UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of
The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported)— February 8, 2012

PAA Natural Gas Storage, L.P.

(Exact name of registrant as specified in its charter)

333 Clay Street, Suite 1500, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o            Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o            Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o            Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 9.01.          Financial Statements and Exhibits

(d) Exhibit 99.1 — Press Release dated February 8, 2012.

Item 2.02 and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure

PAA Natural Gas Storage, L.P. (the “Partnership”) today issued a press release reporting its fourth quarter and annual 2011 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01, we are providing first quarter and full year 2012 detailed guidance for financial performance.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

First Quarter and Full Year 2012 Guidance

Adjusted EBITDA (as defined below in Note 1 to the “Operating and Financial Guidance” table) is a financial measure used by our chief operating decision maker to evaluate our performance. In Note 9 below, we reconcile Adjusted EBITDA to net income for the 2012 guidance periods presented. We encourage you to visit our website at www.pnglp.com (in particular the section entitled “Non-GAAP Reconciliations”), which presents a historical reconciliation of Adjusted EBITDA and certain commonly used non-GAAP financial measures. We present Adjusted EBITDA because it is a measure used by management to evaluate performance and because we believe it provides additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We believe that Adjusted EBITDA is used to assess our operating performance compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis. In addition, as part of our presentation of Adjusted EBITDA, we have highlighted the impact of certain selected items that impact comparability between periods and affect EBITDA, Net Income, and Net Income per Basic and Diluted Limited Partner Unit. For the guidance period presented, selected items include only equity compensation expense.

The following guidance for the three-month period ending March 31, 2012 and the twelve-month period ending December 31, 2012 includes assumptions and estimates that we believe are reasonable given our assessment of historical trends (modified for changes in market conditions), business cycles and other reasonably available information. Projections contemplate inter-period changes in future performance resulting from a variety of factors we believe to be relevant, including new expansion projects, changes in our portfolio of storage and services contracts, the seasonal and dynamic nature of our business, and other market and competitive factors influencing the demand for storage services. Our projections reflect the assumption the derivative instruments utilized are fully effective in hedging applicable risks in accordance with our risk management procedures.  We do not believe that there is an accurate way to forecast any ineffectiveness in hedging relationships or unrealized gains or losses required to be recognized in net income without the offsetting impact of physical transactions for a period associated with derivative activity. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so we can provide no assurance that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of February 7, 2012. We undertake no obligation to publicly update or revise any forward-looking statements.

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PAA Natural Gas Storage, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

(1)          Amounts may not recalculate due to rounding.

(2)          Our outstanding limited partner interests as of December 31, 2011 consisted of 59.2 million common units, 11.9 million Series A subordinated units and 13.5 million Series B subordinated units.  Series B subordinated units are not entitled to cash distributions unless and until they convert to Series A subordinated units or common units, which conversion is contingent on our meeting both certain distribution levels and certain in-service operational requirements at our Pine Prairie facility. As a result, the Series B subordinated units are not included in the calculation of basic or diluted net income per unit amounts.

(3)          We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate periods distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.

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Notes and Significant Assumptions:

1.                Definitions.

2.               Business Overview. Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. We provide natural gas storage services to a broad mix of customers, including local gas distribution companies (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 own and operate three natural gas storage facilities located in Louisiana, Mississippi and Michigan.  From time to time, we also lease storage capacity and pipeline transportation capacity from third parties in order to increase our operational flexibility and enhance the services we offer our customers. Acquisitions are expected to constitute an important element of our growth strategy; however, the accompanying detailed financial guidance does not include any forecasts for acquisitions, but does include certain costs we expect to incur associated with evaluating acquisitions.

We generate revenue primarily from the provision of fee-based gas storage services to our customers, and we categorize the majority of the revenue we generate as being derived from “Firm Storage Services” or “Hub Services and Merchant Storage”.  We also generate a portion of our net revenues from other sources as described below in “Other revenues.”

·                  Net Revenue from Firm Storage Services. The majority of our net revenue from firm storage services is derived from contracts with initial terms that generally range from one year to 10 years in length and pursuant to which customers receive the assured or “firm” right to store gas in our facilities. 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. Firm storage services revenue also include cycling fees based on the volume of natural gas nominated for injection and/or withdrawal as well as a small portion of natural gas nominated for injection that we retain as compensation for our fuel use.  Certain components of our firm storage services revenue, such as cycling fees and fuel compensation, are dependent on the injection and withdrawal activities of our individual customers, both from a timing and volume perspective. Timing differences between forecasted activity and actual activity may result in a shifting of revenues between individual quarterly periods within a given storage season. Throughput differences may result in our ultimate realization of revenues being different from our forecasted amounts.

Firm storage services revenues are shown net of storage related costs.  Storage related costs consist of fees incurred to lease third-party storage and pipeline capacity and fuel expense we incur at our facilities associated with managing injection and deliverability capacity and certain other costs we may incur.

For calendar year 2012, an average of approximately 90% of our average owned and leased storage capacity is contracted under firm storage contracts with third parties.  Our full year revenue guidance for firm storage services includes the fixed capacity reservation fees, and an assumed amount of cycling fees and net fuel consumption, that we will earn under such contracts, plus our estimate of revenues to be generated for currently uncontracted storage capacity under future contracts for firm storage services, if any.  Projected net revenues from our existing storage contracts with third parties account for over 85% of our total net revenue guidance for the year.

·                  Net Revenue from Hub Services and Merchant Storage. Our guidance for net revenue from Hub Services and Merchant Storage includes revenues generated from the provision of hub services at our facilities and net revenue generated by our commercial marketing group, which captures short term market opportunities by utilizing a portion of our owned and leased storage capacity and engaging in related commercial marketing activities.  Our capacity to provide hub services is primarily dependent on our outstanding obligations to customers under firm storage services contracts. As a result,

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increases in our firm storage services obligations may limit our ability to provide hub services and vice versa. 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) “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. A portion of our revenues related to these activities may include fuel collections.

Net revenue from merchant storage consists of revenue generated through the hedged purchase and sale of natural gas net of any storage related costs incurred.  Our full year guidance for 2012 is based in part on assumptions regarding expected margin to be achieved on approximately 10% of our average owned and leased storage capacity. We utilize both physical storage from our uncontracted space and derivatives to hedge our expected margin from these activities; however, such activities may not generate the forecasted level of net revenues or, even if achieved, may not result in ratable realizations throughout the year.  For calendar year 2012, our projected net revenue from merchant storage activities is less than 5% of our total net revenue guidance.

Revenues from hub services and merchant storage are influenced by weather, operating disruptions, domestic producers’ completion activities, foreign import activities and other conditions that result in temporary disruptions in supply and demand. Additionally, our wheeling and balancing activities are also influenced by certain market conditions such as location price differentials and other competing sources of transportation capacity. Accordingly, providing guidance on the overall amount and timing of revenue from these activities is less precise than guidance associated with net revenues from firm storage services and thus we have provided for a wider range of potential performance on a relative basis during any given guidance period. Our overall net revenue guidance for hub services and merchant storage is based on assumptions and estimates for an annual period that we believe are reasonable given our assessment of historical trends (modified for changes in market conditions) and other reasonably available information.

In addition, our guidance for net revenue from hub services and merchant storage is shown net of storage related costs.  These costs consist of fees incurred to lease third-party pipeline capacity and storage and transaction costs associated with managing injection and deliverability capacity at our facilities. Costs associated with our leased pipeline capacity are subject to variation as the terms of these agreements typically contain certain fees which fluctuate based on actual volumes shipped in addition to monthly reservation fees.  Also included in our storage related costs is fuel expense we incur as part of our short term activities.

·                  Other Revenues. Our guidance for other revenues includes certain fixed access fees at Pine Prairie and revenues we generate through the sale of crude oil and liquids produced in conjunction with the operation of our Bluewater facility, net of royalties and taxes. Due to injection and withdrawal cycles and related reservoir pressure considerations, we anticipate crude oil and liquids production will occur disproportionately in the first quarter of each year, a lesser amount in the second quarter and the balance over the third and fourth quarters of each year. Revenues from sales of crude oil and liquids are also impacted by changes in market prices.  Our revenue guidance for these activities reflects our estimates of likely production and our estimate of a net realizable price at the time of sale. Additionally, we periodically sell any fuel-in-kind volumes in excess of actual volumes needed as fuel to operate facilities and reflect any gain or loss on such sales as a part of other revenues.

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The following table summarizes our Adjusted EBITDA guidance for the forecasted periods, average owned working natural gas storage capacities and operating metrics.

(1)  Excluding selected items impacting comparability,

(2)  Mid-point of guidance.

Our primary expense components related to gas storage services comprise operating costs and general and administrative expense.

·                  Field Operating Costs (excluding fuel). Our operating costs typically do not materially vary based on the amount of natural gas we store. The timing of certain expenditures during a year generally fluctuates with customers’ demands, which change depending on market conditions and whether we are in the injection or withdrawal season for natural gas.

·                  General and Administrative Expense / Other Income (Expense). For guidance purposes, we anticipate we will routinely incur annual third party acquisition expenses. In accordance with Section 805 of the FASB’s Accounting Standards Codification, effective in 2009, we are required to expense costs related to acquisition evaluations as incurred, regardless of the success of such acquisition efforts. Accordingly, from time to time we may incur general and administrative expenses related to our acquisition efforts in excess of such guidance amounts. To the extent considered meaningful, such excess amounts will be classified as a selected item impacting comparability and thus excluded from Adjusted EBITDA, as such costs do not impact the operations of our existing assets and may benefit future periods.

3.              Depreciation, Depletion and Amortization. We forecast depreciation, depletion and amortization based on our existing assets, unamortized deferred debt costs, forecasted capital expenditures and projected in-service dates.

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4.              Capital Expenditures. Excluding any potential acquisitions, we forecast capital expenditures (net of estimated insurance and certain reimbursements) during calendar 2012 to be approximately $58 million for expansion projects (including capitalized interest) with an additional $0.6 million for maintenance capital projects.  Following is a breakdown by facility of our forecasted expansion capital expenditures for the year ending December 31, 2012:

(1)          Potential variation to current facility capital cost estimates may result from changes to project design, final cost of materials and labor and timing of incurrence of costs due to uncontrollable factors such as regulatory approvals and weather.

5.               Capital Structure. This guidance is based on our capital structure as of December 31, 2011.

6.               Interest Expense, net. Debt balances are projected based on estimated (i) operating cash flows, (ii) capital expenditures for expansion / maintenance projects and base gas purchases, (iii) working capital sources and uses and (iv) distribution payments. Interest rate assumptions for variable rate debt are based on the current forward LIBOR curve. Also included in interest expense are interest rate swap accruals, commitment fees. Interest expense is net of amounts capitalized for expansion capital projects.

7.               Reconciliation of Net Income to DCF. The following table reconciles the mid-point of Net Income to distributable cash flow for the three-month period ending March 31, 2012 and for the twelve-month period ending December 31, 2012.

8.               Equity Compensation Plans. As a result of the modification of certain of our equity compensation awards in February 2012, the majority of our outstanding equity compensation awards contain vesting criteria that are based either on (i) the date upon which a specified PNG distribution level is attained, or (ii) the conversion of our Series A subordinated units. For the majority of our outstanding equity compensation awards as of February 7, 2012, specified annualized PNG distribution vesting thresholds range from $1.35 to $1.55 and require continued service through achievement of such performance thresholds. The majority of these awards are classified as equity awards for accounting purposes and thus the compensation expense recognized over the service period is based on the fair value of the awards on the grant date and is generally not subject to re-measurement prior to vesting. Upon vesting, our equity classified awards will result in the issuance of PNG common units.

During September 2010, certain officers of PAA were granted approximately 375,000 Transaction Grants denominated in PNG common units, Series A subordinated units, and Series B Subordinated units.  The awards will vest upon the completion of the service period and certain performance conditions and will be settled with outstanding common or Series A subordinated units of

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PNG currently owned by PAA.  Although PNG does not bear the economic burden of these awards, since the services these officers provide benefit PNG, we are required to reflect the expense associated with these awards in our financial statements.  Our forecasts for the three months ending March 31, 2012 and the twelve months ending December 31, 2012 reflect expense of approximately $0.4 million and $1.2 million, respectively, associated with these awards.

We have determined that an annualized distribution of $1.45 and the conversion of our Series A subordinated units are probable of occurring in the foreseeable future.  Therefore, for awards that vest upon these assumptions, our guidance includes compensation expense accruals over the service period of the respective awards.  The actual amount of equity compensation expense for any given period can vary as a result of future changes to our probability assessments relative to the performance conditions required for vesting and as a result of changes to our outstanding awards, such as granting additional awards or forfeitures.

9.               Reconciliation of Net Income to Adjusted EBITDA. The following table reconciles net income to Adjusted EBITDA for the three-month period ending March 31, 2012 and the twelve-month period ending December 31, 2012.

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Forward-Looking Statements and Associated Risks

All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements identified by 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 results anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

·                                          significantly reduced volatility and/or lower spreads in natural gas markets for an extended period of time;

·                                          factors affecting demand for natural gas storage services and the rates we are able to charge for such services, including the balance between the supply of and demand for natural gas;

·                                          our ability to maintain or replace expiring storage contracts, or enter into new storage contracts, in either case at attractive rates and on otherwise favorable terms;

·                                          factors affecting our ability to realize revenues from hub services and merchant storage transactions involving uncontracted or unutilized capacity at our facilities;

·                                          the effects of competition;

·                                          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;

·                                          the effectiveness of our risk management activities;

·                                          geologic or other factors that affect the timing or amount of crude oil and other liquid hydrocarbons that we are able to produce in conjunction with the operation of our Bluewater facility;

·                                          market or other factors that affect the prices we are able to realize for crude oil and other liquid hydrocarbons produced in conjunction with the operation of our Bluewater facility;

·                                          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;

·                                          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

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trading companies with which we do business;

·                                          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.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

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