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 9, 2011

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 9, 2011.

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 2010 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 updated detailed guidance for financial performance for the first quarter of calendar 2011 and for the full year.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under this 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.

Disclosure of First Quarter and Full Year 2011 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 segment performance. In Note 9 below, we reconcile Adjusted EBITDA to net income for the 2011 guidance periods presented. We encourage you to visit our website at www.pnglp.com (in particular the section entitled “Non-GAAP Reconciliation”), 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, we have highlighted the impact of our selected items impacting comparability, including expenses associated with equity compensation expense, the insurance deductible on the incident at Bluewater (see Note 2) and SG Resources acquisition related costs as such items affect EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

The following guidance for the three-month period ending March 31, 2011 and twelve-month period ending December 31, 2011 includes the impact of the timing of repairs to the damage sustained to certain treating equipment at our Bluewater facility on January 12, 2011, as well as other 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 covering multi-quarter periods 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 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 8, 2011. We undertake no obligation to publicly update or revise any forward-looking statements.

On December 28, 2010, PAA Natural Gas Storage entered into a definitive agreement to acquire SG Resources Mississippi, LLC, (“SG Resources”).  The primary asset of SG Resources is the Southern Pines Energy Center (“Southern Pines”), which is a FERC-regulated, high-performance, salt-cavern natural gas storage facility. The following guidance includes the impact of the Southern Pines acquisition, which closed on February 9, 2011 for a total consideration of approximately $750 million.

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PAA Natural Gas Storage, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

(1)             Includes the effect of the SG Resources acquisition (see note 5).  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.

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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. Effective with the SG Resources acquisition on February 9, 2011 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. On a system-wide basis, natural gas is typically injected into storage between April and October when producers’ wellhead production and natural gas imports exceed end-user demand and is typically withdrawn during the winter months of November through March to supplement producers’ wellhead production and natural gas imports, which in the aggregate are typically not sufficient to meet end-user demand. Acquisitions are expected to constitute an important element of our growth strategy; however, except for the SG Resources acquisition as previously mentioned, the accompanying detailed financial guidance does not include any forecasts for acquisitions.

We generate revenue almost exclusively from fee-based gas storage services to our customers, which include both “firm storage services” and “hub services.” We also generate a relatively small portion of our revenues from other sources as described below in “other revenues.”

·                  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. Firm storage services 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 (see “fuel expense” below). For the twelve-month period ending December 31, 2011, approximately 90% of our storage capacity is contracted, with 100% contracted in the first quarter and approximately 85% contracted for the balance of the year. Our revenue guidance for firm storage services is based primarily on the service fees provided for under such existing contracts, the service fees provided for under any existing seasonal park and loan contracts, and our estimate of revenues to be generated for un-contracted storage capacity under new contracts for firm storage services, if any. Our full year revenue guidance assumes that we will be able to realize the equivalent level of revenue for any uncontracted space that is managed by our commercial optimization group.  However, even if such activities realize the equivalent level of revenue for the full year, such activities may not result in ratable realizations throughout the balance of the year.  Additional components of our firm storage services revenue, such as cycling fees and fuel compensation, are dependent on the injection and withdrawal actions 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. A meaningful portion of revenues associated with fuel collections are offset by fuel related expenses (see discussion of “Fuel expense”).

Hub Services. We also generate revenue from the provision of “hub services” at our facilities. Our capacity to provide hub services is primarily dependent on our outstanding obligations to customers under firm storage services contracts. As a result, increases in our firm storage services obligations may result in certain limitations in 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) 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. A portion of revenues related to these activities may include fuel collections which are offset by fuel related expenses (see discussion of “Fuel expense” below). Such activities are generally short-term in nature and the timing is influenced by weather, operating disruptions, 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 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 revenue guidance for hub services 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.

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·                  Other Revenues. We also generate revenues 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. Our accompanying detailed guidance for financial performance for the three-month period ending March 31, 2011 and twelve-month period ending December 31, 2011 does not include forecasts with respect to potential gains or losses on derivative financial instruments as we do not believe that there is an accurate way to forecast such activity. 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.

·                  Bluewater Incident. Certain equipment was damaged at the gas handling portion of the Bluewater facility on January 12, 2011.  While the cause of the incident remains under review and the assessment of impact on operations is ongoing, 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 one of the two offsite storage reservoirs at Bluewater before it is injected into pipelines for transportation. Accordingly, we do not believe the damage will have a significant or extended impact on injection operations at Bluewater and, with certain exceptions, the operational impact of the incident on Bluewater’s primary gas storage activities should be largely confined to the first quarter of 2011.  Reconstruction of the damaged portion of the gas handling facilities, which are generally utilized on a limited basis during the summer months, will extend beyond the first quarter and the facility’s liquids removal volumes will be negatively affected beyond the first quarter.  Our guidance includes the financial impact of the incident, including lost revenues, repairs and incidental expenses (but excluding incremental market opportunities), net of insurance, of approximately $4.6 million.  Approximately $2.8 million of estimated lost revenue is associated with reduced volumes of crude oil and liquids production during the 12 month period ending December 31, 2011.

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.

(3)  SG Resources acquisition effective February 9, 2011.

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Net Revenue Margin is total revenues less storage related costs. Storage related costs consist of fees incurred to lease third-party storage and pipeline capacity 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. Our revenues generated through the use of leased assets, which are typically limited to a margin, are not significant to our results of operations when compared to activities generated from the assets which we own.  Additionally, we enter into loans of our base gas to provide us greater flexibility in providing firm storage services and hub services. Costs incurred to enter into seasonal loan agreements are reflected as a component of storage related costs in our detailed guidance. Storage related costs are subject to fluctuation based on both the amount and timing of loan agreements we enter into and certain timing differences may occur between the recognition of costs associated with these loans and the corresponding firm storage services or hub services revenues generated from the operational flexibility provided by these loans.

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

·                  Fuel expense. Natural gas is the primary fuel for our compressors, which are used to inject natural gas into our storage facilities and to boost the pressures for certain pipeline deliveries or transfers. Fuel-related expense may fluctuate materially from period to period due to variations in both the volume and value of natural gas consumed in our operations, with volumes being driven primarily by the volumes of natural gas injected into or wheeled through our facilities. During an annual cycle, we generally collect sufficient quantities of fuel from our customers through our cycling collections and hub services activities to offset the amount of fuel we consume (see revenue descriptions above), therefore our fuel expense is principally offset by fuel related revenue on an annual basis. However, the fuel consumed and collected may not be equivalent on a quarterly basis. Fuel expense is also impacted by our ability to maximize the efficiency of our operation of our facilities. We measure our fuel consumption using meters located at our central facilities. We charge fuel expense for the estimated volume consumed based on the weighted average price of fuel collected. Actual fuel revenue generated and consumed will vary with customer activity and may be influenced by weather and other factors.

·                  Operating Costs. Excluding fuel-related expenses, 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. Fluctuations in operating costs may occur due to the timing of planned maintenance activities as well as fluctuations in the level of project development and acquisition activity during a given period of time. Regulatory compliance can also impact our maintenance programs and affect the timing and amount of our expenditures.

·                  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.  For the three-month period ending March 31, 2011 and twelve-month period ending December 31, 2011, our forecast includes $4.2 million and $4.5 million, respectively, of SG Resources acquisition related costs.

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

4.               Capital Expenditures. Excluding any potential acquisitions which we may commit to after the date hereof, we forecast capital expenditures during calendar 2011 to be approximately $103 million for expansion projects (including capitalized interest) with an additional $0.8 million for maintenance capital projects as follows:

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5.               Capital Structure. This guidance is based on our capital structure as of December 31, 2010 adjusted for the SG Resources acquisition effective February 9, 2011, which was funded with a $200 million unsecured loan from PAA and the private placement of $600 million of equity to PAA and third parties.

6.               Interest Expense, net. Debt balances, including a three-year, 5.25% $200 million unsecured term loan with PAA related to the SG Resources acquisition, are projected based on estimated (i) operating cash flows, (ii) capital expenditures for maintenance / expansion projects and base gas purchases, (iii) working capital sources and uses and (iv) estimated distribution payments. Interest rate assumptions for variable rate debt are based on the current forward LIBOR curve. Included in interest expense are commitment fees and other financing costs. Interest expense is net of amounts capitalized for major expansion capital projects.

7.               Net Income per Limited Partner Unit. We are required to prepare our earnings per unit computations in accordance with requirements contained in generally accepted accounting principles specific to master limited partnerships. Our outstanding limited partner interests as of December 31, 2010 consisted of approximately 31.6 million common units, approximately 11.9 million Series A subordinated units and 13.5 million Series B subordinated units.  The weighted average units used in Guidance include the effect of a private placement of 27.6 million common units to complete the acquisition of SG Resources.  Basic net income per limited partner unit is calculated by dividing net income allocated to each class of limited partner interest by the basic weighted average units outstanding for such limited partner interest during the period.

(1)    Our general partner owns our incentive distribution rights which entitle our general partner to receive, in addition to its 2.0% general partner interest, increasing percentages of the cash we distribute in excess of our minimum quarterly distribution.

(2)    Includes the impact of a private placement of 27.6 million common units on February 8, 2011. 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.

8.               Equity Compensation Plans. The majority of our outstanding equity compensation awards contain vesting criteria that are based either on (i) the later to occur of a specified date, or the date upon which a specified PNG distribution level is attained, or (ii) the conversion of our Series A and Series B subordinated units. For the majority of our outstanding equity compensation awards as of December 31, 2010, estimated vesting dates range from May 2011 to May 2015 and annualized PNG distribution levels for the same time period range from $1.44 to $1.90. 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 including the conversion of PNG’s Series A subordinated units into common units of PNG and the conversions of PNG’s Series B subordinated units into Series A subordinated units of PNG.  Upon vesting, these awards will be settled with outstanding common or Series A subordinated units of 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, 2011 and the twelve months ending December 31, 2011 reflect expense of approximately $1.2 million and $3.1 million, respectively, associated with these awards.

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Effective December 31, 2010, we determined that an annualized distribution of $1.45 and the conversion of our Series A subordinated units and the conversion of the first tranche of the Series B subordinated units was probable of occurring and accordingly, for awards that vest upon annualized distribution levels of $1.45 or less, 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.  For example, if an assessment was made that a $1.53 distribution level was probable at March 31, 2011, equity compensation expense would increase by approximately $0.5 million (approximately $0.3 million for the cumulative effect of prior service periods and approximately $0.2 million for the current service period amortization).  Compensation expense for the remaining nine months ending December 31, 2011 would increase approximately $0.6 million.

9.                  Reconciliation of Net Income to Adjusted EBTIDA. The following table reconciles net income to Adjusted EBTIDA for the three-month and twelve-month guidance periods ending March 31, 2011 and December 31, 2011, respectively.

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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 of our management 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 are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

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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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