UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-34722

PAA Natural Gas Storage, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		27-1679071 (I.R.S. Employer Identification No.)
333 Clay Street, Suite 1500, Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

(713) 646-4100
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Each Exchange on Which Registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

     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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ (Do not check if a smaller reporting company)		Smaller reporting company o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

     The aggregate market value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $315 million on June 30, 2010, based on $23.83 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on such date.

     At February 28, 2011, there were outstanding 59,184,450 Common Units.

DOCUMENTS INCORPORATED BY REFERENCE
NONE

 

 

PAA NATURAL GAS STORAGE, L.P. AND SUBSIDIARIES
FORM 10-K—2010 ANNUAL REPORT

Table of Contents

				Page
PART I
Items 1 and 2.		Business and Properties			4
Item 1A.		Risk Factors			21
Item 1B.		Unresolved Staff Comments			40
Item 3.		Legal Proceedings			40
Item 4.		(Removed and Reserved)			40
PART II
Item 5.		Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities			41
Item 6.		Selected Financial Data			43
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			45
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			57
Item 8.		Financial Statements and Supplementary Data			58
Item 9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			58
Item 9A.		Controls and Procedures			58
Item 9B.		Other Information			59
PART III
Item 10.		Directors and Executive Officers of Our General Partner and Corporate Governance			60
Item 11.		Executive Compensation			66
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			83
Item 13.		Certain Relationships and Related Transactions, and Director Independence			85
Item 14.		Principal Accountant Fees and Services			89
PART IV
Item 15.		Exhibits and Financial Statement Schedules			90
EX-10.15
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

FORWARD-LOOKING STATEMENTS

           All statements included in this report, other than statements of historical fact, are forward-looking statements, including but not limited to statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of these words, however, does not mean that the statements are not forward-looking. These statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results to differ materially from the results anticipated in the forward-looking statements. These factors include, but are not limited to:

	•		the impact of operational and commercial factors that could result in an inability on our part to satisfy our contractual commitments and obligations, including the impact of equipment performance, cavern operating pressures and cavern temperature variances;
	•		risks related to the development and operation of natural gas storage facilities;
	•		failure to implement or execute planned internal growth projects on a timely basis and within targeted cost projections;
	•		interruptions in service and fluctuations in tariffs or volumes on third party pipelines;
	•		general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns;
	•		the successful integration and future performance of acquired assets or businesses;
	•		our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;
	•		the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations;
	•		significantly reduced volatility in natural gas markets for an extended period of time;
	•		factors affecting demand for natural gas and natural gas storage services and the rates we are able to charge for such services;
	•		our ability to maintain or replace expiring storage contracts at attractive rates and on other favorable terms;
	•		the effects of competition;
	•		shortages or cost increases of supplies, materials or labor;
	•		weather interference with business operations or project construction;
	•		our ability to receive open credit from our suppliers and trade counterparties;
	•		continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;
	•		the effectiveness of our risk management activities;
	•		the availability of, and our ability to consummate, acquisition or combination opportunities;
	•		environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
	•		increased costs or unavailability of insurance;

	•		fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plan;
	•		future developments and circumstances at the time distributions are declared; and
	•		other factors and uncertainties inherent in the development and operation of natural gas storage facilities.

Other factors, described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. See Item 1A. “Risks Factors.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

PART I

Items 1 and 2. Business and Properties

General

          PAA Natural Gas Storage, L.P. is a Delaware limited partnership formed by Plains All American Pipeline, L.P. (“PAA”) on January 15, 2010. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K and unless the context indicates otherwise, the terms “Partnership,” “PNG,” “we,” “us,” “our,” “ours” and similar terms refer to PAA Natural Gas Storage, L.P. and its subsidiaries.

          Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. As of December 31, 2010, we owned and operated two natural gas storage facilities located in Louisiana and Michigan. On February 9, 2011, we closed the acquisition of a third natural gas storage facility in Mississippi. See “— Recent Developments.” We also lease storage capacity and pipeline transportation capacity from third parties from time to time in order to increase our operational flexibility and enhance the services we offer our customers.

          We provide natural gas storage services to a broad mix of customers, including local gas distribution companies, or LDCs, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. Our storage rates are regulated under Federal Energy Regulatory Commission, or FERC, rate-making policies, which currently permit our facilities to charge market-based rates for our services.

Organizational History

          We were formed as a limited partnership to own, operate and grow the natural gas storage business of PAA in which it acquired its initial interest in 2005. Our 2% general partner interest is held by PNGS GP LLC, a Delaware limited liability company, whose sole member is PAA. References to our “general partner,” as the context requires, include only PNGS GP LLC.

Partnership Structure and Management

          On May 5, 2010, we completed our initial public offering. As a result of this transaction, we issued 13.5 million common units to the public, representing an approximate 23% ownership interest in the Partnership. In exchange for contributing its natural gas storage business and $16.4 million of intercompany indebtedness, PAA received a 2% general partner interest, 18.1 million common units, 13.9 million Series A subordinated units and 11.5 million Series B subordinated units, as well as incentive distribution rights. In August 2010, our partnership agreement was amended to reflect the exchange by PAA of two million Series A subordinated units for two million newly issued Series B subordinated units. As a result, at December 31, 2010, PAA owned an aggregate direct and indirect 77% ownership interest in PNG comprised of the general partner’s 2% interest, 18.1 million common units, 11.9 million Series A subordinated units and 13.5 million Series B subordinated units, as well as incentive distribution rights. The Series B subordinated units are not entitled to participate in our quarterly distributions unless and until they convert into Series A subordinated units or common units. The Series B subordinated units are, however, entitled to vote on matters submitted to a vote by our unitholders.

          In connection with the Southern Pines Acquisition completed on February 9, 2011, we issued 27.6 million common units in a private placement of which 10.2 million units were issued to PAA. As a result of this transaction, as of February 9, 2011, PAA owned an aggregate 64% interest in us consisting of the general partner’s 2% interest, 28.3 million common units, 11.9 million Series A subordinated units and 13.5 million Series B subordinated units, as well as incentive distribution rights. See “— Recent Developments.” The diagram below illustrates the structure of PAA Natural Gas Storage, L.P. at February 28, 2011.

          PNGS GP LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. We have entered into an omnibus agreement with PAA and certain of its affiliates, which governs certain aspects of our relationship with them, including the provision by PAA’s general partner to us of certain general and administrative services and employees, our agreement to reimburse PAA’s general partner for the cost of such services and employees, certain indemnification obligations, the use by us of the name “PAA” and related marks, and other matters. See Item 10. “Directors and Executive Officers of Our General Partner and Corporate Governance” and Item 13. “Certain Relationships and Related Transactions, and Director Independence — Related Party Transactions — Omnibus Agreement.”

          As is common with publicly traded partnerships and in order to maximize operational flexibility, we conduct our operations through our subsidiaries.

Our Business Strategy

          Our principal business strategy is to capitalize on the anticipated long-term growth in demand for natural gas storage services in North America by owning and operating high-quality natural gas storage facilities and providing to our current and future customers reliable, competitive and flexible natural gas storage and related services. In executing this strategy, we intend to expand the scope and scale of our business, grow our earnings and cash flow and increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:

	•		Optimizing our existing natural gas storage facilities. Our primary commercial objective is to generate a significant portion of our revenues by committing a high percentage of our storage capacity under firm multi-year storage contracts. We also provide our customers with a variety of hub services that are designed to accommodate customer needs, maximize the utilization of our assets and optimize our earnings and cash flow. Commercially and operationally, we routinely seek to optimize our profitability by executing various initiatives that increase our efficiency, reliability and flexibility.
	•		Organically expanding our existing natural gas storage facilities. Our existing assets enable us to expand our storage capacity on what we believe to be attractive economic terms. We currently have permitted expansion activities underway at each of our three facilities. Including the acquisition of Southern Pines in February 2011 and expansions that are currently permitted and under construction, we have the potential to increase our capacity from approximately 50 billion cubic feet (Bcf) of working capacity at December 31, 2010 to an aggregate of over 110 Bcf of working capacity at these three facilities.
	•		Pursuing strategic and accretive acquisition or development projects. We continually evaluate opportunities to acquire or develop new natural gas storage facilities in our existing and new markets. In general, we are seeking acquisition or development opportunities that will be accretive (or result in an increase in distributable cash flow on a per unit basis) and that will add natural gas storage assets or facilities that either complement our existing assets or strategically enhance our overall business by facilitating our entry into a desirable new market, diversifying our customer base or positioning us for future growth.
	•		Leasing storage capacity and transportation services from third parties to enhance operational flexibility. In order to supplement our owned storage capacity, increase our operating flexibility, enhance the services that we are capable of offering to our customers and optimize the commercial performance of our assets, we periodically lease storage and/or transportation capacity from third parties.
	•		Utilizing a portion of our owned and leased storage capacity to enhance our commercial management activities. Similar to the business model successfully employed by PAA, and without altering our basic commercial strategy of committing a high percentage of our storage capacity under firm multi-year storage contracts at attractive rates, during 2010 we established a dedicated commercial marketing group that will capture market opportunities by leasing storage capacity for our own account and engaging in related commercial marketing activities.

Our Financial Strategy

          An important factor to successfully grow our business will be our ability to maintain a competitive cost of capital and sufficient access to the capital markets. These factors will be significantly influenced by our ability to grow our distribution to unitholders, maintain a solid credit profile and ultimately achieve and maintain an investment-grade credit rating.

          Targeted Credit Profile. We have targeted a general credit profile that has the following attributes:

	•		a long-term debt-to-total capitalization ratio of 40% or less;
	•		an average long-term debt-to-Adjusted EBITDA multiple of approximately 3.5x to 4.0x (Adjusted EBITDA is earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan expense, gains and losses from derivative activities and selected items that are generally unusual or non-recurring); and
	•		an average Adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.

          In order for us to maintain our targeted credit profile, we generally intend to fund approximately 60% of the capital required for expansion projects beyond the projects currently under development, as well as future acquisitions, through a combination of equity capital and cash flow in excess of distributions. From time to time, we may be outside the parameters of our targeted credit profile due to timing issues related to the initial funding of certain capital expenditures or acquisitions with debt or delays in realizing increases in Adjusted EBITDA, synergies or other benefits from expansion and/or acquisition projects. For example, as a result of the timing of growth in Adjusted EBITDA related to the Southern Pines Acquisition, we expect our long-term debt to Adjusted EBITDA multiple will be above our target range until the second half of 2012. See “— Recent Developments.”

          When considered together with what we believe to be the relatively low-risk profile of our business, we believe this credit profile is consistent with an investment grade credit rating. In combination with our intent to maintain a high percentage of storage capacity under multi-year contracts, we believe this credit profile should provide flexibility during periods where storage markets become oversupplied and thus position us to take advantage of attractive acquisition opportunities.

          Credit Rating. We have not applied for a credit rating from any credit rating agency, nor to our knowledge has any such credit rating been assigned. Additionally, we do not currently intend to apply for a credit rating until such time as we expect to access the public debt capital markets. If and when we seek a credit rating, our credit rating may be positively or negatively impacted by the leverage and credit rating of PAA. In addition, while we believe our targeted credit profile is consistent with an investment grade rating, we can provide no assurance in this regard. See Item 1A. “Risk Factors — The credit and risk profile of our general partner and its owner, PAA, could adversely affect our credit and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.”

Our Competitive Strengths

          We believe that the following competitive strengths will position us to successfully execute our principal business strategy:

	•		Our natural gas storage assets are strategically located and operationally flexible. Our Pine Prairie, Southern Pines and Bluewater storage facilities are strategically positioned relative to several major market hubs and have extensive pipeline header systems that are interconnected directly or indirectly with multiple large-diameter interstate and intrastate pipelines. These facilities enable us to serve a variety of major producing regions and LNG importers as well as the primary consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast. After giving effect to the Southern Pines Acquisition (see “— Recent Developments”), our three facilities have permitted aggregate peak injection and withdrawal capacity of 2.9 Bcf per day and 5.6 Bcf per day, respectively. Upon the completion of current expansion activities, these capacities will increase to 4.1 Bcf per day of peak rate injection capacity and 6.4 Bcf per day of peak rate withdrawal capacity. Utilization of a portion of our existing and planned capacity is subject to market demand and receipt of appropriate governmental approvals.
	•		Our business generates relatively stable and predictable cash flow. Given the high percentage of our cash flow that is derived from fixed-capacity reservation fees under multi-year contracts with a diverse portfolio of customers, our baseline cash flow profile is relatively stable and predictable, which we believe significantly mitigates the risk to us of negative cash

			flow fluctuations caused by changing supply and demand conditions and other market factors. In addition, we do not take title to the natural gas that we store for our customers and, accordingly, are not exposed to commodity price fluctuations on the gas that is stored in our facilities by our customers.
	•		Our storage facilities have the ability to be significantly expanded at competitive costs and with a relatively high degree of schedule certainty. Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our facilities significantly beyond their current size. In addition, because the existing infrastructure at two of our facilities has been specifically designed to facilitate future expansion, as we expand these facilities we expect to both reduce our overall capital costs per additional Bcf of storage capacity and shorten the length, and enhance the predictability of, our development cycle.
	•		We have the evaluation, integration and engineering skill sets in-house that are necessary to successfully pursue acquisition and expansion opportunities. We possess the in-house capabilities and expertise necessary to develop, construct, own, acquire and operate both depleted reservoir and salt-cavern storage capacity. We and our predecessor have been involved in substantially all aspects of the natural gas storage business since 2005 and our operational and management teams have extensive energy industry and acquisition experience.
	•		We have the financial flexibility to pursue acquisition and expansion opportunities. We believe our borrowing capacity and our ability to access private and public debt and equity capital should provide us with the financial flexibility necessary to execute our growth and expansion strategy. Additionally, PAA may elect, but is not obligated, to provide us with financial support in connection with acquisitions or expansion capital projects in certain circumstances.
	•		Our general partner has an experienced management team with specialized knowledge of natural gas storage and markets and whose interests are aligned with those of our unitholders. Our general partner has an executive management team that has extensive experience managing, operating, building, acquiring and integrating energy assets, including natural gas storage assets and other midstream energy assets. Through their indirect and direct interests in us, our general partner and PAA, our general partner’s executive and senior management team has a significant, vested interest in our continued success.

          We believe these competitive strengths will aid our efforts to expand our presence in the natural gas storage sector.

Our Relationship with PAA

          We believe one of our strengths is our relationship with PAA, which is one of the largest publicly-traded master limited partnerships as measured by equity market capitalization, which was approximately $8.9 billion as of December 31, 2010. PAA’s common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol “PAA.” In addition to its participation in the natural gas storage business through its ownership interest in us, PAA is engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products. PAA’s assets include approximately 16,000 miles of pipelines, approximately 90 million barrels of storage capacity, and a significant fleet of trucks, trailers, tugs, barges and railcars. Through its transportation, storage and commercial activities, PAA physically handles in excess of 3 million barrels per day of petroleum products.

          PAA and its predecessors have been active participants in the hydrocarbon storage industry since the early 1990s. PAA has a long history of successfully expanding its energy infrastructure businesses through a combination of organic growth projects and complementary acquisitions. Since its initial public offering in 1998, PAA has grown its asset base from approximately $600 million to approximately $14 billion and increased the annualized distribution on its limited partner units by over 100%, from $1.80 per unit as of PAA’s initial public offering to $3.83 per unit for the distribution paid in February 2011.

          Our partnership owns all of the natural gas storage business and assets formerly owned by PAA and PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business. As the ultimate owner of our 2% general partner interest, all of our incentive distribution rights and an approximate 62% limited partner interest in us (including common units, Series A subordinated units and Series B subordinated units) following the Southern Pines Acquisition and related financings, PAA has a significant economic stake in us and a commensurate incentive to promote and support the successful execution of our growth plan and strategy. See “— Recent Developments.”

          We have also entered into an omnibus agreement with PAA and certain of its affiliates, pursuant to which PAA’s general partner has agreed to provide us with certain general and administrative services and employees, and we have agreed to reimburse PAA’s general partner for the costs of such services.

          We believe PAA’s significant presence in the energy sector, its successful track record of growth and its significant investment in, and sponsorship and support of, us enhances our ability to grow our business.

Recent Developments

Acquisition of SG Resources Mississippi, L.L.C.

          On February 9, 2011, we acquired 100% of the equity interests in SG Resources Mississippi, L.L.C. (the “Southern Pines Acquisition”), which entity owns the Southern Pines Energy Center natural gas storage facility (“Southern Pines”), for total consideration of approximately $746 million, subject to certain post-closing adjustments.

          Southern Pines is a FERC-regulated, high-performance, salt-cavern natural gas storage facility located in Greene County, Mississippi. The facility’s current permits allow for 40 Bcf of working capacity from four storage caverns. The facility commenced service in 2008 and three caverns have been placed into service, which are serving over 17 Bcf of customer contracts. These caverns are being expanded over time to their permitted capacity of 10 Bcf each. The fourth cavern is currently being drilled. Drilling is expected to be completed during the second quarter of 2011, at which point leaching will commence. The fourth cavern is anticipated to be placed into service in the third quarter of 2012. The facility has the capacity for further expansion beyond 40 Bcf, if warranted by market demand and subject to receipt of required permits. Based on our estimates of current working capacity and the projected working capacity to be created, Southern Pines is fully contracted for the 2011/2012 and 2012/2013 storage seasons and substantially contracted for the 2013/2014 and 2014/2015 storage seasons (storage seasons run from April — March). Working capacity of salt cavern facilities is dependent, among other factors, on cavern temperature and pressure as well as the leaching rate achieved to create incremental space. As a result, aggregate capacity available to serve existing contracts may at times exceed or lag aggregate contractual obligations. As of January 1, 2011, existing contracts at Southern Pines had a remaining weighted average term of approximately 5.5 years. As a result, we believe that Southern Pines will generate stable and predictable, low-risk, fee-based revenues.

          Southern Pines has an aggregate of 48,000 horsepower of compression and is permitted to accommodate injection and withdrawal capabilities of approximately 1.2 Bcf and approximately 2.4 Bcf of gas per day, respectively. Southern Pines is designed to accommodate daily injection and withdrawal capabilities of 1.5 Bcf and 3.0 Bcf, respectively. Utilization of such incremental capacity is subject to market demand and would require governmental approval. Southern Pines is connected directly or indirectly to eight major natural gas pipelines servicing the Gulf Coast, Northeast, Mid-Atlantic and Southeastern U.S. markets.

          In connection with the transaction, we raised $800 million of capital, which funded the purchase price, estimated closing and integration costs and the first 18 months of expected expansion capital related to Southern Pines. This financing was composed of $600 million of equity and $200 million of debt. The equity financing included a private placement of 17.4 million PNG common units to third-party purchasers for net proceeds of approximately $370 million and the sale of 10.2 million PNG common units to PAA for net proceeds of approximately $230 million, including PAA’s proportionate general partner contribution of $12 million. The debt financing consisted of PNG issuing a three-year, $200 million note to PAA at an interest rate of 5.25% per annum. The note will mature on February 9, 2014. As a result of the equity financing, PAA’s aggregate equity ownership in us decreased to 64% from 77% prior to the transaction. PAA continues to own 100% of our general partner and our incentive distribution rights. During the fourth quarter of 2010, we made a deposit related to the Southern Pines Acquisition of $20 million which was reflected as restricted cash on our consolidated balance sheet as of December 31, 2010. Because of the ongoing expansion activities and lead time necessary to increase Southern Pines’ contributions to Adjusted EBITDA, we anticipate we will be outside the parameters of our targeted credit profile until the second half of 2012.

Bluewater Incident

          On January 12, 2011, we experienced an operational incident and related fire at our Bluewater natural gas storage facility located in St. Claire County, Michigan. Facility damage from the incident was limited to the portion of Bluewater’s gas handling facility that removes liquids from natural gas that is withdrawn from the larger of Bluewater’s two storage reservoirs before such gas is injected into pipelines for transportation. As a result, the amount of gas that can be withdrawn from that storage reservoir has been temporarily limited. Gas is still able to be withdrawn from the other storage reservoir and we do not expect that our ability to

inject gas into either reservoir will be impacted for any extended period. Through the utilization of these capabilities, our leased storage in the market area and other operational and commercial alternatives, we have to date been able to meet all of our customers’ contractual requirements. Based on our current expectations of customer demands, we expect to be able to continue to meet our obligations throughout the remainder of the withdrawal season, which typically ends on March 31st. Because this incident is not expected to materially impact Bluewater’s injection capabilities, we do not anticipate any material issues in satisfying our customer obligations during the injection season, which follows the withdrawal season and typically ends on September 30th.

          Subject to receiving the necessary regulatory clearances and permits, we are targeting to have the damaged portion of the facility back in service by October 2011, which should return Bluewater to fully functional operation for the balance of the 2011/2012 storage season. We currently estimate the cost of the reconstruction will be in the range of $3.5 to $5 million and we have a $500,000 insurance deductible for property damage. As a result of this incident, we have had to defer until early 2012 our planned capital program for Bluewater with respect to the drilling of two additional liquid withdrawal wells.

Natural Gas Market Overview

          North American natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. The long term demand for storage services in the United States is driven primarily by the long-term demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In general and on a long term basis, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations, should increase the need for and the value of storage services. On a short term basis, storage demand and values are also significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.

          Natural Gas Demand. During the period from 2001 through 2010, domestic natural gas consumption has grown, albeit unevenly, driven primarily by growth in the seasonal and weather-sensitive electric power generation and commercial sectors, offset by declines in the residential and industrial sectors. The chart below, based on U.S. Energy Information Administration (“EIA”) data and forecasts, shows the overall growth in consumption (and the disposition of such growth) for the ten year period ended November 2010. The chart also includes EIA forecasted data for December 2010, and calendar years 2011 and 2012, which suggests relatively flat overall consumption of natural gas for the next two years.

          Natural Gas Supply. For a number of years during the last decade, domestic natural gas production was relatively flat and failed to keep pace with domestic consumption. Over the past several years, however, domestic natural gas production has been growing. This trend reversal is primarily due to increases in production from developing shale resource plays. According to EIA data, domestic production of natural gas increased by an average of approximately 3.7% per annum during the four year period from January 1, 2007 through December 31, 2010.¹ By comparison, EIA data also indicates that 2009 production from shale gas wells was approximately 3.1 trillion cubic feet (Tcf), representing an approximate 142% increase over 2007 levels. At the time of this report, 2010 production estimates by component (i.e. shale gas) were not available from EIA.

          In addition to the emergence of domestic shale plays as a significant supply source, over the past several years the U.S. has developed significant infrastructure for the import of liquefied natural gas (“LNG”). Total LNG import capacity of U.S. infrastructure has increased to approximately 16 Bcf per day; however, because LNG suppliers have been able to obtain more favorable prices in global markets outside of the U.S., LNG imports into the U.S. have decreased from a peak of 2.1 Bcf a day in 2007 to less than 1.2 Bcf per day in 2009 and 2010, per EIA and other published daily data sources.

          Market Balance and Volatility. The seasonality of natural gas has remained strong during the last decade, with consumption during the peak winter months averaging approximately 40% more than consumption during the summer months, per EIA data. For the lower 48 states, from January 1, 2010 to December 31, 2010, U.S. consumption reached peak use of more than 110 Bcf on January 5, while the lowest daily consumption during this same period was approximately 46 Bcf on September 5, per EIA and other published daily data sources. On the other hand, daily U.S. production in the lower 48 during this same twelve month period ranged from 56 Bcf to 63 Bcf. Natural gas storage (and to a lesser extent imported natural gas from Canada and LNG supplies) served as the “shock absorber” that balanced the market, serving as a source of supply to meet the consumption demands in excess of daily production capacity and a warehouse for gas production in excess of daily demand during low demand periods. This seasonal consumption pattern is a major driver of demand for gas storage and the price difference, or “spread,” between the summer and winter season provides a proxy for the fundamental value of storage.

          During most of the past decade, this strong seasonal trend has produced seasonal spreads that have generally moved within a range of approximately $0.50-$4.75 per MMBtu, with the high end of that range occurring during the 2006-2007 timeframe. However, during the past six months, seasonal spreads fell to as low as $0.43, their lowest point since 2004. In addition, lower short term spreads and basis differentials have reduced overall market volatility, which negatively impacts storage demand and value.

While there are a variety of factors that have contributed to these softer market conditions, we believe the key drivers are (i) relatively flat natural gas consumption over the last year and projected flat consumption for the next two years, (ii) increased natural gas supplies due to production from shale resources, (iii) lower basis differentials due to expansion of natural gas transportation infrastructure in the U.S. over the last five years, and (iv) abnormal seasonal weather patterns resulting in decreased seasonal price spreads.

          Supply of Storage Capacity. Another important factor in determining the value of storage is whether there is a surplus or shortfall of storage capacity relative to the overall demand for storage services in a given market area. In general, on a relative basis, storage values will be lower in markets that are oversupplied with storage than in markets where storage capacity is in short supply. The extent to which markets are oversupplied or undersupplied will fluctuate based on capacity additions and in response to significant variations in natural gas supply and demand.

          According to EIA data and as indicated in the chart below, peak storage utilization as a percentage of peak storage capacity has generally increased over the last six years, climbing from 91% in 2005 to 99% in 2009 and then settling down to 95% in 2010, in part due to a 4.1% increase in peak capacity relative to 2009 levels. Despite the increase in storage capacity and a warmer than normal summer in 2010, storage inventories reached a record peak level of 3.84 Tcf in November of 2010.

		Non Coincident Peak				Max Inventory in
		Capacity (Tcf)				Storage (Tcf)				Peak Utilization
2005			3.600				3.282				91	%
2006			3.609				3.461				96	%
2007			3.703				3.545				96	%
2008			3.789				3.488				92	%
2009			3.889				3.837				99	%
2010			4.049				3.840				95	%

          While it is difficult to predict when, and how much, new capacity will be added to the market in the next few years, we believe that certain of the supply and demand factors contributing to the current softness in the storage market (i.e., robust supply levels, lower natural gas demand levels and reduced price volatility) are cyclical and self correcting over time, and that the long term outlook for storage utilization and demand is positive.

Our Assets

          As of December 31, 2010 we owned a 100% interest in two natural gas storage facilities: the Pine Prairie facility, which is a recently constructed, high-deliverability salt-cavern natural gas storage complex located in Evangeline Parish, Louisiana, and the Bluewater facility, which is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. The following table contains certain information regarding our Pine Prairie and Bluewater storage facilities as of December 31, 2010:

										Peak
		Working Gas				Peak Injection				Withdrawal				Compression
Facility Name and Type		Capacity (Bcf)				Rate (Bcf/d)				Rate (Bcf/d)				(Horsepower)
Pine Prairie (salt-cavern)
Existing facility			24				1.2				2.4				48,000
Planned & permitted expansion			21	(1)			1.2	(2)			0.8	(2)			50,500	(3)
Subtotal			45				2.4				3.2				98,500
Bluewater (depleted reservoir) (5)
Existing facility			26				0.5				0.8				13,350
Planned expansion			2	(4)			—				—				—
Subtotal			28				0.5				0.8				13,350
Total (both facilities) (5) (6)			73				2.9				4.0				111,850

          Pine Prairie. As a strategically-located, high-deliverability storage facility, Pine Prairie has attracted a diverse group of customers, including utilities, pipelines, producers, power generators, marketers and LNG importers, whose storage needs include both traditional seasonal storage services and short-term storage services. Pine Prairie is strategically positioned relative to several major market hubs, including:

	•		the Henry Hub, which is the delivery point for New York Mercantile Exchange (“NYMEX”) natural gas futures contracts and is located approximately 50 miles southeast of Pine Prairie;
	•		the Carthage Hub in east Texas, which is located approximately 150 miles northwest of Pine Prairie; and
	•		the Perryville Hub in north Louisiana, which is located approximately 130 miles north of Pine Prairie.

          Additionally, in January 2011, the CME Group, which owns the NYMEX, announced the introduction of three new natural gas futures contracts for physical delivery at Pine Prairie. The contracts began trading in February 2011 on the NYMEX floor and electronically through CME Globex and will be available for clearing services through CME ClearPort.

          Pine Prairie’s pipeline header system, which includes an aggregate of 74 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, is directly connected to eight large-diameter interstate pipelines through nine interconnects that service both conventional and unconventional natural gas production in Texas and Louisiana, including production from existing and

emerging shale plays, as well as Gulf of Mexico production and LNG imports. These interconnects also provide direct or indirect access to each of the market hubs described above and to consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast regions of the United States.

          Pine Prairie has a total current working gas storage capacity of 24 Bcf in three caverns, and planned expansions that will increase Pine Prairie’s total capacity to 42 Bcf by mid-2012 and 45 Bcf by mid-2016 (see table above). Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account and with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf.

          In October 2010 we filed an application for a permit from the FERC to expand Pine Prairie’s working capacity up to 80 Bcf. The incremental 32 Bcf would be comprised of expanding four existing caverns by an aggregate 8 Bcf through low-cost fill and dewater operations and adding two additional caverns of 12 Bcf each, increasing the total caverns at Pine Prairie to seven caverns.

          Bluewater. Bluewater is located in the State of Michigan, which contains more underground natural gas storage capacity than any other state in the U.S. according to EIA data, and primarily services seasonal storage needs throughout the Midwestern and Northeastern portions of the U.S. and the Southeastern portion of Canada. Accordingly, Bluewater’s customers consist primarily of pipelines, utilities and marketers seeking seasonal storage services. Bluewater’s 30-mile, 20-inch diameter pipeline header system is supported by 13,350 horsepower of compression and connects with three interstate and three natural gas utility pipelines that provide access to the major market hubs of Chicago, Illinois and Dawn, Ontario, which supply natural gas to eastern Ontario and the northeastern United States. These interconnects also provide access to natural gas utilities that serve local markets in Michigan and Ontario.

          As indicated in the table above, Bluewater has total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs and we expect to increase Bluewater’s working gas capacity by 2 Bcf ratably over a 9 to 10-year period in connection with an ongoing liquids removal project. Bluewater also leases third-party storage capacity and pipeline transportation capacity from time to time to increase its operational flexibility and enhance its service offerings.

Recent Acquisition

          On February 9, 2011, we closed the Southern Pines Acquisition. See “— Recent Developments.” Following is a description of the principal asset acquired in the Southern Pines Acquisition.

          Southern Pines. Southern Pines is a FERC-regulated, high-performance, salt-cavern natural gas storage facility located in Greene County, Mississippi. The facility’s permits allow for 40 Bcf of working capacity from four storage caverns. The facility commenced service in 2008 and three caverns have been placed into service, which are serving over 17 Bcf of customer contracts. These caverns are being expanded over time to their permitted capacity of 10 Bcf each. The fourth cavern is currently being drilled. Drilling is expected to be completed during the second quarter of 2011, at which point leaching will commence. The fourth cavern is anticipated to be placed into service in the third quarter of 2012. The facility has the capacity for further expansion beyond 40 Bcf, if warranted by market demand and subject to availability of additional permits.

          Southern Pines has an aggregate of 48,000 horsepower of compression and is permitted to accommodate daily injection and withdrawal capabilities of approximately 1.2 Bcf and approximately 2.4 Bcf of gas per day, respectively. Southern Pines is designed to accommodate daily injection and withdrawal capabilities of 1.5 Bcf and 3.0 Bcf, respectively, but the utilization of such incremental capacity is subject to market demand and would require governmental approval. Southern Pines is connected directly or indirectly to 8 major natural gas pipelines servicing the Gulf Coast, Northeast, Mid-Atlantic and Southeastern U.S. markets.

Our Operations

          We provide natural gas storage services to a broad mix of customers, including local gas distribution companies, or LDCs, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. Our storage rates are regulated under Federal Energy Regulatory Commission, or FERC, rate-making policies, which currently permit our facilities to charge market-based rates for our services.

          We generate revenue almost exclusively through the provision of fee-based gas storage services to our customers. For the year ended December 31, 2010, approximately 97% of our total revenue was derived from fee-based storage activities, with the remaining approximately 3% primarily attributable to the sale of liquid hydrocarbons incidentally produced in connection with the operation of our depleted reservoir storage facilities at Bluewater as well as other fuel and derivative related net gains and losses. Our revenues from fee-based gas storage services are derived from both “firm storage services” and “hub services.”

	•		Firm Storage Services. Firm storage services include (i) storage services pursuant to which customers receive the assured or “firm” right to store gas in our facilities over a multi-year period and (ii) seasonal “park and loan” services pursuant to which customers receive the “firm” right to store gas in (park), or borrow gas from (loan), our facilities on a seasonal basis. Under our firm storage contracts, our customers are obligated to pay us fixed monthly capacity reservation fees, which are owed to us regardless of the actual storage capacity utilized. At Pine Prairie, our firm storage contracts typically have terms of 3 to 5 years, while at Bluewater terms generally range from 1 to 3 years. As of December 31, 2010, the weighted average remaining tenor of our existing portfolio of firm storage contracts is approximately 3.0 years at Pine Prairie and approximately 2.1 years at Bluewater. At Southern Pines, acquired in February 2011, existing contracts have a remaining weighted average term of approximately 5.5 years as of January 1, 2011. Under our firm storage contracts, we also typically collect a “cycling fee” based on the volume of natural gas nominated for injection and/or withdrawal and retain a small portion of natural gas nominated for injection as compensation for our fuel use. For the year ended December 31, 2010, approximately 91% of our total revenue was derived from firm storage services.
	•		Hub Services. We also generate revenue from the provision of “hub services” at our facilities. Hub services include (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from, our facilities. For the year ended December 31, 2010, approximately 6% of our total revenue was derived from hub services.

          We believe that the high percentage of our baseline cash flow derived from fixed-capacity reservation fees under firm multi-year contracts with a diverse portfolio of customers stabilizes our cash flow profile and substantially mitigates the risk to us of significant negative cash flow fluctuations caused by changing supply and demand conditions and other market factors.

          Additionally, without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year storage contracts, during 2010 we formed a dedicated commercial marketing group in order to capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Through these transactions, we will seek to maintain a position that is substantially balanced between purchases on the one hand and sales or future delivery obligations on the other hand. Our general policy is (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.

Customers

          We provide storage services to a broad mix of customers including LDCs, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. LDCs use storage services for seasonal balancing, to meet peak day deliveries and ensure reliability. Pipelines use storage services to manage short-term operational balancing requirements. Power generators, marketers and producers generally use storage services for short-term balancing, to manage risk and to take advantage of the pricing differential between near-term and long-term natural gas. LNG importers use storage services to insure they have adequate storage capacity to accommodate imported LNG cargoes.

          As of December 31, 2010 and excluding contracts with a future start date, Pine Prairie had 16 customers with firm storage contracts and Bluewater had 17 customers with firm storage contracts. For the year ended December 31, 2010, Iberdrola Renewables, Inc., Guardian Pipeline, LLC and Anadarko Energy Services accounted for approximately 13%, 9% and 8% of our revenues, respectively. As of closing on February 9, 2011, Southern Pines had 15 customers with firm storage contracts. The number of active hub services customers at each facility fluctuates throughout the course of the year depending on market conditions and other factors.

Contracts

          See “— Our Operations.”

Competition

          The principal elements of competition among storage facilities are rates, terms of service, types of service, supply and market access, and flexibility and reliability of service. An increase in competition in our markets could arise from new ventures or expanded operations from existing competitors.

          Pine Prairie competes with several regional high-deliverability storage facilities along the Gulf Coast as well as the storage services offered by interstate and intrastate pipelines that serve the same markets as Pine Prairie, while Bluewater competes with several Midwest utility and pipeline storage providers. Southern Pines competes with many of the same facilities and pipelines as Pine Prairie.

Regulation

          Our operations are subject to extensive laws and regulations. We are subject to regulatory oversight by numerous federal, state, and local regulatory agencies, many of which are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas storage and pipeline industry, related businesses and individual participants. The failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. Except for certain exemptions that apply to smaller companies, however, we do not believe that we are affected by these laws and regulations in a significantly different manner than are our competitors.

          Following is a discussion of certain laws and regulations affecting us. However, our unitholders should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our operations.

          Our natural gas storage assets are subject to several kinds of regulation. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. The following is a summary of the kinds of regulation that may impact our operations.

Natural Gas Storage Regulation

          Interstate Regulation. Our natural gas storage facilities are classified as “natural-gas companies” under the Natural Gas Act of 1938 (“NGA”), and are therefore subject to regulation by the FERC. The NGA requires that tariff rates for gas storage facilities be just and reasonable and non-discriminatory. The FERC has authority to regulate rates and charges for natural gas transported and stored in U.S. interstate commerce or sold by a natural gas company in interstate commerce for resale. The FERC has granted our natural gas storage facilities market-based rate authority. Market-based rate authorization allows us to negotiate rates with individual customers based on market demand, which Pine Prairie, Bluewater and Southern Pines then make public via postings on their respective websites.

          The FERC also has authority over the construction and operation of U.S. pipeline transportation and storage facilities and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. In addition, the FERC’s authority extends to maintenance of accounts and records, terms and conditions of service, depreciation and amortization policies, acquisition and disposition of facilities, initiation and discontinuation of services, imposition of creditworthiness and credit support requirements applicable to customers and relationships among pipelines and storage companies and certain affiliates.

          Standards of Conduct for Transmission Providers. Historically, the FERC’s standards of conduct regulations (now vacated) generally restricted access to U.S. interstate natural gas storage customer data by marketing and other energy affiliates, and placed certain conditions on services provided by U.S. storage facility operators to their affiliated gas marketing entities. The standards of conduct did not apply, however, to natural gas storage providers authorized to charge market-based rates that (i) were not interconnected with the jurisdictional facilities of any affiliated interstate natural gas pipeline and (ii) had no exclusive franchise area, no captive ratepayers, and no market power. The FERC found that Pine Prairie qualified for this exemption from the standards of conduct in January 2006 and Bluewater qualified for this exemption in October 2006.

          In November 2006, the D.C. Circuit vacated the standards of conduct regulations with respect to natural gas pipelines and storage companies, and remanded the matter to the FERC. Following a notice of proposed rulemaking, in October 2008, the FERC

issued revised Standards of Conduct for Transmission Providers (“Standards of Conduct”). The Standards of Conduct continue to exempt natural gas storage providers like Pine Prairie, Bluewater and Southern Pines. The FERC has since issued three Orders on Rehearing and Clarification in October and November 2009 and April 2010. However, one request for rehearing of the April 2010 order is pending with the FERC. Accordingly, there may be further modifications to the Standards of Conduct upon rehearing.

          Natural Gas Price Transparency. In April 2007, the FERC issued a notice of proposed rulemaking (“NOPR”) regarding price transparency provisions of the NGA and the Energy Policy Act of 2005 (the “EPAct 2005”). In the notice, the FERC proposed to revise its regulations to, among other things, require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC. In December 2007, the FERC issued Order No. 704 implementing the annual reporting provisions of the NOPR with minimal changes to the original proposal. The order became effective in February 2008. The FERC issued two orders on rehearing in 2008, and following a technical conference in March 2010, the FERC issued an order clarifying the reporting requirements in April 2010. Pine Prairie, Bluewater and Southern Pines are subject to these annual reporting requirements.

          In November 2008, the FERC issued Order No. 720 requiring interstate pipelines and certain non-interstate facilities to post certain daily capacity and volume information. The rule extends to storage facilities (such as Bluewater) that provide no-notice service. The rule has been appealed, but pending the results of that appeal, Bluewater will be subject to a requirement to post volumes with respect to no-notice service flows at each receipt and delivery point.

          Energy Policy Act of 2005. Under the EPAct 2005 and related regulations, it is unlawful in connection with the purchase or sale of natural gas or transportation services subject to FERC jurisdiction to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

          Other Proposed Regulation. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot provide assurances that the less stringent and pro-competition regulatory approach recently pursued by the FERC and Congress will continue.

Environmental Matters

          General. Our natural gas storage operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, and other approvals. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities, increases in operating expenses or curtailment of certain operations to limit or prevent the release of materials from our facilities, the incurrence of capital expenditures associated with the installation of pollution control equipment, and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.

          We believe that we are in substantial compliance with existing federal, state, and local environmental laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance of the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental laws and regulations that are applicable to our natural gas storage operations.

          Waste Management. Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws and regulations, which impose detailed requirements for the handling, storage, treatment, and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA

prohibits the disposal of certain hazardous wastes on land without prior treatment. RCRA also requires waste generators subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities receiving such wastes. Generators of hazardous wastes must also comply with certain standards for the accumulation and storage of hazardous wastes and meet recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities.

          Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA,” also known as “Superfund”) and comparable state laws and regulations impose liability — without regard to fault or the legality of the original conduct — on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include current and prior owners or operators of the site where the release occurred and companies that disposed of, or arranged for the disposal of, hazardous substances found at offsite locations such as landfills. CERCLA also authorizes the EPA and, in some instances, third parties, to respond to threats to public health or the environment and seek recovery of response costs from responsible persons. Although natural gas is not classified as a hazardous substance under CERCLA, we may nonetheless handle hazardous substances within the meaning of CERCLA or similar state statutes in the course of our ordinary operations; as a result, we may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where such hazardous substances have been released into the environment, natural resource damages, and the cost of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

          Air Emissions. Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations. These laws and regulations regulate the emission of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in significant air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, and/or utilize specific emission control technologies to limit our emissions. To comply with, maintain, or obtain our air emissions operating permits, we may be required to incur certain capital expenditures in the future for the purchase and installation of air pollution control equipment. For example, we may be required to supplement or modify our air emission control equipment and strategies due to changes in state implementation plans for controlling air emissions or more stringent regulation of hazardous air pollutants.

          Water Discharges. The Clean Water Act (“CWA”) and analogous state laws regulate the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The CWA prohibits the discharge of pollutants into regulated waters, except in accordance with the terms of a permit issued by the EPA or analogous state agency. The CWA also regulates the discharge of storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, which require monitoring and sampling of storm water runoff from such facilities.

          Safe Drinking Water Act. As part of our operations, we employ underground injection wells to inject natural gas into our underground storage facilities. Such operations are subject to the Safe Drinking Water Act (“SDWA”) and analogous state laws, which regulate drinking water quality in the United States, including above ground and underground sources designated for actual or potential drinking water use. In particular, to protect underground sources of drinking water, the Underground Injection Control Program (“UIC Program”) of the SDWA regulates the construction, operation, maintenance, monitoring, testing, and closure of underground injection wells. The UIC Program also requires that all underground injection wells be authorized, either under the general rules of the UIC Program or through specific permits. In most jurisdictions, states have primary enforcement authority over the implementation of the UIC Program, including the issuance of permits.

          Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas

facilities, including underground natural gas storage facilities, on an annual basis beginning in 2012 for emissions occurring in 2011.

          In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHG gases primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

          The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas we store. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Pipeline Safety

          As part of our natural gas storage operations, we own and operate pipeline header systems connecting our natural gas storage facilities to various interstate pipelines. As a result, our pipeline operations are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”). The NGPSA regulates safety requirements in the design, installation, testing, construction, operation and maintenance of gas pipeline facilities. The NGPSA has since been amended by the Pipeline Safety Act of 1992, the Pipeline Safety Improvement Act of 2002, and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. These amendments, along with implementing regulations more recently adopted by PHMSA, have imposed additional safety requirements on pipeline operators such as the development of a written qualification program for individuals performing covered tasks on pipeline facilities and the implementation of pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventative measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. Accordingly, we will continue to focus on pipeline integrity management for any of the pipelines we currently own or acquire in the future, and significant additional expenses could be incurred if new or more stringent pipeline safety requirements are implemented. We believe that our operations are in substantial compliance with all existing federal, state, and local pipeline safety laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations.

Occupational Safety and Health

          Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes designed to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local governmental authorities, and the public. Our operations are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process that involves a chemical at or above specified thresholds or any process that involves 10,000 pounds or more of a flammable liquid or gas in one location. We believe that our operations are in substantial compliance with all existing federal, state, and local occupations health and safety laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations.

Title to Properties and Rights-of-Way

          Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or

governmental authorities permitting the use of such land for our operations. Portions of the land on which our facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to leases between us, as lessee, and the fee owner of the lands, as lessors. We believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses. See “— Our Assets.”

Insurance

          We share insurance coverage with PAA and we reimburse PAA’s general partner pursuant to the terms of the omnibus agreement. To the extent PAA experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased. Our insurance program includes general liability insurance, auto liability insurance, worker’s compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate. In addition, the insurance policies are subject to deductibles that we consider reasonable and not excessive.

          A natural gas storage facility, associated pipeline header system, and gas handling and compression facilities may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property, base gas, and equipment, pollution or environmental damage and suspension of operations. Our insurance does not cover every potential risk associated with operating natural gas storage facility, associated pipeline header system, and gas handling and compression facilities, including the potential loss of significant revenues. The overall trend in the environmental insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the environmental insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our environmental activities or incorporate higher retention in our insurance arrangements.

          The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, although we believe that we have established adequate reserves to the extent that such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

Employees

          Plains All American GP LLC employs all of our personnel. We are managed and operated by the directors and officers of our general partner. We rely on an omnibus agreement with Plains All American GP LLC to provide us with employees needed to carry out our operations. As of December 31, 2010, 53 full time employees of Plains All American GP LLC devoted substantially all of their time to carrying out our operations.

Summary of U.S. Income Tax Considerations

          The following is a brief summary of material tax considerations of owning and disposing of common units, however, the tax consequences of ownership of common units depends in part on the owner’s individual tax circumstances. It is the responsibility of each unitholder, either individually or through a tax advisor, to investigate the legal and tax consequences, under the laws of pertinent U.S. federal, states and localities, of the unitholder’s investment in us. Further, it is the responsibility of each unitholder to file all U.S. federal, state, provincial and local tax returns that may be required of the unitholder.

Partnership Status; Cash Distributions

          We are treated for federal income tax purposes as a partnership based upon our meeting the “Qualifying Income Exception” imposed by Section 7704 of the Internal Revenue Code (the “Code”), which we must meet each year. The owners of our common units are considered partners in the Partnership so long as they do not loan their common units to others to cover short sales or

otherwise dispose of those units. Accordingly, we are not liable for U.S. federal income taxes, and a common unitholder is required to report on the unitholder’s federal income tax return the unitholder’s share of our income, gains, losses and deductions. In general, cash distributions to a common unitholder are taxable only if, and to the extent that, they exceed the tax basis in the common units held.

Partnership Allocations

          In general, our income and loss is allocated to the general partner and the unitholders for each taxable year in accordance with their respective percentage interests in the Partnership, as determined annually and prorated on a monthly basis and subsequently apportioned among the general partner and the unitholders of record as of the opening of the first business day of the month to which they relate, even though unitholders may dispose of their units during the month in question. In determining a unitholder’s U.S. federal income tax liability, the unitholder is required to take into account the unitholder’s share of income generated by us for each taxable year of the Partnership ending with or within the unitholder’s taxable year, even if cash distributions are not made to the unitholder. As a consequence, a unitholder’s share of our taxable income (and possibly the income tax payable by the unitholder with respect to such income) may exceed the cash actually distributed to the unitholder by us. Any time incentive distributions are made to the general partner, gross income will be allocated to the recipient to the extent of those distributions.

Basis of Common Units

          A unitholder’s initial tax basis for a common unit is generally the amount paid for the common unit and the unitholder’s share of our nonrecourse liabilities (or liabilities for which no partner bears the economic risk of loss). A unitholder’s basis is generally increased by the unitholder’s share of our income and by any increases in the unitholder’s share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by the unitholder’s share of our losses and distributions (including deemed distributions due to a decrease in the unitholder’s share of our nonrecourse liabilities).

Limitations on Deductibility of Partnership Losses

          The deduction by a unitholder of that unitholder’s allocable share of our losses will be limited to the amount of that unitholder’s tax basis in his or her common units and, in the case of an individual unitholder or a corporate unitholder who is subject to the “at-risk” rules (generally, certain closely-held corporations), to the amount for which the unitholder is considered to be “at-risk” with respect to our activities, if that is less than the unitholder’s tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause the unitholder’s at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such unitholder’s tax basis in his common units. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain could no longer be used.

          In addition to the basis and at-risk limitation described above, in the case of taxpayers subject to the passive loss rules (generally, individuals and certain closely held corporations), any partnership losses generated by us are only available to offset future income generated by us and cannot be used to offset income from other activities, including passive activities or investments. Any losses unused or suspended by virtue of the passive loss rules may be fully deducted if the unitholder disposes of all of the unitholder’s common units in a taxable transaction with an unrelated party.

Section 754 Election

          We have made the election provided for by Section 754 of the Code, which will generally result in a unitholder being allocated income and deductions calculated by reference to the portion of the unitholder’s purchase price attributable to each asset of the Partnership.

Disposition of Common Units

          A unitholder who sells common units will recognize gain or loss equal to the difference between the amount realized and the adjusted tax basis of those common units. A unitholder may not be able to trace basis to particular common units for this purpose. Thus, distributions of cash from us to a unitholder in excess of the income allocated to the unitholder will, in effect, become taxable income if the unitholder sells the common units at a price greater than the unitholder’s adjusted tax basis even if the price is less than the unitholder’s original cost. Moreover, a portion of the amount realized (whether or not representing gain) will be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

State, Local and Other Tax Considerations

          In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which a unitholder resides or in which we conduct business or own property. A unitholder may also be required to file state income tax returns and to pay taxes in various states. A unitholder may be subject to interest and penalties for failure to comply with such requirements. In certain states, tax losses may not produce a tax benefit in the year incurred (if, for example, we have no income from sources within that state) and also may not be available to offset income in subsequent taxable years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be more or less than a particular unitholder’s income tax liability owed to a particular state, may not relieve the unitholder from the obligation to file an income tax return in that state. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

Ownership of Common Units by Tax-Exempt Organizations and Certain Other Investors

          An investment in common units by tax-exempt organizations (including IRAs and other retirement plans) and foreign persons raises issues unique to such persons. Virtually all of our income allocated to a unitholder that is a tax-exempt organization is unrelated business taxable income and, thus, is taxable to such a unitholder. A unitholder who is a nonresident alien, non-U.S. corporation or other non-U.S. person is regarded as being engaged in a trade or business in the United States as a result of ownership of a common unit and, thus, is required to file federal income tax returns and to pay tax on the unitholder’s share of our taxable income. Finally, distributions to foreign unitholders are subject to federal income tax withholding at the highest applicable rate.

Available Information

          We make available, free of charge on our Internet website (http://www.pnglp.com), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission.

Item 1A. Risk Factors

Risks Related to Our Business

We may not have sufficient cash following the establishment of reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common units and Series A subordinated units.

          We may not have sufficient available cash from distributable cash flow each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

	•		the rates we charge for storage services and the amount of natural gas storage services our customers purchase from us;
	•		the overall balance between the supply of and demand for natural gas, on a seasonal and long-term basis, which impacts the

			level of demand for the natural gas storage services we provide and the rates we are able to charge for such services;
	•		regulatory action affecting the rates we can charge for the services we provide, the demand for natural gas, the supply of natural gas, how we contract for services, our existing contracts, our operating and capital costs and our operating flexibility;
	•		the creditworthiness of our customers;
	•		the level of competition from other providers of natural gas storage services;
	•		the level of our operating and maintenance and general and administrative costs; and
	•		prevailing economic conditions.

          In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

	•		the level of capital expenditures we make;
	•		the cost of acquisitions;
	•		our debt service requirements and other liabilities;
	•		fluctuations in our working capital needs;
	•		our ability to borrow funds and access capital markets;
	•		restrictions contained in debt agreements to which we are a party; and
	•		the amount of cash reserves established by our general partner.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.”

The amount of cash we have available for distribution to holders of our common units and Series A subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

          The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Increased competition from other companies that provide natural gas storage services or services that can substitute for storage services could have a negative impact on the demand for our services, which could adversely affect our financial results.

          We compete primarily with other providers of natural gas storage services that own or operate salt-dome, depleted reservoir and/or converted aquifer gas storage facilities. Such competitors include independent storage developers and operators, local distribution companies, utilities, interstate and intrastate gas transmission companies with storage facilities connected to their pipelines and midstream energy companies. FERC has adopted policies that favor the development of new storage projects and there are numerous projects, including expansions of existing facilities and greenfield construction projects, at various stages of development in the markets where we operate. According to FERC data, since 2000, permits have been issued by the FERC for new interstate gas storage facilities or expansions in the Gulf Coast (excluding intrastate facilities and FERC pre-filings for additional storage capacity) representing aggregate additional working gas capacity of approximately 671 Bcf. These projects, if developed

and placed into service, may compete with our storage operations. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, flexibility and reliability of service.

          We also compete with certain pipelines, marketers and LNG facilities that provide services that can substitute for certain of the storage services we offer. In addition, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage services.

          All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business. This could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas storage in our markets, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

Our natural gas storage operations are subject to regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

          Our natural gas storage operations are subject to federal, state and local laws and regulations administered by a number of authorities. Because we store natural gas that is transported in interstate commerce, our natural gas storage facilities are subject to comprehensive regulation by the FERC under the NGA. Federal regulation under the NGA extends to a wide array of matters, including rates, terms of service, types of service, expansions and other matters.

          The NGA requires that tariff rates for our interstate gas storage facilities be “just and reasonable.” In addition, under the NGA and applicable FERC regulations, we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to rates or terms and conditions of service.

          The rates and terms and conditions for interstate services provided by our facilities are set forth in a FERC-approved tariff for each facility which in each case currently permits us to charge market-based rates. Market-based rate authority allows us to negotiate rates with individual customers based on market demand. This right to charge market-based rates may be challenged by a party filing a complaint with FERC. Our market-based rate authorization may also be re-examined if we add substantial new storage capacity through expansion or acquisition and as a result obtain market power. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing storage services.

          Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for certain violations of up to $1,000,000 per day for each violation. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005. See Items 1 and 2. “Business and Properties — Regulation.”

          Finally, new rules, regulations or laws may be passed or implemented that impose additional costs, burdens or restrictions on us. We cannot give any assurance regarding the likelihood of such future rules, regulations or laws or the effect they could have on our business, financial condition, results of operations or ability to make distributions to our unitholders.

Our authorizations to charge “market-based rates” are subject to the continued existence of certain conditions related to the competitive position of our facilities in their respective markets and, if those conditions change, the right to charge “market-based rates” could be terminated.

          The rates we charge for storage services are regulated by FERC pursuant to its “market-based rate” policy, which allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Our authorization to charge “market-based rates” is based on determinations by FERC that the facilities have no “market power” in their respective markets. The determination that storage facilities lack market power is subject to review and revision by FERC if there is a change in circumstances that could affect the ability of additional storage or interconnected pipeline facilities to exercise market power. Among the sorts of changes in circumstances that could raise market power concerns would be

an expansion of capacity, acquisitions, or other changes in market dynamics. If the FERC were to conclude that a facility may have acquired and cannot mitigate market power, its rates could become subject to cost-of-service regulation.

          If a facility’s rates become subject to cost-of-service regulation, the maximum rates that may be charged for storage services would be established through FERC’s ratemaking process, and the facility would no longer be able to charge a rate demanded by the market. Generally, cost-of-service based rates for interstate natural gas services are based on the cost of providing service including recovery of, and a reasonable return on, the entity’s actual prudent historical cost investment for providing jurisdictional service. Key determinants in the ratemaking process are costs of providing service, allowed rate of return, and billing determinants, which are based upon storage volumes and contractual capacity commitment assumptions. Rate design and the allocation of costs underlying cost-of-service based rates must also be approved by FERC as part of each rate case. The resolution of these key determinants, particularly the allowed rate of return and billing determinants that would underlie the cost-of-service based rates through the FERC’s ratemaking process, could adversely impact our profitability, and have adverse consequences on our cash flow and our ability to make distributions. Additionally, changes in generally applicable FERC ratemaking policies could also affect us.

Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our business.

          Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline.

          In addition to volatility and seasonality, an extended period of high gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated expansion activities. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business and financial results.

We may not be able to maintain or replace expiring storage contracts.

          Our primary exposure to market risk occurs at the time our existing storage contracts expire and are subject to renegotiation and renewal and as we bring on additional working capacity that is uncontracted. As of December 31, 2010, the weighted average remaining tenor of our existing portfolio of firm storage contracts is approximately 3.0 years at Pine Prairie, approximately 2.1 years at Bluewater and approximately 5.5 years at Southern Pines. For the year ended December 31, 2010, Iberdrola Renewables, Inc., Guardian Pipeline, LLC and Anadarko Energy Services accounted for approximately 13%, 9% and 8% of our revenues, respectively. The extension or replacement of existing contracts depends on a number of factors beyond our control.

          The failure to extend or replace a significant portion of our existing contracts, the extension or replacement of such contracts at unfavorable or lower rates, or the failure to enter into favorable contracts with respect to incremental working capacity, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

Our storage business depends on third-party pipelines connected to our storage facilities, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such pipelines.

          We depend on the continued operation of third-party pipelines and other facilities that provide delivery options to and from our storage facilities. Because we do not own the pipelines that are interconnected to our facilities, their continued operation is not within our control. If any of the pipelines to which we are connected were to become unavailable for current or future withdrawals or injections of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and satisfy our customer’s needs could be compromised, thereby potentially reducing our revenues. Any temporary or permanent interruption at any key pipeline or other interconnect point with our gas storage facilities that caused a material reduction in the volume of storage services provided by us could have a material adverse effect on our business, financial condition, results of operation and ability to make distributions.

          In addition, the rates charged by pipelines interconnected with our storage facilities for transportation to and from our facilities affects the utilization and value of the storage services we provide. Significant changes in the rates charged by these pipelines or their competitors could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

We may not be able to achieve our current expansion plans at our facilities on economically viable terms.

          Our current permitted expansion plans include the addition of 21 Bcf of working gas storage capacity at our Pine Prairie facility, 18 Bcf of which we expect to place into service in stages through mid-2012. In addition, in October of 2010, we submitted an application with the FERC requesting approval to construct 32 Bcf of additional capacity at Pine Prairie, an expansion application that will, if approved, increase Pine Prairie’s permitted working gas capacity from 48 to 80 Bcf. We also plan to expand the working gas storage capacity of the Southern Pines facility to its permitted level of 40 Bcf. See Items 1 and 2. “Business and Properties — Recent Developments — Acquisition of SG Resources Mississippi, LLC.” In connection with these expansion efforts, we may encounter difficulties in the drilling required to access subsurface storage caverns, the drilling of raw water wells or salt water disposal wells and the completion of the wells. These risks include the following:

	•		unexpected operational events;
	•		adverse weather conditions;
	•		facility or equipment malfunctions or breakdowns;
	•		unusual or unexpected geological formations;
	•		drill bit or drill pipe difficulties;
	•		collapses of wellbore, casing or other tubulars or other loss of drilling hole;
	•		unexpected problems associated with filling the caverns with base gas and conducting pressure and mechanical integrity tests;
	•		unexpected problems associated with leaching the caverns, filtration of extracted water and offsite disposal of water; and
	•		risks associated with subcontractors’ services, supplies, cost escalation and personnel.

          Specifically, the creation of a salt-cavern storage facility requires sourcing, injecting, withdrawing and disposing of significant volume of water. For example, to create 10 Bcf of working capacity, a salt cavern requires approximately 72 million barrels of raw water supply and an equivalent volume of salt water disposal. Additionally, the rate of access to raw water and the rate of disposal of salt water have a direct impact on the time it takes to create a salt cavern. Any physical or regulatory restriction imposed on our current operations with respect to accessing raw water or disposing of salt water would have an adverse impact on our ability to timely and fully expand our facilities at Pine Prairie or Southern Pines. Additionally, the occurrence of uninsured or under-insured losses, delays or operating cost overruns associated with these drilling efforts could have a negative impact on our operations and financial results.

We may not be able to increase the capacity of our Pine Prairie or Southern Pines facilities beyond our current expansion plans.

          We have both the property rights and operational capacity necessary to expand both our Pine Prairie facility and our Southern Pines facility beyond their respective currently permitted capacities of 48 Bcf and 40 Bcf, respectively. As indicated above, in October of 2010, we submitted an application with the FERC requesting approval to construct 32 Bcf of additional capacity at Pine Prairie, an expansion application that will, if approved, increase Pine Prairie’s permitted working gas capacity from 48 to 80 Bcf. In addition, we believe Pine Prairie can be expanded to a potential of over 150 Bcf of total working gas storage capacity. Albeit to a lesser degree, we also have expansion capabilities beyond 40 Bcf at Southern Pines. See Items 1 and 2. “Business and Properties — Recent Developments.” We may not be able to secure the financing or permits necessary to pursue such expansion and the necessary infrastructure modifications that would be needed to accommodate such expansion. Additionally, such expansion will be subject to market demand, the successful execution of any expansion projects and the availability of sufficient third-party

interstate and intrastate pipelines receipt and deliverability capacity to accommodate the increased capacity. Any combination of these factors may prevent us from expanding our Pine Prairie or Southern Pines facilities beyond their current permitted capacity.

We are exposed to the credit risk of our customers in the ordinary course of our business.

          As a normal part of our business we extend credit to our customers. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. Although we have established credit policies that include assessing the creditworthiness of our customers and requiring appropriate terms or credit support from them based on the results of such assessments, there can be no assurance that we have adequately assessed the creditworthiness of our existing or future customers or that there will not be unanticipated deterioration in their creditworthiness. Resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operation and ability to make distributions.

          Additionally, in instances where we loan natural gas to third parties, the magnitude of our credit risk is significantly increased, as the failure of the third party to return the loaned volumes would result in losses equal to the full value of the loaned natural gas rather than, in the case of firm storage or hub services contracts, losses equal to fees on volumes nominated for injection or withdrawal.

For various operating and commercial reasons, we may not be able to perform all of our obligations under our contracts, which could lead to increased costs and negatively impact our financial results.

          Various operational and commercial factors could result in an inability on our part to satisfy our contractual commitments and obligations. For example, in connection with our provision of firm storage services and hub services to our customers, we enter into contracts that obligate us to honor our customers’ requests to inject gas into our storage facilities, withdraw gas from our facilities and wheel gas through our facilities, in each case subject to volume, timing and other limitations set forth in such contracts. The following factors could adversely impact our ability to perform our obligations under these contracts:

	•		a failure on the part of our storage facilities to perform as we expect them to, whether due to malfunction of equipment or facilities or realization of other operational risks;
	•		a failure on our part to create incremental storage capacity at our facilities due to reduced leaching rates, operational or other factors;
	•		the operating pressure of our storage facilities (affected in varying degree, depending on the type of storage cavern, by total volume of working and base gas, and temperature);
	•		a variety of commercial decisions we make from time to time in connection with the management and operation of our storage facilities. Examples include, without limitation, decisions with respect to matters such as (i) the aggregate amount of commitments we are willing to make with respect to wheeling, injection, and withdrawal services, which could exceed our capabilities at any given time for various reasons, (ii) the timing of scheduled and unplanned maintenance or repairs, which can impact equipment availability and capacity, (iii) the schedule for and rate at which we conduct leaching activities at our facilities in connection with the creation of new salt caverns or the expansion of existing caverns, which can impact the amount of storage capacity we have available to satisfy our customers’ requests, (iv) the timing and aggregate volume of any base gas park and/or loan transactions we consummate, which can directly affect the operating pressure of our storage facilities and (v) the amount of compression capacity and other gas handling equipment that we install at our facilities to support gas wheeling, injection and withdrawal activities; and
	•		adverse operating conditions due to hurricanes, extreme weather events or conditions, and operational problems or issues with third party pipelines, storage or production facilities.

          Although we manage and monitor all of these various factors in connection with the ongoing operation of our natural gas storage facilities with the goal of performing all of our contractual commitments and obligations and optimizing our revenue, one or more of the above factors may adversely impact our ability to satisfy our injection, withdrawal or wheeling obligations under our

storage contracts. In such event, we may be liable to our customers for losses or damages they suffer and/or we may need to incur costs or expenses in order to permit us to satisfy our obligations and avoid a breach or increase our costs in doing so.

Our marketing activities could result in financial losses.

          Without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year firm storage contracts, during 2010 we formed a dedicated commercial marketing group in order to capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Through these transactions, we will seek to maintain a position that is substantially balanced between purchases on the one hand and sales or future delivery obligations on the other hand. Our general policy is (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes. While we intend to conduct these transactions within these pre-defined risk parameters, these policies will not eliminate all risks. For example, any event that disrupts our anticipated physical supply of or market for natural gas could expose us to significant costs or expenses in order to enable us to satisfy our obligations to store or deliver contracted natural gas volumes.

We are subject to environmental laws and regulations that may expose us to significant costs and liabilities.

          Our natural gas storage operations are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities, increases in operating expenses or curtailment of certain operations to limit or prevent releases of materials from our facilities, the incurrence of capital expenditures associated with the installation of pollution control equipment, and the imposition of substantial liabilities for pollution resulting from our operations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the costs of any remediation of environmental contamination that may become necessary, and these costs could be material. For example, the adoption and implementation of any climate change legislation or regulations imposing reporting obligations with respect to, or limiting emissions of, “greenhouse gases” could result in increased operating costs and adversely affect demand for natural gas.

          Numerous governmental authorities, such as the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. In addition, joint and several liability or strict liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover all or any of these costs through insurance or other means, which may have a material adverse effect on our business, financial condition, results of operation and ability to make distributions. See Items 1 and 2. “Business and Properties — Regulation” for more information.

If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.

          A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated from operations on a per unit basis (i.e., are accretive). We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:

	•		we are unable to identify attractive expansion projects or acquisition candidates that satisfy our economic and other criteria, or we are outbid for such opportunities by our competitors;
	•		we are unable to raise financing for such expansion projects or acquisitions on economically acceptable terms;

	•		we are unable to secure adequate customer commitments to use the facilities to be expanded or acquired; or
	•		we are unable to obtain governmental approvals or other rights, licenses or consents needed to complete such expansion projects or acquisitions.

Acquisitions or expansion projects that we complete may not perform as anticipated and could result in a reduction of our distributable cash flow on a per unit basis.

          Even if we complete expansion projects or acquisitions that we believe will be accretive, such projects or acquisitions may nevertheless reduce our available cash from distributable cash flow on a per unit basis due to the following factors:

	•		mistaken assumptions about storage capacity, deliverability, base gas needs, geological integrity, revenues, synergies, costs (including operating and general and administrative, capital, debt and equity costs), customer demand, growth potential, assumed liabilities and other factors;
	•		an inability to complete expansion projects on schedule and within applicable budgets due to various factors, including cost overruns, schedule delays, and the inability to obtain necessary permits or approvals;
	•		the failure to receive cash flows from an expansion project or newly acquired asset due to delays in the commencement of operations for any reason;
	•		unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or expansion project was completed;
	•		the inability to attract new customers or retain acquired customers to the extent assumed in connection with the expansion or acquisition project;
	•		the failure to successfully integrate expansion projects or acquired assets or businesses into our operations and/or the loss of key employees; or
	•		the impact of regulatory, environmental, political and legal uncertainties that are beyond our control.

          If we consummate any future expansion projects or acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources. If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per common unit and Series A subordinated unit, our ability to make distributions may be reduced.

Our natural gas storage facilities are new and have limited operating history. The facilities may not be able to deliver as anticipated, which could prevent us from meeting our contractual obligations and cause us to incur significant costs.

          Although we believe that our operating gas storage facilities have been designed to meet our contractual obligations with respect to wheeling, injection, withdrawal and gas specifications, the facilities are relatively new and have a limited operating history. If we fail to wheel, inject or withdraw natural gas at contracted rates, or cannot deliver natural gas consistent with contractual quality specifications, we could incur significant costs to satisfy our contractual obligations. These costs could have an adverse impact on our business, financial condition, results of operations and ability to make distributions.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.

          Our operations are subject to all of the risks and hazards inherent in the natural gas storage business, including:

•

reduction of our available storage capacity at our salt caverns over time due to (i) unexpected increases in the temperature of our caverns, which reduces capacity as a result of the expansion of the stored natural gas, (ii) the long-term effect of

			pressure differentials between the caverns and the surrounding salt formations (known as “salt creep”) or (iii) problems with the structural integrity of our salt caverns;
	•		subsidence of the geological structures where we store natural gas;
	•		risks and hazards inherent in drilling operations associated with the development of new caverns and/or the drilling of raw water wells or salt water disposal wells;
	•		problems maintaining the wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our storage facilities;
	•		impacts to our operations due to the unavailability of raw water for any reason or the inability to dispose of salt water through our salt water disposal wells for any reason;
	•		damage to our storage facilities, related equipment and connecting pipelines and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
	•		inadvertent damage from third parties, including construction, farm and utility equipment;
	•		leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
	•		collapse of storage caverns;
	•		operator error;
	•		environmental pollution or other environmental issues, including drinking water contamination, associated with our raw water or water disposal wells or our water treatment facilities;
	•		damage associated with equipment or material failures, pipeline or vessel ruptures or corrosion, explosions, fires and other incidents; and
	•		other hazards that could result in personal injury and loss of life, pollution and suspension of operations.

          These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. In addition, we are not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

          In addition, we share insurance coverage with PAA, for which we reimburse PAA’s general partner pursuant to the terms of the omnibus agreement. To the extent PAA experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.

If leakage or migration of natural gas or other hydrocarbons occurs from any of our storage facilities, our operations and financial results could be adversely affected.

          Our operations are subject to the risk that natural gas or other hydrocarbons could leak or migrate from our storage facilities, causing a loss of volumes stored in the storage facilities. This risk could cause substantial losses due to our inability to deliver the

stored volumes back to our customers. Furthermore, we may not be able to obtain insurance to protect against this risk, and we may not be able to maintain insurance of the type and amount we desire at reasonable rates to insure against this risk.

Restrictions in our credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our units.

Our credit agreement restricts our ability to, among other things:

	•		make distributions of available cash to unitholders if any default or event of default (as defined in the credit agreement) exists or would result therefrom;
	•		incur additional indebtedness;
	•		grant or permit to exist liens or enter into certain restricted contracts;
	•		engage in transactions with affiliates;
	•		make any material change to the nature of our business;
	•		make a disposition of all or substantially all of our assets; or
	•		enter into a merger, consolidate, liquidate, wind up or dissolve.

          Furthermore, our credit facility contains covenants requiring us to maintain certain financial ratios related to our consolidated EBITDA, consolidated interest charges and consolidated funded indebtedness, as such terms are defined in our credit agreement.

          The provisions of our credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facility could result in an event of default, which could enable our lenders, subject to the terms and conditions of the credit facility, to declare any outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of any such debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

          Our future level of debt could have important consequences to us, including the following:

	•		our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
	•		our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
	•		we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
	•		our flexibility in responding to changing business and economic conditions may be limited.

          Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

          For more information regarding our debt agreements, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

We are considered a subsidiary of PAA under its debt instruments and, as such, we may be directly or indirectly subject to and impacted by certain restrictions in PAA’s existing and future credit facilities and indentures. These restrictions may limit our access to credit, prevent us from engaging in beneficial activities, and in certain circumstances, require us to guarantee PAA’s indebtedness.

          Although we are not contractually bound by and are not liable for PAA’s debt under its debt instruments, we are subject to and indirectly affected by certain prohibitions and limitations contained therein. Such restrictions may prevent us from obtaining the most advantageous financing terms or from engaging in certain transactions that might otherwise be considered beneficial. For example (by reference to the most restrictive of any applicable covenant):

	•		We will be restricted from entering into any future sale/leaseback transactions.
	•		PAA is subject to a limit of 10% of PAA’s consolidated net tangible assets with respect to the amount of debt that can be secured by liens on facilities owned by its subsidiaries, including us. We cannot control the incurrence of secured debt by PAA’s other subsidiaries.
	•		We cannot give intercompany guaranties of debt for borrowed money for the benefit of PAA or any subsidiary of PAA (including any of our subsidiaries) unless we agree to guarantee PAA’s outstanding debt. The same restriction would apply to a guaranty of our debt by one of our subsidiaries.

          Although we believe that the restrictions in PAA’s debt instruments will not have a material impact on our operations or access to credit, no assurance can be given to that effect, and PAA’s ability to comply with any restrictions in PAA’s debt instruments may be affected by events beyond our control.

          Any debt instruments that PAA or any of its affiliates enters into in the future, including any amendments to existing credit facilities, may include additional or more restrictive limitations on our ability to conduct our business. These additional restrictions could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities. In addition, PAA has the ability to prevent us from taking actions that would cause PAA to violate any covenants in its credit facilities or indentures, or otherwise to be in default under any of its debt instruments. In deciding whether to prevent us from taking any such action, PAA will have no fiduciary duty to us or our unitholders.

The credit and risk profile of our general partner and its owner, PAA, could adversely affect our credit and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

          The credit and business risk profiles of our general partner and PAA may be factors considered in credit evaluations of us. This is because our general partner, which is owned by PAA, controls our business activities, including our cash distribution policy and expansion strategy. Any adverse change in the financial condition of PAA, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, may adversely affect our credit and risk profile.

          If we were to seek a credit rating in the future, the credit rating may be adversely affected by the leverage of our general partner or PAA, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of PAA and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

          Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and our implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for

investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.

An impairment of goodwill could reduce our earnings.

          At December 31, 2010, we had $25 million of goodwill. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the acquired tangible and separately measurable intangible net assets. U.S. generally accepted accounting principles, or GAAP, requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. If we were to determine that any of our goodwill was impaired, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.

Risks Inherent in an Investment in Us

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

          Pursuant to our partnership agreement, we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

          In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Cost reimbursements due to PAA’s general partner and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by PAA’s general partner.

          Prior to making distributions on our common units, we will reimburse PAA’s general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by PAA, its general partner or our general partner in managing and operating us. These operating expense reimbursements and the reimbursement of incremental general and administrative expenses we incur are not capped. In addition, PAA and our general partner will have substantial discretion in incurring third-party expenses on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to PAA’s general partner and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

          Our general partner has the right, at any time when there are no Series A subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and each target distribution level will be reset to the correspondingly higher amount that causes such reset target distribution level to exceed the reset minimum quarterly distribution by the same percentage that such distribution level exceeds the then-current minimum quarterly distribution.

          If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and will retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

          Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.

          Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

          Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.

          In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Holders of our common units have limited voting rights and are not entitled to elect the directors of our general partner.

          Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect the directors of our general partner. The board of directors of our general partner will be chosen by PAA. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot remove our general partner without its consent.

          The unitholders will be unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. PAA owns an aggregate of approximately 62% of our outstanding limited partner units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining Series A subordinated units and Series B subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our then-existing common units by prematurely eliminating their distribution and liquidation preference over our Series A subordinated units and Series B subordinated units, which would otherwise have continued until we had met certain distribution, performance and operational tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all Series A subordinated units and Series B subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

          Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

          Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of PAA to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner may then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

We may issue additional units without our unitholders’ approval, which would dilute our unitholders’ existing ownership interest.

          Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

	•		our existing unitholders’ proportionate ownership interest in us will decrease;
	•		the amount of cash available for distribution on each unit may decrease;
	•		because a lower percentage of total outstanding units will be Series A subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	•		the ratio of taxable income to distributions may increase;
	•		the relative voting strength of each previously outstanding unit may be diminished; and
	•		the market price of the common units may decline.

PAA may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

           As of February 28, 2011, PAA holds 28,272,870 common units, 11,934,351 Series A subordinated units and 13,500,000 Series B subordinated units. All of the Series A subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. The Series B subordinated units are also eligible for conversion into common units if certain operational and financial conditions are satisfied and the end of the subordination period has occurred. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. A sale or transfer, including certain deemed transfers, by PAA of all or portions of its interests in us may cause our partnership to terminate for federal income tax purposes. For a discussion of the impact this could have on common unitholders, see Items 1A. “Risk Factors — Tax Risks to Common Unitholders — The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.”

Risks Related to Conflicts of Interest

PAA owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. PAA and our general partner have conflicts of interest and may favor PAA’s interests to a unitholder’s detriment.

          PAA owns and controls our general partner, as well as appoints all of the officers and directors of our general partner, and some of the officers of our general partner are also officers of PAA’s general partner (and one such officer is also a member of the board of directors of PAA’s general partner). Although our general partner has a legal duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a legal duty to manage our general partner in a manner that is beneficial to its owner, PAA. Conflicts of interest may arise between PAA and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of PAA over our interests and the interests of our unitholders.

PAA may engage in competition with us.

          Although PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business, PAA and its affiliates are not limited in their ability to compete with us.

Our partnership agreement defines and modifies the duties of our general partner and restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner.

          Our partnership agreement contains provisions that define the standard of care that our general partner must exercise and restrict the remedies available to unitholders for actions taken by our general partner in accordance with that standard of care, including in circumstances that might otherwise be challenged under state law standards. For example, our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include:

	(a)		how to allocate corporate opportunities among us and our general partner’s affiliates;
	(b)		whether to exercise its limited call right;
	(c)		how to exercise its voting rights with respect to the units it owns;
	(d)		whether to exercise its registration rights;
	(e)		whether to elect to reset target distribution levels; and

(f)

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

	•		provides that whenever our general partner makes a determination, including any determination with respect to distributable cash flow or any components thereof, or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
	•		provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it subjectively believed that the decision was (i) with respect to matters involving us, in, or not opposed to, the best interests of our partnership and (ii) with respect to matters involving the relative rights and privileges of holders of our equity interests, consistent with the intent of the provisions of our partnership agreement;
	•		provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal;
	•		generally provides that any resolution or course of action adopted by our general partner and its affiliates in respect of a conflict of interest will be permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement or any duty stated or implied by law or equity if the resolution or course of action in respect of such conflict of interest is:

(a)

approved by the conflicts committee of our general partner after due inquiry, based on a subjective belief that the course of action or determination that is the subject of such approval is fair and reasonable to us;

(b)

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates, directors and executive officers;

(c)

determined by our general partner (after due inquiry) to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d)

approved by our general partner (after due inquiry) based on a subjective belief that the course of action or determination that is the subject of such approval is fair and reasonable to us, which may include taking into account the totality of the circumstances and relationships involved (our short-term or long-term interests and other arrangements or relationships that could be considered favorable or advantageous to us); and

•

provides that, to the fullest extent permitted by law, in connection with any action or inaction of, or determination made by, our general partner’s board of directors or its conflicts committee with respect to any matter relating to us, it shall be presumed that our general partner’s board of directors or its conflicts committee acted in a manner that satisfied the contractual standards set forth in our partnership agreement, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or our partnership challenging any such action or inaction of, or determination made by, our general partner, the person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption.

Our general partner intends to limit its liability regarding our obligations.

          Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we

could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

          If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

          The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we are treated as a partnership rather than a corporation for such purposes; however, a change in our business could cause us to be treated as a corporation for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or the IRS, on this or any other tax matter affecting us.

          In addition, a change in current law may cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Specifically, we will be subject to an entity-level tax on any portion of our income that is generated in Texas in the prior year. Imposition of any such additional taxes on us will reduce the cash available for distribution to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, our target distribution amounts will be adjusted to reflect the impact of that law on us.

          If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to them. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

          Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of (i) publicly traded partnerships or (ii) an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

          The present U.S. federal income tax treatment of (i) publicly traded partnerships, including us, or (ii) an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied

retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. Although the considered legislation would not appear to have affected our treatment as a partnership, we are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

          Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

          We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. PAA owns more than 50% of the total interests in our capital and profits interests. Therefore, a transfer by PAA of all or a portion of its interests in us, including a deemed transfer as a result of a termination of PAA’s partnership for federal income tax purposes, could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Tax gain or loss on the disposition of our common units could be more or less than expected.

          If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price the unitholder receives is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

          Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution or debt service.

          The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution or debt service.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

          To maintain the uniformity of the economic and tax characteristics of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

          When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

          A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

          We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

          Because there is no tax concept of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller

and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where our unitholders do not live as a result of investing in our common units.

          In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in the states of Louisiana, Michigan and Mississippi. Each of these states currently imposes a personal income tax and also imposes income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is a unitholder’s responsibility to file all U.S. federal, foreign, state and local tax returns.

Item 1B. Unresolved Staff Comments

          None.

Item 3. Legal Proceedings

          We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are also a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business, none of which we believe to be material. See Items 1 and 2. “Business and Properties — Regulation — Natural Gas Storage Regulation.”

Item 4. (Removed and Reserved)

PART II

Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

          Our common units are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “PNG.” As of February 28, 2011, the closing market price for our common units was $24.37 per unit and there were approximately 7,247 record holders and beneficial owners (held in street name). As of February 28, 2011, there were 59,184,450 common units outstanding.

          The following table sets forth high and low sales prices for our common units and the cash distributions declared per common unit for the periods indicated:

		Common Unit Price Range								Cash
2010		High				Low				Distributions (1)
4th Quarter		$	25.75			$	22.61			$	0.3450
3rd Quarter		$	26.65			$	22.61			$	0.3375
2nd Quarter (2) (3)		$	26.00			$	22.25			$	0.2114
1st Quarter (3)		$	—			$	—			$	—

          Our common units are used as a form of compensation to our directors and our employees. Additional information regarding our equity compensation plans is included in Part III of this report under Item 13. “Certain Relationships and Related Transactions, and Director Independence.”

Cash Distribution Policy

          We will distribute all of our available cash to our unitholders, of record on the applicable record date, within 45 days following the end of each quarter in the manner described below. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:

	•		provide for the proper conduct of our business;
	•		comply with applicable law or any partnership debt instrument or other agreement; or
	•		provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.

          We distribute all of our available cash each quarter in the following manner:

	•		first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.3375, plus any arrearages from prior quarters; and
	•		second, 98.0% to the holders of Series A subordinated units and 2.0% to our general partner, until each Series A subordinated unit has received the minimum quarterly distribution of $0.3375.

          If cash distributions to our unitholders exceed $0.3375 per common unit and Series A subordinated unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, incentive distributions in increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount as follows:

						Marginal Percentage
		Total Quarterly Distributions				Interest in Distributions
		per Common Unit and								General
		Series A Subordinated Unit				Unitholders				Partner
Minimum quarterly distribution			$0.3375				98.0	%			2.0	%
First target distribution		above $0.3375 up to $0.37125					85.0	%			15.0	%
Second target distribution		above $0.37125 up to $0.50625					75.0	%			25.0	%
Thereafter		above $0.50625					50.0	%			50.0	%

          Our general partner has the right, at any time when there are no Series A subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election.

          The following table details the distributions subsequent to our initial public offering (in millions, except per unit amounts):

				Distributions Paid
								Series A																Distributions
				Common				Subordinated				General Partner												per limited
Date Declared		Date Paid or To Be Paid		Units				Units				Incentive				2%				Total				partner unit
January 12, 2011		February 14, 2011 (1)		$	10.9			$	4.1			$	0.1			$	0.3			$	15.4			$	0.3450
October 12, 2010		November 12, 2010		$	10.7			$	4.0			$	—			$	0.3			$	15.0			$	0.3375
July 13, 2010		August 13, 2010 (2)		$	6.7			$	2.9			$	—			$	0.2			$	9.8			$	0.2114

          We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to distribute available cash as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including our partnership agreement, our credit facility or other debt agreements and applicable partnership law. Under the terms of the agreements governing our debt, we are prohibited from declaring or making any distribution to unitholders if a default or event of default (as defined in such agreements) exists. No such default has occurred. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

          See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

Issuer Purchases of Equity Securities

          We did not repurchase any of our common units during the fourth quarter of fiscal 2010, and we do not have any announced or existing plans to repurchase any of our common units.

Item 6. Selected Financial Data

		Predecessor																	Successor				Pro Forma (1)				Successor
														January 1,					September 3,
														2009					2009
		Year Ended				Year Ended				Year Ended				through					through				Year Ended				Year Ended
		December 31,				December 31,				December 31,				September 2,					December 31,				December 31,				December 31,
		2006				2007				2008				2009					2009				2009				2010
		(in thousands, except for per unit data and monthly operating metrics)
Statement of operations data:
Total revenues		$	30,831			$	36,945			$	49,177			$	46,929				$	25,251			$	72,180			$	100,287
Storage related costs			100				3,847				8,934				8,792					7,003				15,795				23,465
Operating costs (except those shown below)			3,658				3,947				4,059				4,820					3,257				8,077				7,242
Fuel expense			613				1,140				2,320				1,816					578				2,394				2,368
General and administrative expenses			3,402				3,755				3,874				3,562					4,083				8,885				15,965
Depreciation, depletion and amortization			3,986				4,520				6,245				8,054					3,578				11,341				14,119
Total costs and expenses			11,759				17,209				25,432				27,044					18,499				46,492				63,159
Operating income			19,072				19,736				23,745				19,885					6,752				25,688				37,128
Interest expense			(8,389	)			(7,108	)			(4,941	)			(4,352	)				(4,262	)			(11,676	)			(7,323	)
Interest income and other income (expense), net			2,030				5,378				1,669				458					(2	)			456				(18	)
Income tax expense			—				—				(887	)			(473	)				—				(473	)			—
Net income		$	12,713			$	18,006			$	19,586			$	15,518				$	2,488			$	13,995			$	29,787
Calculation of Limited Partner Interest in
Net Income: (2)
Net income			n/a				n/a				n/a				n/a					n/a				n/a			$	24,359
Less general partner interest in net income			n/a				n/a				n/a				n/a					n/a				n/a				537
Limited partner interest in net income			n/a				n/a				n/a				n/a					n/a				n/a			$	23,822
Per unit data:
Basic net income per limited partner unit(2)			n/a				n/a				n/a				n/a					n/a				n/a			$	0.54
Diluted net income per limited partner unit(2)			n/a				n/a				n/a				n/a					n/a				n/a			$	0.54
Declared distribution per limited partner unit(3)			n/a				n/a				n/a				n/a					n/a				n/a			$	0.345
Balance sheet data (at end of period):
Total assets		$	518,092			$	674,765			$	811,436								$	900,407							$	998,728
Long-term debt		$	227,300			$	352,713			$	415,263								$	450,523							$	259,900
Total debt		$	227,300			$	355,163			$	417,713								$	450,523							$	259,900
Members’/partners’ capital		$	264,109			$	294,717			$	363,229								$	432,744							$	723,390
Other financial data:
Adjusted EBITDA(4)		$	27,395			$	29,663			$	31,001			$	28,701				$	12,165	(5)		$	39,626			$	53,857
Distributable cash flow(4)		$	19,006			$	22,156			$	25,577			$	23,965				$	7,200			$	26,863			$	44,962
Maintenance capital expenditures		$	—			$	—			$	377			$	384				$	320			$	704			$	438
Net cash provided by (used in) operating activities		$	13,973			$	22,343			$	21,818			$	22,603				$	15,265							$	44,361
Net cash provided by (used in) investing activities		$	(206,612	)		$	(177,280	)		$	(118,890	)		$	(58,561	)			$	(9,656	)						$	(103,580	)
Net cash provided by (used in) financing activities		$	158,771			$	145,743			$	122,344			$	23,636				$	(22,813	)						$	56,441
Operating data:
Net revenue margin(6)		$	30,731			$	33,098			$	40,243			$	38,137				$	18,248			$	56,385			$	76,822
Other operating expenses / G&A / Other			(3,336	)			(3,435	)			(9,242	)			(9,436	)				(6,083	)			(16,759	)			(22,965	)
Adjusted EBITDA		$	27,395			$	29,663			$	31,001			$	28,701				$	12,165			$	39,626			$	53,857
Average working storage capacity (Bcf)(7)			24				26				27				36					40				38				47
Monthly Operating Metrics ($/Mcf)
Net revenue margin		$	0.11			$	0.11			$	0.12			$	0.13				$	0.11			$	0.12			$	0.14
Operating expenses / G&A / Other			(0.01	)			(0.01	)			(0.03	)			(0.03	)				(0.03	)			(0.03	)			(0.04	)
Adjusted EBITDA		$	0.10			$	0.10			$	0.09			$	0.10				$	0.08			$	0.09			$	0.10

Non-GAAP and Segment Financial Measures

          To supplement our financial information presented in accordance with GAAP, management uses Adjusted EBITDA and distributable cash flow in its evaluation of past performance and prospects for the future. Management believes that the presentation of such additional financial measures provides useful information to investors regarding our financial condition and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operations and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. Adjusted EBITDA and/or distributable cash flow may exclude, for example, the impact of unique and infrequent items, items outside of management’s control and/or items that are not indicative of our core operating results and business outlook, which we have defined hereinafter as “selected items impacting comparability.” These additional financial measures are reconciled to net income, the most directly comparable measures as reported in accordance within GAAP, in the following table and should be viewed in addition to, and not in lieu of, our consolidated financial statements and footnotes.

          We define Adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, unrealized gains and losses from derivative activities and applicable “selected items impacting comparability.”

          Distributable cash flow, as determined by our general partner, is defined as: (i) net income; plus or minus, as applicable, (ii) any amounts necessary to offset the impact of any items included in net income that do not impact the amount of available cash; plus (iii) any acquisition-related expenses deducted from net income and associated with (a) successful acquisitions or (b) any other potential acquisitions that have not been abandoned; minus (iv) any acquisition related expenses covered by clause (iii)(b) immediately preceding that relate to (a) potential acquisitions that have since been abandoned or (b) potential acquisitions that have not been consummated within one year following the date such expense was incurred (except that if the potential acquisition is the subject of a pending purchase and sale agreement as of such one-year date, such one-year period of time shall be extended until the first to occur of the termination of such purchase and sale agreement or the first day following the closing of the acquisition contemplated by such purchase and sale agreement); and minus (v) maintenance capital expenditures. The types of items covered by clause (ii) above include (a) depreciation, depletion and amortization expense, (b) any gain or loss from the sale of assets not in the ordinary course of business, (c) any gain or loss as a result of a change in accounting principle, (d) any non-cash gains or items of income and any non-cash losses or expenses, including asset impairments, amortization of debt discounts, premiums or issue costs,

mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities and (e) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received. Distributable cash flow does not reflect actual cash on hand that is available for distribution to our unitholders.

          The following table reconciles Non-GAAP and segment financial measures to the most directly comparable measures as reported in accordance with GAAP (in thousands):

		Predecessor																	Successor				Pro Forma (1)				Successor
		Year Ended				Year Ended				Year Ended				January 1 —					September 3 —				Year Ended				Year Ended
		December				December				December				September 2,					December 31,				December				December
		31, 2006				31, 2007				31, 2008				2009					2009				31, 2009				31, 2010
														(in thousands)
Adjusted EBITDA reconciliation
Net income		$	12,713			$	18,006			$	19,586			$	15,518				$	2,488			$	13,995			$	29,787
Income tax expense			—				—				887				473					—				473				—
Interest expense, net of amounts capitalized			8,389				7,108				4,941				4,352					4,262				11,676				7,323
Depreciation, depletion and amortization			3,986				4,520				6,245				8,054					3,578				11,341				14,119
Selected items impacting Adjusted EBITDA
Equity compensation expense			515				553				(110	)			304					1,467				1,771				2,747
Acquisition related costs			—				—				—				—					—				—				251
Mark-to-market on open derivative positions			1,792				(524	)			(548	)			—					370				370				(370	)
Adjusted EBITDA		$	27,395			$	29,663			$	31,001			$	28,701				$	12,165			$	39,626			$	53,857
Distributable cash flow reconciliation
Net income		$	12,713			$	18,006			$	19,586			$	15,518				$	2,488			$	13,995			$	29,787
Depreciation, depletion and amortization			3,986				4,520				6,245				8,054					3,578				11,341				14,119
Income tax expense			—				—				887				473					—				473				—
Acquisition related costs			—				—				—				—					—				—				251
Maintenance capital expenditures			—				—				(377	)			(384	)				(320	)			(704	)			(438	)
Other non cash items:
Net, non cash equity compensation			515				154				(216	)			304					1,084				1,388				1,613
Mark-to-market on open derivative positions			1,792				(524	)			(548	)			—					370				370				(370	)
Distributable cash flow		$	19,006			$	22,156			$	25,577			$	23,965				$	7,200			$	26,863			$	44,962

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

          The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations, including periods prior to our initial public offering on May 5, 2010. Such analysis should be read in conjunction with the historical audited consolidated financial statements, and accompanying notes. For ease of reference, we refer to the historical financial results of PAA Natural Gas Storage, LLC (“PNGS”) prior to our initial public offering as being “our” historical financial results. Unless the context otherwise requires, references to “we,” “us,” “our,” and “the Partnership” are intended to mean the business and operations of PAA Natural Gas Storage, L.P. (the “Partnership” or “PNG”) and its consolidated subsidiaries since May 5, 2010. When used in the historical context (i.e. prior to May 5, 2010), these terms are intended to mean the business and operations of PNGS. Unless the context indicates otherwise, for purposes of the following discussion “PAA” refers to Plains All

American Pipeline, L.P. (the owner of our general partner) (NYSE: PAA) and its consolidated subsidiaries and affiliates other than the Partnership and its general partner and their respective subsidiaries.

          For periods prior to our initial public offering, the historical condensed consolidated financial statements are those of PNGS, our predecessor. Through the contribution of all of the equity interest of PNGS to us in connection with the closing of our initial public offering on May 5, 2010, all of the assets, liabilities and operations of PNGS were contributed directly or indirectly by PAA to the Partnership. For further discussion regarding the Partnership’s initial public offering, please see Notes 1 and 5 to our consolidated financial statements.

          As further discussed in Note 1 to our consolidated financial statements, PNGS became a wholly owned subsidiary of PAA on September 3, 2009 when PAA acquired an additional 50.0% interest in PNGS from Vulcan Capital (the “PAA Ownership Transaction”). Application of push-down accounting from PAA to PNGS resulted in a change in carrying value for certain assets and liabilities of PNGS.

          Our discussion and analysis includes the following:

•

Executive Summary

	•		Company Overview
	•		Overview of Operating Results, Capital Spending and Significant Activities

	•		Critical Accounting Policies and Estimates
	•		Recent Accounting Pronouncements
	•		Results of Operations
	•		Outlook
	•		Liquidity and Capital Resources

Executive Summary

Company Overview

          We are a fee-based, growth-oriented Delaware limited partnership formed by Plains All American in January 2010 to own, operate and grow the natural gas storage business that PAA acquired in 2005 and has continuously operated since that time. In conjunction with our initial public offering in May 2010, PAA contributed the equity interest in the entities that owned its natural gas storage business to us. Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. As of December 31, 2010, we owned and operated two natural gas storage facilities located in Louisiana and Michigan that have an aggregate working gas storage capacity of 50 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. In February 2011, we acquired the Southern Pines facility. See Items 1 and 2. “Business and Properties — Recent Developments — Acquisition of SG Resources Mississippi, L.L.C.” for further discussion of our February 2011 acquisition of the Southern Pines facility.

          As of December 31, 2010, our operating assets included the Pine Prairie facility, which is a recently constructed, high-deliverability salt-cavern natural gas storage complex located in Evangeline Parish, Louisiana and the Bluewater facility, which is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. Pine Prairie has a total current working gas storage capacity of 24 Bcf in three salt caverns and Bluewater has total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs.

Overview of Operating Results, Capital Spending and Significant Activities

          Adjusted EBITDA for the year ended December 31, 2010 was approximately $53.9 million, a 36% increase over Adjusted EBITDA of approximately $39.6 million for the year ended December 31, 2009 on a pro forma basis. This increase was primarily the result of continued expansion of our Pine Prairie facility, including placing our third cavern into service during the second quarter of 2010 which provided an additional 10 Bcf of working gas capacity. See “— Results of Operations” for further discussion and analysis of our operating results. Expansion capital expenditures for 2010 were approximately $86.0 million. Such expenditures were principally associated with the ongoing development of our Pine Prairie facility.

          In May 2010, the Partnership completed its initial public offering, issuing approximately 13.5 million common units to the public for net proceeds of approximately $268.2 million. Distributions declared for the period from the date of our initial public offering through December 31, 2010 were $0.8939 per distribution eligible limited partner unit.

          In October 2010, we filed with FERC for expansion of our Pine Prairie facility. The filing contemplates construction of an additional 32 Bcf of working gas storage capacity, including two new 12 Bcf caverns and the expansion of existing permitted capacity by eight Bcf. Receipt of FERC approval of the proposed expansions would increase Pine Prairie’s permitted capacity from 48 Bcf to 80 Bcf.

          In February 2011, we completed the acquisition of SG Resources Mississippi, LLC (“SG Resources”) from SGR Holdings, L.L.C. for consideration of approximately $746 million, which is subject to finalization of working capital and capital expenditure adjustments as defined in the purchase and sale agreement for this transaction. The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”), a FERC-regulated, salt-cavern natural gas storage facility located in Greene County, Mississippi. Southern Pines is permitted for 40 Bcf of working gas capacity from four storage caverns. See Items 1 and 2. “Business and Properties — Recent Developments — Acquisition of SG Resources Mississippi, L.L.C.”

Critical Accounting Policies and Estimates

Critical Accounting Policies

          We have adopted various accounting policies to prepare our consolidated financial statements in accordance with GAAP. These critical accounting policies are discussed in Note 2 to our consolidated financial statements.

Critical Accounting Estimates

          The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. The critical accounting estimates that we have identified are discussed below.

          Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In accordance with FASB guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimated provision will be recognized. This provision will be adjusted as if the amount was recognized when the combination occurred if material. We also expense the transaction costs as incurred in connection with each acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Intangible assets with finite lives are amortized over their estimated useful lives as determined by management. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment.

          Impairment testing entails estimating future net cash flows relating to the asset, based on management’s estimate of market conditions including pricing, demand, competition, operating costs and other factors. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, and industry expertise involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third-party assessments. Uncertainties associated with these estimates include assumptions regarding natural gas supply and demand, volatility and pricing of natural gas, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary

significantly from estimated amounts. We perform our goodwill impairment test annually (as of June 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable.

          We did not have any goodwill impairments in 2010, 2009 or 2008.

          Property, Plant and Equipment and Depreciation Expense. We compute depreciation using the straight-line method based on estimated useful lives. We periodically evaluate the estimated useful lives of our property, plant and equipment and revised our estimates in September 2009. See Note 2 to our consolidated financial statements.

          We also evaluate our property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:

	•		whether there is an indication of impairment;
	•		the grouping of assets;
	•		the intention of “holding” versus “selling” an asset;
	•		the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
	•		if an impairment exists, the fair value of the asset or asset group.

          We did not have any asset impairments in 2010, 2009 or 2008.

          Accruals and Contingent Liabilities. We record accruals or liabilities including, but not limited to, insurance claims, asset retirement obligations, taxes and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Such accruals may include estimates and are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory requirements for operating gas storage facilities, costs of medical care associated with worker’s compensation and employee health insurance claims, and the possibility of legal claims. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. Presently, there are no material accruals in these areas. Although the resolution of uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

          Equity Compensation Plan Accruals. We accrue compensation expense for outstanding equity compensation awards granted under our Long Term Incentive Plan and similar plans sponsored by PAA. Under generally accepted accounting principles, we are required to estimate the fair value of our outstanding equity awards and recognize that fair value as compensation expense over the service period. For awards that contain a performance condition, the fair value of the award is recognized as compensation expense only if the attainment of the performance condition is considered probable. See Note 10 to our consolidated financial statements for further discussion of our equity compensation plans.

          Mark-to-Market Accrual. In situations where we are required to mark-to-market derivatives pursuant to FASB guidance, the estimates of derivative gains or losses at a particular period are unrealized and will most likely not reflect the realized derivative gain or loss upon settlement of the derivative. We reflect estimates of current valuations for these items based on our internal records and information from third parties. For any derivatives that are not exchange traded, the estimates we derive are based on indicative broker quotations that are further validated with market observable inputs. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Recent Accounting Pronouncements

          For a discussion of recent accounting pronouncements that will impact us, see Note 2 to our consolidated financial statements.

Results of Operations

PAA Ownership Transaction and Basis of Presentation

          The tables below summarize our results of operations for the periods indicated. Due to the change in accounting basis that occurred as a result of the PAA Ownership Transaction, combining results of operations for 2009 periods prior to and subsequent to the PAA Ownership Transaction for purposes of comparison to 2010 or 2008 results, without making appropriate adjustments, may not necessarily facilitate a meaningful analysis and would be inconsistent with relevant accounting and financial reporting authoritative guidance applicable to similar circumstances. As a result, we have elected to present pro forma results of operations for the year ended December 31, 2009 which have been prepared as if the PAA Ownership Transaction had occurred on January 1, 2009.

          The pro forma information is based on assumptions that we believe are reasonable under the circumstances and are intended for illustrative purposes only. While not necessarily indicative of the results of the actual or future operations that would have been achieved had the PAA Ownership Transaction occurred on January 1, 2009, we believe this information provides a more meaningful basis of comparison for purposes of discussion of current period results as information is presented on a comparable accounting basis for complete fiscal periods. Pro forma adjustments reflected in the pro forma results for year ended December 31, 2009 impacted general and administrative expenses, interest expense and depreciation, depletion and amortization. Revenues and expense categories, other than those previously noted, were not materially impacted by the change in basis and amounts on a pro forma basis for the 2009 period are the summation of activity for the applicable 2009 historical periods prior to and subsequent from the PAA Ownership Transactions. Further discussion of the nature of the pro forma adjustments made is included as a part of this analysis. No pro forma adjustments were made attributable to the Partnership’s May 2010 initial public offering.

          The following table includes our operating results for these periods (dollar amounts in thousands, except per Mcf amounts). Information designated as “Predecessor” and “Successor” relate to the accounting periods preceding and succeeding the PAA Ownership Transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of our consolidated financial statements to highlight the fact that the financial information for such periods has been prepared under a different basis of accounting.

		Successor				Pro Forma				Successor					Predecessor								Favorable/(Unfavorable) Variance
										September					January 1,
		Year				Year				3, 2009					2009				Year
		Ended				Ended				through					through				Ended				2010 — Pro								Pro forma 2009
		December				December				December					September				December				Forma 2009								— 2008
		31, 2010				31, 2009				31, 2009					2, 2009				31, 2008				$				%				$				%
		(in thousands, except monthly operating metrics)
Revenues
Firm Storage Services
Reservation fees		$	85,651			$	62,535			$	22,919				$	39,616			$	37,674			$	23,116				37	%		$	24,861				63	%
Cycling fees and fuel-in-kind			5,314				4,086				1,053					3,033				5,197				1,228				30	%			(1,111	)			-37	%
Hub Services			6,190				4,625				1,637					2,988				1,417				1,565				34	%			3,208				107	%
Other			3,132				934				(358	)				1,292				4,889				2,198				235	%			(3 ,955	)			-306	%
Total revenue			100,287				72,180				25,251					46,929				49,177				28,107				39	%			23,003				49	%
Storage related costs			(23,465	)			(15,795	)			(7,003	)				(8,792	)			(8,934	)			(7,670	)			-4 9	%			(6 ,86 1	)			-78	%
Other operating costs (except those shown below)			(7,242	)			(8,077	)			(3,257	)				(4,820	)			(4,059	)			835				10	%			(4 ,018	)			-83	%
Fuel expense			(2,368	)			(2,394	)			(578	)				(1,816	)			(2,320	)			26				1	%			(74	)			-4	%
General and administrative expenses			(15,965	)			(8,885	)			(4,083	)				(3,562	)			(3,874	)			(7,080	)			-80	%			(5,011	)			-141	%
Interest income and other income (expense), net			(18	)			456				(2	)				458				1,669				(474	)			-104	%			(1,213	)			-265	%
Equity compensation expense			2,747				1,771				1,467					304				(110	)
Acquisition related costs			251				—				—					—				—
Mark-to-market of open derivative positions			(370	)			370				370					—				(548	)
Adjusted EBITDA		$	53,857			$	39,626			$	12,165				$	28,701			$	31,001			$	14,231				36	%		$	8,625				30	%
Reconciliation to net income
Adjusted EBITDA		$	53,857			$	39,626			$	12,165				$	28,701			$	31,001			$	14,231				36	%		$	8,625				30	%
Depreciation, depletion and amortization			(14,119	)			(11,341	)			(3,578	)				(8,054	)			(6,245	)			(2,778	)			-24	%			(5,096	)			-63	%
Interest expense, net of capitalized interest			(7,323	)			(11,676	)			(4,262	)				(4,352	)			(4,941	)			4,353				37	%			(6 ,735	)			-155	%
Income tax expense			—				(473	)			—					(473	)			(887	)			473				100	%			414				88	%
Equity compensation expense			(2,747	)			(1,771	)			(1,467	)				(304	)			110
Acquisition related costs			(251	)			—				—					—				—
Mark-to-market of open derivative positions			370				(370	)			(370	)				—				548
Net income		$	29,787			$	13,995			$	2,488				$	15,518			$	19,586			$	15,792				113	%		$	(5,591	)			-36	%
Operating Data:
Net revenue margin (1)		$	76,822			$	56,385			$	18,248				$	38,137			$	40,243			$	20,437				36	%		$	16,142				42	%
Other operating expenses/G&A/Other			(22,965	)			(16,759	)			(6,083	)				(9,436	)			(9,242	)			(6,206	)			-37	%			(7,517	)			-80	%
Adjusted EBITDA		$	53,857			$	39,626			$	12,165				$	28,701			$	31,001			$	14,231				36	%		$	8,625				30	%
Average working storage capacity(Bcf)			47.0				38.0				40.0					36.0				27.0				9.0				24	%			11.0				31	%
Monthly Operating Metrics($/Mcf)
Net Revenue Margin		$	0.14			$	0.12			$	0.11				$	0.13			$	0.12			$	0.02				17	%		$	—				—	%
Operating expenses / G&A / Other			(0.04	)			(0.03	)			(0.03	)				(0.03	)			(0.03	)			(0.01	)			33	%			—				—	%
Adjusted EBITDA		$	0.10			$	0.09			$	0.08				$	0.10			$	0.09			$	0.01				11	%		$	—				—	%