracts, and New Zealand income tax obligations, all
denominated in New Zealand dollars.
Interest Rate Risk
Our Senior Notes due 2011 and Senior Subordinated Notes due 2012 have
fixed interest rates; consequently we are not exposed to cash flow risk
from market interest rate changes on these notes. However, there is a risk
that market rates will decline and the required interest payments on our
Senior Notes and Senior Subordinated Notes may exceed those payments based
on the current market rate. At September 30, 2006, we had no borrowings
under our credit facility, which is subject to floating rates and
therefore 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 2006 cash flows based on
this same level or a modest level of borrowing.
40
Item 4.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that
information required to be disclosed in our filings under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commission rules and
forms. Our chief executive officer and chief financial officer have evaluated
our disclosure controls and procedures as of the end of the period covered by
this report and have concluded that such disclosure controls and procedures are
effective in ensuring that material information required to be disclosed in this
report is accumulated and communicated to them and our management to allow
timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting
during the first nine months of 2006 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
41
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings.
No material legal proceedings are pending other than ordinary, routine
litigation incidental to the Company's business.
Item 1A. Risk Factors.
There have been no material changes in our risk factors from those disclosed in
our 2005 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits.
10.1* Third Amendment to First Amended and Restated
Credit Agreement, effective as of October 2,
2006.
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.
* Filed herewith
42
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SWIFT ENERGY COMPANY
(Registrant)
Date: November 3, 2006 By: (original signed by)
------------------------ ----------------------------------
Alton D. Heckaman, Jr.
Executive Vice President &
Chief Financial Officer
Date: November 3, 2006 By: (original signed by)
----------------------- ----------------------------------
David W. Wesson
Controller &
Principal Accounting Officer
43
Exhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended
September 30, 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: November 3, 2006
/s/ Terry E. Swift
----------------------------------------
Terry E. Swift
Chairman of the Board &
Chief Executive Officer
44
Exhibit 31.2
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended
September 30, 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: November 3, 2006
/s/ Alton D. Heckaman Jr.
----------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President &
Chief Financial Officer
45
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 Quarterly Report on Form 10-Q for the
period ended September 30, 2006 (the "Report") of Swift Energy Company ("Swift")
as filed with the Securities and Exchange Commission on November 3, 2006, 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: November 3, 2006
/s/ Alton D. Heckaman, Jr.
----------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President &
Chief Financial Officer
Dated: November 3, 2006
/s/ Terry E. Swift
----------------------------------------
Terry E. Swift
Chairman of the Board &
Chief Executive Officer
46
THIRD AMENDMENT TO FIRST AMENDED AND RESTATED
CREDIT AGREEMENT
AMONG
SWIFT ENERGY COMPANY
SWIFT ENERGY OPERATING, LLC
AS BORROWER
JPMORGAN CHASE BANK, N.A.
AS ADMINISTRATIVE AGENT
WELLS FARGO BANK (TEXAS), NATIONAL ASSOCIATION
AS SYNDICATION AGENT
BNP PARIBAS
AS SYNDICATION AGENT
CALYON NEW YORK BRANCH
AS DOCUMENTATION AGENT
SOCIETE GENERALE
AS DOCUMENTATION AGENT
AND
THE LENDERS SIGNATORY HERETO
AND
J.P. MORGAN SECURITIES, INC.
AS SOLE LEAD ARRANGER AND SOLE BOOK RUNNER
Effective as of October 2, 2006
----------------------------------
Revolving Line of Credit of up to $500,000,000
with Letter of Credit Subfacility
-----------------------------------
TABLE OF CONTENTS
PAGE
ARTICLE I DEFINITIONS.........................................1
1.01 Terms Defined Above.................................1
1.02 Terms Defined in Agreement..........................1
1.03 References..........................................1
1.04 Articles and Sections...............................2
1.05 Number and Gender...................................2
ARTICLE II AMENDMENTS.................................................2
2.01 Amendment of Section 1.2............................2
2.02 Amendment of Section 2.11(a)........................3
2.03 Amendment of Section 2.12...........................3
2.04 Amendment of Section 2.14...........................3
2.05 Amendment of Section 6.1............................4
2.06 Amendment of Section 6.2............................4
2.07 Amendment of Section 6.4............................4
2.08 Amendment of Section 6.5............................4
2.09 Amendment of Section 6.8(h).........................4
2.10 Amendment of Exhibit I..............................4
2.11 Amendment of Exhibit V..............................5
2.12 Amendment of Exhibit VIII...........................5
2.13 Amendment of Exhibit X..............................5
ARTICLE III CONDITIONS................................................5
3.01 Receipt of Documents................................5
3.02 Accuracy of Representations and Warranties..........6
3.03 Matters Satisfactory to Lenders.....................6
ARTICLE IV REPRESENTATIONS AND WARRANTIES.............................6
ARTICLE V RATIFICATION................................................6
ARTICLE VI MISCELLANEOUS..............................................6
6.01 Scope of Amendment..................................6
6.02 Agreement as Amended................................6
6.03 Parties in Interest.................................6
6.04 Rights of Third Parties.............................6
6.05 ENTIRE AGREEMENT....................................6
6.06 JURISDICTION AND VENUE..............................7
i
Exhibit I -........Form of Promissory Note
Exhibit V -........Facility Amounts
Exhibit VIII -........Subsidiaries and Partnerships
Exhibit X -........Pricing Schedule
ii
THIRD AMENDMENT TO FIRST AMENDED AND
RESTATED CREDIT AGREEMENT
This THIRD AMENDMENT TO FIRST AMENDED AND RESTATED CREDIT AGREEMENT (this
"Third Amendment") is made and entered into effective as of October 2, 2006, by
and among SWIFT ENERGY COMPANY, a Texas corporation, and SWIFT ENERGY OPERATING,
LLC, a Texas limited liability company, (collectively the "Borrower"), each
lender that is a signatory hereto or becomes a signatory hereto as provided in
Section 9.1 of the Credit Agreement (individually, together with its successors
and assigns, a "Lender" and, collectively, together with their respective
successors and assigns, the "Lenders"), and JPMORGAN CHASE BANK, N.A.,
(successor by merger to Bank One, NA (Main Office Chicago)), a national banking
association, as Administrative Agent for the Lenders (in such capacity, together
with its successors in such capacity pursuant to the terms hereof, the
"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 NEW YORK BRANCH as Documentation Agent
and SOCIETE GENERALE as Documentation Agent.
W I T N E S S E T H
WHEREAS, SWIFT ENERGY COMPANY, a Texas corporation prior to merging ("Old
Swift") into Swift Energy Operating, LLC ("Operating"), was the Borrower in the
First Amended and Restated Credit Agreement dated June 29, 2004, as amended by
First Amendment to First Amended and Restated Credit Agreement dated October 21,
2005, and as further amended by Second Amendment to First Amended and Restated
Credit Agreement dated December 28, 2005 (the "Agreement") to reflect that
Operating and the newly formed parent holding company, Swift Energy Company, a
Texas corporation ("Swift") were the parties to the credit agreement, to which
reference is made for all purposes;
NOW, THEREFORE, in consideration of the mutual covenants and agreements of
the parties to the Agreement, as set forth therein, and the mutual covenants and
agreements of the parties hereto, as set forth in this Third Amendment, the
parties hereto agree as follows:
ARTICLE I
DEFINITIONS
1.01.....Terms Defined Above. As used herein, each of the terms "Administrative
Agent," "Agreement," "Borrower," "Lender" "Lenders" and "Third Amendment" shall
have the meaning assigned to such term hereinabove.
1.02.....Terms Defined in Agreement. As used herein, each term defined in the
Agreement shall have the meaning assigned thereto in the Agreement, unless
expressly provided herein to the contrary.
1.03.....References. References in this Third Amendment to Article or Section
numbers shall be to Articles and Sections of this Third Amendment, unless
expressly stated herein to the contrary. References in this Third Amendment to
"hereby," "herein," hereinafter," hereinabove," "hereinbelow," "hereof," and
"hereunder" shall be to this Third Amendment in its entirety and not only to the
particular Article or Section in which such reference appears.
1
1.04.....Articles and Sections. This Third Amendment, for convenience only, has
been divided into Articles and Sections and it is understood that the rights,
powers, privileges, duties, and other legal relations of the parties hereto
shall be determined from this Third Amendment as an entirety and without regard
to such division into Articles and Sections and without regard to headings
prefixed to such Articles and Sections.
1.05.....Number and Gender. Whenever the context requires, reference herein made
to the single number shall be understood to include the plural and likewise the
plural shall be understood to include the singular. Words denoting sex shall be
construed to include the masculine, feminine, and neuter, when such construction
is appropriate, and specific enumeration shall not exclude the general, but
shall be construed as cumulative. Definitions of terms defined in the singular
and plural shall be equally applicable to the plural or singular, as the case
may be.
ARTICLE II
AMENDMENTS
The Borrower, Administrative Agent and the Lenders hereby amend the
Agreement in the following particulars:
2.01.....Amendment of Section 1.2. Section 1.2 of the Agreement is hereby
amended as follows:
The following definitions are amended or deleted as follows:
"Base Rate" shall be deleted and replaced by "Prime Rate".
"Controlled Foreign Subsidiaries" shall mean Swift Energy
New Zealand Limited, Swift Energy Canada, Ltd. and
Southern Petroleum (New Zealand) Exploration Limited.
"Final Maturity" shall mean October 3, 2011.
"Future Net Investments in New Zealand" shall mean Investments
by the Borrower, on a non-consolidated basis, beginning in the
year 2002, in its Subsidiaries in New Zealand for the purpose
of production of oil, gas and other hydrocarbons in New
Zealand which shall take into consideration the amount of
dollars invested and the amount of dollars returned to the
Borrower from such Subsidiaries to arrive at the sum which
will be the net investment for the Borrower in New Zealand.
"Prime Rate" shall mean the rate of interest per annum
announced from time to time by the Administrative Agent as its
Prime Rate. The Prime Rate is a variable rate and each change
in the Prime Rate is effective from and including the date the
change is announced as being effective. THE PRIME RATE IS A
REFERENCE RATE AND MAY NOT BE THE ADMINISTRATIVE AGENT'S
LOWEST RATE.
2
2.02 Amendment of Section 2.11(a). Section 2.11(a) of the Agreement is
amended to read as follows:
"2.11 Borrowing Base Determinations (a) The Borrowing Base as
of October 2, 2006, is acknowledged by the Borrower and the Lenders to
be $250,000,000."
2.03 Amendment of Section 2.12. The second paragraph of Section 2.12 of
the Agreement shall be amended to read as follows:
"2.12 Mandatory Prepayments. ....
"If at any time and from time to time, there are no
outstanding amounts due and owing under this Agreement, Borrower shall
be entitled to sell Oil and Gas Properties which are part of the
Borrowing Base and retain the sales proceeds therefrom without the
consent of the Lenders, but subject to a reduction in the then existing
Borrowing Base by the amount of the Release Price (as hereinafter
defined) for such properties. Upon the sale of any Oil and Gas
Properties which are part of the Borrowing Base in excess of 10% of the
Borrowing Base amount during any fiscal year while there are amounts
due and owing under this Agreement (no such sale will be permitted
without the prior written consent of the Required Lenders), the
Borrower will immediately make a prepayment of principal on the loans
equal to, and the Borrowing Base will be automatically reduced by, an
amount equal to 100% of the Release Price of the sold properties. The
term "Release Price" means the price determined by the Required Lenders
in their discretion based upon the loan value of the Oil and Gas
Properties being sold by the Borrower that the Required Lenders in
their discretion (using such methodology, assumptions and discount
rates as such Lender's customarily use in assigning loan value to Oil
and Gas Properties) assign to such oil and gas properties as of the
time in question."
2.04 Amendment of Section 2.14. Section 2.14 of the Agreement is hereby
amended to read as follows:
"2.14 Commitment Amount. The Commitment Amount as of October
2, 2006, is $250,000,000. The Commitment Amount may be reduced by the
Borrower, in multiples of $10,000,000, upon three Business Days' prior
written notice to the Administrative Agent but not more than two times
in any fiscal year. At any time after the Closing Date, and so long as
no Default or Event of Default has occurred and is continuing, Borrower
shall have the right (without the consent of any Lender(s)) to increase
the Commitment Amount to an aggregate amount of up to the then current
Borrowing Base, provided that (i) each Lender shall be offered a pro
rata share of any increase, (ii) no Lender's commitment shall be
increased without its consent, and (iii) if needed, other eligible
institutions may become Lenders to accommodate an increase."
3
2.05 Amendment of Section 6.1. Section 6.1 of the Agreement is hereby
amended to read as follows by adding (l):
"6.1 Indebtedness; Contingent Obligations. ....,
and (l) amounts applicable to Controlled Foreign
Subsidiaries."
2.06 Amendment of Section 6.2. Section 6.2 of the Agreement is hereby
amended to change (g) and add (h) as follows:
"6.2 Loans or Advances. .... (g) loans or advances to wholly
owned Subsidiaries, not including Controlled Foreign Subsidiaries, for
Oil and Gas related investments in an amount not to exceed $5,000,000
in the aggregate unless such Subsidiary has provided a guaranty
hereunder, or (h) loans or advances to Controlled Foreign Subsidiaries
to the extent otherwise permitted under Section 6.8(h)."
2.07 Amendment of Section 6.4. Section 6.4 of the Agreement is hereby
amended to change $25,000,000 to $50,000,000. The remainder of Section 6.4
shall not be changed.
2.08 Amendment of Section 6.5. Section 6.5 of the Agreement is hereby
amended to read as follows:
"6.5 Dividends and Distributions. Declare, pay or make,
whether in cash or other Property, any dividend or distribution on any
share of any class of its capital stock other than cash dividends not
exceeding $15,000,000 in any fiscal year, provided that both before and
after giving effect to any such distribution there shall exist no
Default or Event of Default, and dividends paid in capital stock of the
Borrower; or purchase, redeem or otherwise acquire, directly or
indirectly, for value or set apart in any way for redemption,
retirement or other acquisition, directly or indirectly, any of its
stock now or hereafter outstanding; return any capital to its
stockholders; or make any distribution (whether by reduction of capital
or otherwise) of its assets to its stockholders. Provided, however, the
Borrower may acquire of its common stock after the Closing Date having
a fair market value at the time of Acquisition not to exceed in the
aggregate $50,000,000."
2.09 Amendment of Section 6.8(h). Section 6.8(h) of the Agreement is hereby
amended to read as follows:
"6.8 Investments. .... and (h) Future Net Investments
in New Zealand which may not exceed 10% of the Borrowing
Base amount per year."
2.10 Amendment of Exhibit I. Exhibit I, i.e. the "Form of Promissory
Note" shall be as set forth on Exhibit I to this Third Amendment to First
Amended and Restated Credit Agreement.
4
2.11 Amendment of Exhibit V. Exhibit V, i.e., "Facility Amounts" shall be as set
forth on Exhibit V of this Third Amendment to First Amended and Restated Credit
Agreement.
2.12 Amendment of Exhibit VIII. Exhibit VIII, i.e. "Subsidiaries and
Partnerships" shall be as set forth on Exhibit VIII to this Third Amendment to
First Amended and Restated Credit Agreement.
2.13 Amendment of Exhibit X. Exhibit X, i.e., "Pricing Schedule" shall be as set
forth on Exhibit X to this Third Amendment to First Amended and Restated Credit
Agreement.
ARTICLE III
CONDITIONS
The obligation of the Lenders to amend the Agreement as provided herein
is subject to the fulfillment of the following conditions precedent:
3.01 Receipt of Documents. The Lenders shall have received, reviewed, and
approved the following documents and other items, appropriately executed when
necessary and in form and substance satisfactory to the Lenders:
(a) multiple counterparts of this Third Amendment, as requested by the
Lender;
(b) the Notes;
(c) Ratification of and Amendment to Act of Mortgage and Security
Agreement;
(d) Ratification of and Amendment to Mortgage, Deed of Trust, Security
Agreement, Financing Statement, Fixture Filing and Assignment of
Production;
(e) a certificate of incumbency, including specimen signatures of all
officers or other representatives of the Borrower who are authorized to
execute Loan Documents on behalf of the Borrower, such certificate
being executed by the secretary or an assistant secretary or another
authorized representative of the Borrower;
(f) copies of resolutions of the Borrower, adopted by the board of
directors of the Borrower approving the Loan Documents to which the
Borrower is a party and authorizing the transactions contemplated
herein and therein, accompanied by a certificate dated the Closing Date
issued by the secretary or assistant secretary or another authorized
representative of the Borrower to the effect that such copies are true
and correct copies of resolutions duly adopted and that such
resolutions constitute all the resolutions adopted with respect to such
transactions, have not been amended, modified, or rescinded in any
respect, and are in full force and effect as of the date of such
certificate; and
(g) such other agreements, documents, items, instruments, opinions,
certificates, waivers, consents, and evidence as the Administrative
Agent may reasonably request.
5
3.02 Accuracy of Representations and Warranties. The representations and
warranties contained in Article IV of the Agreement and this Third Amendment
shall be true and correct.
3.03 Matters Satisfactory to Lenders. All matters incident to the
consummation of the transactions contemplated hereby shall be satisfactory to
the Administrative Agent and the Lenders.
ARTICLE IV
REPRESENTATIONS AND WARRANTIES
The Borrower hereby expressly re-makes, in favor of the Lenders, all of
the representations and warranties set forth in Article IV of the Agreement, and
represents and warrants that all such representations and warranties remain true
and unbreached.
ARTICLE V
RATIFICATION
Each of the parties hereto does hereby adopt, ratify, and confirm the
Agreement and the other Loan Documents, in all things in accordance with the
terms and provisions thereof, as amended by this Third Amendment.
ARTICLE VI
MISCELLANEOUS
6.01 Scope of Amendment. The scope of this Third Amendment is expressly limited
to the matters addressed herein and this Third Amendment shall not operate as a
waiver of any past, present, or future breach, Default, or Event of Default
under the Agreement except to the extent, if any, that any such breach, Default,
or Event of Default is remedied by the effect of this Third Amendment.
6.02 Agreement as Amended. All references to the Agreement in any document
heretofore or hereafter executed in connection with the transactions
contemplated in the Agreement shall be deemed to refer to the Agreement as
amended by this Third Amendment.
6.03 Parties in Interest. All provisions of this Third Amendment shall be
binding upon and shall inure to the benefit of the Borrower, the Administrative
Agent and the Lenders and their respective successors and assigns.
6.04 Rights of Third Parties. All provisions herein are imposed solely and
exclusively for the benefit of the Administrative Agent, the Lenders and the
Borrower, and no other Person shall have standing to require satisfaction of
such provisions in accordance with their terms and any or all of such provisions
may be freely waived in whole or in part by the Lenders at any time if in their
sole discretion it deems it advisable to do so.
6.05 ENTIRE AGREEMENT. THIS THIRD AMENDMENT CONSTITUTES THE ENTIRE AGREEMENT
BETWEEN THE PARTIES HERETO WITH RESPECT TO THE SUBJECT HEREOF AND SUPERSEDES ANY
PRIOR AGREEMENT, WHETHER WRITTEN OR ORAL, BETWEEN SUCH PARTIES REGARDING THE
SUBJECT HEREOF. FURTHERMORE IN THIS REGARD, THIS THIRD AMENDMENT, THE AGREEMENT,
THE NOTE, THE SECURITY INSTRUMENTS, AND THE OTHER WRITTEN DOCUMENTS REFERRED TO
IN THE AGREEMENT OR EXECUTED IN CONNECTION WITH OR AS SECURITY FOR THE NOTES
REPRESENT, COLLECTIVELY, THE FINAL AGREEMENT AMONG THE PARTIES THERETO AND MAY
NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE
PARTIES.
6
6.06 JURISDICTION AND VENUE. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING
DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS
THIRD AMENDMENT, THE AGREEMENT OR ANY OTHER LOAN DOCUMENT MAY BE LITIGATED IN
COURTS HAVING SITUS IN HARRIS COUNTY, TEXAS. EACH OF THE BORROWER, THE
ADMINISTRATIVE AGENT AND THE LENDERS HEREBY SUBMITS TO THE JURISDICTION OF ANY
LOCAL, STATE, OR FEDERAL COURT LOCATED IN HARRIS COUNTY, TEXAS, AND HEREBY
WAIVES ANY RIGHTS IT MAY HAVE TO TRANSFER OR CHANGE THE JURISDICTION OR VENUE OF
ANY LITIGATION BROUGHT AGAINST IT BY THE BORROWER, THE ADMINISTRATIVE AGENT OR
THE LENDERS IN ACCORDANCE WITH THIS SECTION.
7
IN WITNESS WHEREOF, this Agreement is executed effective as of the date
first above written.
BORROWER:
SWIFT ENERGY COMPANY
By:-------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:-------------------------------------
Adrian D. Shelley
Treasurer
SWIFT ENERGY OPERATING, LLC
By:-------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:-------------------------------------
Adrian D. Shelley
Treasurer
Address for Notices:
Swift Energy Company
Swift Energy Operating, LLC
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attention: Alton D. Heckaman, Jr.
Telecopy: (281) 874-2701
(Signatures Continued on Next Page)
8
ADMINISTRATIVE AGENT AND LENDER:
JPMORGAN CHASE BANK, N.A., (successor by
merger to Bank One, NA (Main Office Chicago)
By:-------------------------------------
Charles Kingswell-Smith
Managing Director
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
10 South Dearborn, Floor 19
Chicago, Illinois 60603
Address for Notices:
600 Travis, 20th Floor
Houston, Texas 77002
Attention: Charles Kingswell-Smith
Telecopy: (713) 216-7770
(Signatures Continued on Next Page)
9
LENDER
BANK OF SCOTLAND
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
565 Fifth Avenue
New York, New York 10017
Attention: Shirley Vargas
Telecopy: 212-479-2807
Address for Notices:
1021 Main Street, Suite 1370
Houston, Texas 77002
Attention: Richard Butler
Telecopy: 713-651-9714
10
(Signatures Continued on Next Page)
LENDER:
NATEXIS BANQUES POPULAIRES
By:
--------------------------------------
Printed Name:
----------------------------
Title:
-----------------------------------
By:
--------------------------------------
Printed Name:
----------------------------
Title:
-----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
333 Clay Street, Suite 4340
Houston, Texas 77002
Attention: Donovan Broussard
Address for Notices:
..........
..........
..........
Attention:.........
Telecopy:..........
(Signatures Continued on Next Page)
11
LENDER:
COMPASS BANK
By:
--------------------------------------
Printed Name:
----------------------------
Title:
-----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
-------------------------------
Address for Notices:
-------------------------------
(Signatures Continued on Next Page)
12
DOCUMENTATION AGENT AND LENDER:
SOCIETE GENERALE
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
560 Lexington Avenue
New York, New York 10022
Attention: Arlene Tellerman
Telephone: 212-278-6086
Telecopy: 212-278-7490
Address for Notices:
1111 Bagby, Suite 2020
Houston, TX 77002
Attention: Mr. Jason Henderson
Ms. Elena Robciuc
Telecopy: 713-650-0824
(Signatures Continued on Next Page)
13
DOCUMENTATION AGENT AND LENDER:
CALYON NEW YORK BRANCH
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
1301 Avenue of the Americas, 15th Floor
New York, New York 10019
Attn: Loan Administration Department
with a copy to:
1301 Travis, Suite 2100
Houston, Texas 77002
Attention: Tom Byargeon
Address for Notices:
1301 Avenue of the Americas, 15th Floor
New York, New York 10019
Attn: Loan Administration Department
with a copy to:
1301 Travis, Suite 2100
Houston, TX 77002
Attention: Tom Byargeon
Telecopy: 713-751-0307
(Signatures Continued on Next Page)
14
SYNDICATION AGENT AND LENDER:
WELLS FARGO BANK, NATIONAL
ASSOCIATION
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
1740 Broadway, 3rd Floor
Denver, CO 80274
Attention: Tanya Ivie
Address for Notices:
1000 Louisiana St., 3rd Floor
Houston, TX 77002
Attention: Chris Carter
(Signatures Continued on Next Page)
15
SYNDICATION AGENT AND LENDER:
BNP PARIBAS
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Loans:
..........
..........
..........
Attention:.........
Address for Notices:
.........
.........
.........
Attention:.........
Telecopy: .........
(Signatures Continued on Next Page)
16
LENDER:
COMERICA BANK
By:
-------------------------------------
Printed Name:
---------------------------
Title:
----------------------------------
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
39200 Six Mile Road
Livonia, Michigan 48152
Attention: Jeffrey Zelenka
Telecopy: 734-632-2993
Address for Notices:
910 Louisiana, Suite 410
Houston, Texas 77002
Attention: Huma Vadgama
Telecopy: 713-220-5651
(Signatures Continued on Next Page)
17
LENDER:
AMEGY BANK NATIONAL ASSOCIATION
By:
-------------------------------------
Kenneth R. Batson, III
Vice President, Energy Lending
Applicable Lending Office
for Alternative Base Rate Loans and
Eurodollar Rate Loans:
AMEGY BANK NATIONAL ASSOCIATION
Attention: Dana Chargois
Address for Notices:
P.O. Box 27459
Houston, Texas 77227
Attention: Dana Chargois Telecopy:
713-693-7467
18
EXHIBIT I
PROMISSORY NOTE
$66,616,161.82 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of JPMORGAN CHASE BANK, N.A. ("Payee"), at the banking
quarters of JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum
of SIXTY-SIX MILLION SIX HUNDRED SIXTEEN THOUSAND ONE HUNDRED SIXTY-ONE AND
82/100 ($66,616,161.82), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-i
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-ii
EXHIBIT I
PROMISSORY NOTE
$66,616,161.82 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of CALYON NEW YORK BRANCH ("Payee"), at the banking quarters
of JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum of
SIXTY-SIX MILLION SIX HUNDRED SIXTEEN THOUSAND ONE HUNDRED SIXTY-ONE AND 82/100
($66,616,161.82), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-i
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-ii
EXHIBIT I
PROMISSORY NOTE
$66,616,161.82 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of SOCIETE GENERALE ("Payee"), at the banking quarters of
JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum of
SIXTY-SIX MILLION SIX HUNDRED SIXTEEN THOUSAND ONE HUNDRED SIXTY-ONE AND 82/100
($66,616,161.82), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-iii
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-iv
EXHIBIT I
PROMISSORY NOTE
$63,636,363.62 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of WELLS FARGO BANK, NATIONAL ASSOCIATION ("Payee"), at the
banking quarters of JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas,
the sum of SIXTY-THREE MILLION SIX HUNDRED THIRTY-SIX THOUSAND, THREE HUNDRED
SIXTY-THREE AND 62/100 ($63,636,363.62), or so much thereof as may be advanced
against this Note pursuant to the First Amended and Restated Credit Agreement
dated as of June 29, 2004, by and among Maker, Bank One, NA, as a Lender and as
the Administrative Agent, Wells Fargo Bank, National Association, as a Lender
and as Syndication Agent, CALYON, as a Lender and as Documentation Agent and
Societe Generale as a Lender and Documentation Agent, and the other Lenders
signatory thereto (as amended, restated or supplemented from time to time, the
"Credit Agreement"), together with interest at the rates and calculated as
provided in the Credit Agreement. The indebtedness evidenced by this Note, both
principal and interest, is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-v
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-vi
EXHIBIT I
PROMISSORY NOTE
$60,000,000.00 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of BANK OF SCOTLAND ("Payee"), at the banking quarters of
JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum of SIXTY
MILLION AND 00/100 ($60,000,000.00), or so much thereof as may be advanced
against this Note pursuant to the First Amended and Restated Credit Agreement
dated as of June 29, 2004, by and among Maker, Bank One, NA, as a Lender and as
the Administrative Agent, Wells Fargo Bank, National Association, as a Lender
and as Syndication Agent, CALYON, as a Lender and as Documentation Agent and
Societe Generale as a Lender and Documentation Agent, and the other Lenders
signatory thereto (as amended, restated or supplemented from time to time, the
"Credit Agreement"), together with interest at the rates and calculated as
provided in the Credit Agreement. The indebtedness evidenced by this Note, both
principal and interest, is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-vii
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-viii
EXHIBIT I
PROMISSORY NOTE
$29,166,666.36 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of NATEXIS BANQUES POPULAIRES ("Payee"), at the banking
quarters of JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum
of TWENTY-NINE MILLION ONE HUNDRED SIXTY-SIX THOUSAND SIX HUNDRED SIXTY-SIX AND
36/100 ($29,166,666.36), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-ix
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-x
EXHIBIT I
PROMISSORY NOTE
$29,166,666.36 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of COMPASS BANK ("Payee"), at the banking quarters of
JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum of
TWENTY-NINE MILLION ONE HUNDRED SIXTY-SIX THOUSAND SIX HUNDRED SIXTY-SIX AND
36/100 ($29,166,666.36), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-xi
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-xii
EXHIBIT I
PROMISSORY NOTE
$54,545,454.52 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of BNP PARIBAS ("Payee"), at the banking quarters of
JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum of
FIFTY-FOUR MILLION FIVE HUNDRED FORTY-FIVE THOUSAND FOUR HUNDRED FIFTY-FOUR AND
52/100 ($54,545,454.52), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-xiii
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-xiv
EXHIBIT I
PROMISSORY NOTE
$31,818,181.82 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of COMERICA BANK ("Payee"), at the banking quarters of
JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum of
THIRTY-ONE MILLION EIGHT HUNDRED EIGHTEEN THOUSAND ONE HUNDRED EIGHTY-ONE AND
82/100 ($31,818,181.82), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-xv
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-xvi
EXHIBIT I
PROMISSORY NOTE
$31,818,181.82 Houston, Texas October 2, 2006
FOR VALUE RECEIVED and WITHOUT GRACE, the undersigned ("Maker") promises
to pay to the order of AMEGY BANK NATIONAL ASSOCIATION ("Payee"), at the banking
quarters of JPMorgan Chase Bank, N.A., in Houston, Harris County, Texas, the sum
of THIRTY-ONE MILLION EIGHT HUNDRED EIGHTEEN THOUSAND ONE HUNDRED EIGHTY-ONE AND
82/100 ($31,818,181.82), or so much thereof as may be advanced against this Note
pursuant to the First Amended and Restated Credit Agreement dated as of June 29,
2004, by and among Maker, Bank One, NA, as a Lender and as the Administrative
Agent, Wells Fargo Bank, National Association, as a Lender and as Syndication
Agent, CALYON, as a Lender and as Documentation Agent and Societe Generale as a
Lender and Documentation Agent, and the other Lenders signatory thereto (as
amended, restated or supplemented from time to time, the "Credit Agreement"),
together with interest at the rates and calculated as provided in the Credit
Agreement. The indebtedness evidenced by this Note, both principal and interest,
is payable as provided in the Credit Agreement.
Reference is hereby made to the Credit Agreement for matters governed
thereby, including, without limitation, certain events which will entitle the
Lenders to accelerate the maturity of all amounts due hereon. Capitalized terms
used but not defined in this Note shall have the meanings assigned to such terms
in the Credit Agreement.
This Note is issued pursuant to, is a "Note" under, and is payable as
provided in, the Credit Agreement and is a substitution for and supersedes the
Note dated December 28, 2005 and all other prior Notes under this Agreement.
This Note shall be governed and controlled by the laws of the State of
Texas (without giving effect to the principles thereof relating to conflicts of
law); provided, however, that CHAPTER 345 OF THE TEXAS FINANCE CODE (which
regulates certain revolving credit loan accounts and revolving triparty
accounts) shall not apply to this Note.
SWIFT ENERGY COMPANY
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page One of Two Page Note]
I-xvii
SWIFT ENERGY OPERATING, LLC
By:
Alton D. Heckaman, Jr.
Executive Vice President and
Chief Financial Officer
By:
Adrian D. Shelley
Treasurer
[Page Two of Two Page Note]
I-xviii
EXHIBIT V
FACILITY AMOUNTS
Facility Borrowing Commitment
Name of Lender Amount Base Amount Facility %
JPMorgan Chase Bank, NA $66,616,161.82 $33,308,080.91 $33,308,080.91 13.32%
CALYON $66,616,161.82 $33,308,080.91 $33,308,080.91 13.32%
Societe Generale $66,616,161.82 $33,308,080.91 $33,308,080.91 13.32%
Wells Fargo Bank, National $63,636,363.62 $31,818,181.81 $31,818,181.81 12.73%
Association
Bank of Scotland $60,000,000.00 $30,000,000.00 $30,000,000.00 12.00%
BNP Paribas $54,545,454.52 $27,272,727.26 $27,272,727.26 10.91%
Amegy Bank National $31,818,181.82 $15,909,090.91 $15,909,090.91 6.36%
Association
Comerica Bank $31,818,181.82 $15,909,090.91 $15,909,090.91 6.36%
Compass Bank $29,166,666.36 $14,583,333.18 $14,583,333.18 5.83%
Natexis Banques Populaires $29,166,666.36 $14,583,333.18 $14,583,333.18 5.83%
------------------- ------------------- ------------------
Facility Totals $500,000,000.00 $250,000,000 $250,000,000
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EXHIBIT VIII
SUBSIDIARIES AND PARTNERSHIPS
Percentage Ownership of
Outstanding Common Stock,
Membership Interest or Place of Incorporation
Partnership Interest or Jurisdiction of Address of Principal
Name (Distributive Share) Formation of Partnership Place of Business
Subsidiaries:
GASRS, Inc. 100.00% TX 16825 Northchase Drive, Suite 400
Houston, Texas 77060
SWENCO-Western, Inc. 100.00% TX 16825 Northchase Drive, Suite 400
Houston, Texas 77060
Swift Energy Marketing Company 100.00% TX 16825 Northchase Drive, Suite 400
Houston, Texas 77060
Swift Energy Exploration Services, 100.00% TX 16825 Northchase Drive, Suite 400
Inc. Houston, Texas 77060
Swift Energy International, Inc. 100.00% DE 16825 Northchase Drive, Suite 400
Houston, Texas 77060
Swift Energy Canada, Ltd. 100.00% Canada 16825 Northchase Drive, Suite 400
Houston, Texas 77060
Swift Energy Group, Inc. 100.00% DE 103 Foulk Road, Suite 202
Wilmington, Delaware 19803
Swift Energy New Zealand Limited 100.00% New Zealand 16825 Northchase Drive, Suite 400
Houston, Texas 77060
Swift Energy New Zealand Holdings 100.00% TX 16825 Northchase Drive,
Limited Suite 400
Houston, Texas 77060
Swift Energy Operating, LLC 100.00% TX 16825 Northchase Drive,
Suite 400
Houston, Texas 77060
VIII-i
Swift Energy USA, Inc. 100.00% DE 103 Foulk Road, Suite 202
Wilmington, Delaware 19803
Southern Petroleum (New Zealand) 100.00% TX 16825 Northchase
Exploration Limited Suite 400
Houston, Texas 77060
Swift Energy Alaska, Inc. 100.00% DE 16825 Northchase
Suite 400
Houston, Texas 77060
Partnerships:
Swift Energy Development Program 40.00% TX c/o Swift Energy Company
1996-A, Ltd. 16825 Northchase Drive, Suite 400
Houston, Texas 77060
Swift Energy Development Program 40.00% TX c/o Swift Energy Company
1998, Ltd. 16825 Northchase Drive, Suite 400
Houston, Texas 77060
VIII-ii
X-i
EXHIBIT X
Pricing schedule
------------------------------------------ ---------------- ----------------- --------------- ---------------
Level I Level II Level III Level IV
Status Status Status Status
------------------------------------------ ---------------- ----------------- --------------- ---------------
Applicable Margin
------------------------------------------ ---------------- ----------------- --------------- ---------------
Eurodollar Rate Loans 100 bps. 125 bps 150 bps 175 bps
------------------------------------------ ---------------- ----------------- --------------- ---------------
Alternate Prime Rate Loans 0.00% bps 0.00% bps 0.00% bps 0.25 bps
------------------------------------------ ---------------- ----------------- --------------- ---------------
Applicable Fee Rate (*) 25 bps 30 bps 35 bps 37.5 bps
------------------------------------------ ---------------- ----------------- --------------- ---------------
For the purposes of this Schedule, the following terms have the following
meanings subject to the final paragraph of this Schedule:
"Borrowing Base Usage" means, as of any date, the percent of
the Borrowing Base then in effect represented by the sum of (i) the
aggregate principal amount of all loans then outstanding under this
Agreement, plus (ii) the aggregate face amount of all Letters of Credit
then outstanding under this Agreement.
"Level I Status" exists at any date if the Borrowing Base
Usage as of such date is less than 50%.
"Level II Status" exists at any date if the Borrowing Base
Usage as of such date is less than 75%, but equal to or in excess of
50%.
"Level III Status" exists at any date if the Borrowing Base
Usage as of such date is less than 90%, but equal to or in excess of
75%.
"Level IV Status" exists at any date, if the Borrower has not
qualified for Level I Status, Level II Status, or Level III Status.
"Status" means Level I Status, Level II Status, Level III
Status, or Level IV Status.
Applicable Fee Rate determined in accordance with the pricing Schedule hereto on
the average daily unused (outstanding Letters of Credit will count as usage)
portion of the Commitment Amount, payable quarterly in arrears to the
Administrative Agent for the ratable benefit of the Lenders (including the
Administrative Agent) from closing until the Final Maturity.
The Applicable Margin and Applicable Fee Rate shall be determined by the
Administrative Agent from time to time in accordance with the foregoing table.
X-i