UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY 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

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)

     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. þ Yes o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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). o Yes o No

     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		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

     As of May 2, 2011, there were 59,184,450 common units outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “PNG.”

 

 

PAA NATURAL GAS STORAGE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION			3
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:			3
Condensed Consolidated Balance Sheets: March 31, 2011 and December 31, 2010			3
Condensed Consolidated Statements of Operations: For the three months ended March 31, 2011 and 2010			4
Condensed Consolidated Statement of Changes in Partners’ Capital: For the three months ended March 31, 2011			5
Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2011 and 2010			6
Notes to the Condensed Consolidated Financial Statements:			7
1. Organization, Nature of Operations and Basis of Presentation			7
2. Recent Accounting Pronouncements			8
3. Acquisition			8
4. Derivative Instruments and Risk Management Activities			10
5. Debt			12
6. Commitments and Contingencies			13
7. Partners’ Capital and Distributions			13
8. Comprehensive Income			14
9. Net Income per Limited Partner Unit			14
10. Equity Compensation Plans			16
11. Related Party Transactions			16
12. Reporting Segment			17
13. Subsequent Event			18
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			19
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			28
Item 4. CONTROLS AND PROCEDURES			28
PART II. OTHER INFORMATION			29
Item 1. LEGAL PROCEEDINGS			29
Item 1A. RISK FACTORS			29
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			29
Item 3. DEFAULTS UPON SENIOR SECURITIES			29
Item 4. [REMOVED AND RESERVED]			29
Item 5. OTHER INFORMATION			29
Item 6. EXHIBITS			29
SIGNATURES			31
EX-2.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PAA Natural Gas Storage, L.P. and Subsidiaries

		March 31,				December 31,
		2011				2010
ASSETS
Current assets
Cash and cash equivalents		$	333			$	346
Restricted cash			2,394				20,000
Accounts receivable			26,237				12,786
Natural gas imbalances receivable			1,500				1,200
Other current assets			6,524				1,544
Total current assets			36,988				35,876
Property and equipment
Property and equipment			1,250,053				892,645
Less: Accumulated depreciation, depletion and amortization			(18,351	)			(14,837	)
Property and equipment, net			1,231,702				877,808
Other assets
Base gas			40,368				37,498
Goodwill and intangibles, net			436,384				47,546
Other long term assets			1,003				—
Total other assets, net			477,755				85,044
Total assets		$	1,746,445			$	998,728
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities		$	19,248			$	12,806
Natural gas imbalances payable			1,500				1,200
Accrued taxes			995				1,009
Total current liabilities			21,743				15,015
Long-term liabilities
Note payable to PAA			200,000				—
Long-term debt under credit facility			207,500				259,900
Other long-term liabilities			377				423
Total long-term liabilities			407,877				260,323
Total liabilities			429,620				275,338
Commitments and contingencies (Note 6)
Partners’ capital
Common unitholders (59,184,450 units issued and outstanding at March 31, 2011)			1,056,515				474,489
Subordinated unitholders (25,434,351 units issued and outstanding at March 31, 2011)			233,968				236,853
General partner			26,591				13,637
Accumulated other comprehensive loss			(249	)			(1,589	)
Total partners’ capital			1,316,825				723,390
Total liabilities and partners’ capital		$	1,746,445			$	998,728

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

PAA Natural Gas Storage, L.P. and Subsidiaries

		Three Months				Three Months
		Ended				Ended
		March 31, 2011				March 31, 2010
Revenues
Firm storage services		$	29,124			$	18,673
Hub services			2,401				1,656
Natural gas sales			18,096				—
Other			799				1,876
Total revenues			50,420				22,205
Costs and expenses
Storage related costs			5,807				6,560
Natural gas sales costs			17,599				—
Other operating costs (except those shown below)			3,087				2,004
Fuel expense			1,095				521
General and administrative expenses			9,184				4,014
Depreciation, depletion and amortization			6,469				2,941
Total costs and expenses			43,241				16,040
Operating income			7,179				6,165
Other income/(expense)
Interest expense, net of capitalized interest			(834	)			(3,037	)
Interest income			3				1
Other income (expense)			(3	)			(6	)
Net income		$	6,345			$	3,123
Calculation of Limited Partner Interest in Net Income:
Net income		$	6,345				n/a
Less general partner interest in net income			208				n/a
Limited partner interest in net income		$	6,137				n/a
Net income per limited partner unit (basic and diluted)
Common and Series A subordinated units (1)		$	0.10				n/a
Limited partner units outstanding
Common and Series A subordinated units (1) (Basic)			59,466				n/a
Common and Series A subordinated units (1) (Diluted)			59,480				n/a

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

PAA Natural Gas Storage, L.P. and Subsidiaries

		Partners’ Capital																Accumulated
						Limited Partners												Other
						Subordinated								General				Comprehensive
		Common				Series A				Series B				Partner				Gain/(Loss)				Total
Balance at December 31, 2010		$	474,489			$	135,062			$	101,791			$	13,637			$	(1,589	)		$	723,390
Net income			4,905				1,232				—				208				—				6,345
Issuance of common units, net of offering and other costs			587,868				—				—				12,000				—				599,868
Equity compensation expense			167								—				1,103				—				1,270
Distributions to unitholders and general partner			(10,899	)			(4,117	)			—				(357	)			—				(15,373	)
Distribution equivalent right payments			(15	)			—				—				—				—				(15	)
Net deferred gain on cash flow hedges			—				—				—				—				1,340				1,340
Balance at March 31, 2011		$	1,056,515			$	132,177			$	101,791			$	26,591			$	(249	)		$	1,316,825

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

PAA Natural Gas Storage, L.P. and Subsidiaries

		Three Months				Three Months
		Ended March 31,				Ended March 31,
		2011				2010
Cash flows from operating activities
Net income		$	6,345			$	3,123
Adjustments to reconcile to cash flow from operations
Depreciation, depletion and amortization			6,469				2,941
Equity compensation expense			1,396				415
Non-cash interest expense on borrowings from parent, net			—				3,037
Non-cash change in fair value of derivative instruments			(39	)			(600	)
Changes in assets and liabilities, net of acquisitions
Accounts receivable and other assets			97				(2,120	)
Accounts payable and accrued liabilities			4,013				3,374
Net cash provided by operating activities			18,281				10,170
Cash flows from investing activities
Additions to property and equipment			(16,453	)			(20,580	)
Cash paid in connection with acquisition, net of cash acquired			(751,527	)			—
Decrease in restricted cash			17,606				—
Cash paid for base gas			—				(3,548	)
Net cash (used in) investing activities			(750,374	)			(24,128	)
Cash flows from financing activities
Borrowings on revolving credit facility			41,400				—
Repayments of borrowings on revolving credit facility			(93,800	)			—
Borrowings under note from PAA			200,000				14,000
Net proceeds from issuance of common units			587,868				—
Contribution from general partner			12,000				—
Distributions paid to unitholders			(15,016	)			—
Distributions paid to general partner			(357	)			—
Distribution equivalent right payments			(15	)			—
Net cash provided by financing activities			732,080				14,000
Net increase (decrease) in cash and cash equivalents			(13	)			42
Cash and cash equivalents
Beginning of period			346				3,124
End of period			333			$	3,166
Cash paid for interest, net of amounts capitalized		$	692			$	—
Non-cash items
Change in non-cash asset purchases included in accounts payable		$	2,244			$	1,051
Non-cash interest capitalized on borrowings from parent		$	—			$	4,301

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

PAA Natural Gas Storage, L.P. and Subsidiaries

1. Organization, Nature of Operations and Basis of Presentation

     PAA Natural Gas Storage, L.P. (the “Partnership” or “PNG”) is a Delaware limited partnership formed on January 15, 2010 to own the natural gas storage business of Plains All American Pipeline, L.P. (“PAA”). The Partnership is a fee-based, growth-oriented partnership engaged in the ownership, acquisition, development, operation and commercial management of natural gas storage facilities.

     We currently own and operate three natural gas storage facilities located in Louisiana, Mississippi and Michigan. Our Pine Prairie and Southern Pines facilities are recently constructed, high-deliverability salt cavern natural gas storage complexes located in Evangeline Parish, Louisiana and Greene County, Mississippi, respectively. Our Bluewater facility is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. As of March 31, 2011, through these facilities, PNG had a total of six operational salt storage caverns and two depleted reservoirs used for natural gas storage, with an aggregate owned working gas storage capacity of approximately 67 billion cubic feet (“Bcf”). During the second half of 2010, we formed PNG Marketing, LLC as a commercial optimization company. PNG Marketing engages in the purchase and sale of natural gas as well as leasing capacity and related services from third party and affiliated providers and engaging in related commercial natural gas marketing activities.

     On May 5, 2010, the Partnership completed its initial public offering (“IPO”) pursuant to which PAA sold an approximate 23.0% limited partner interest in the Partnership to the public. Immediately prior to the closing of the IPO, PAA and certain of its consolidated subsidiaries contributed 100.0% of the equity interests in PAA Natural Gas Storage, LLC (“PNGS”), the predecessor of the Partnership, and its subsidiaries to the Partnership. As of March 31, 2011, PAA owned approximately 64.0% of the equity interests in the Partnership, including our 2.0% general partner interest and limited partner interests consisting of 28,272,870 common units, 11,934,351 Series A subordinated units and 13,500,000 Series B subordinated units.

     The accompanying condensed consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2010 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to the Partnership. The condensed balance sheet data as of December 31, 2010 was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. The results of operations for the three months ended March 31, 2011 should not be taken as indicative of the results to be expected for the full year.

     The accompanying condensed consolidated financial statements include the accounts of PNG and its subsidiaries, all of which are wholly owned. All significant intercompany transactions have been eliminated.

     As used in this document, the terms “we,” “us,” “our” and similar terms refer to the Partnership and its subsidiaries including its predecessors, where applicable, unless the context indicates otherwise.

Natural Gas Sales

     Revenues from the sale of natural gas by PNG Marketing are recognized at the time title to the gas sold transfers to the purchaser, which generally occurs upon delivery of the gas to the purchaser or its designee. Natural gas sales also includes applicable derivative gains and losses on commodity derivatives utilized by PNG Marketing in conjunction with natural gas sales activities. Any ineffectiveness on such derivatives designated as cash flow hedges, if any, is reflected as a component of other revenues in our consolidated statements of operations.

     Purchases and sales of natural gas by PNG Marketing are subject to netting provisions (contractual terms that allow us and the counterparty to offset receivables and payables) which serve to mitigate credit risk.

Natural Gas Sales Costs

     Natural gas sales costs include (i) the cost of natural gas, (ii) fees incurred for third-party transportation and storage and (iii) brokerage fees and commissions. Such costs are generally recognized at the time natural gas is sold by PNG Marketing.

Restricted Cash

     As of March 31, 2011, restricted cash consists of approximately $2.4 million of cash acquired in the Southern Pines Acquisition which is restricted for specified capital expenditures.

Inventory

     Natural gas inventory owned by PNG Marketing is valued at the lower of cost or market, with cost determined using an average cost method within specified inventory pools. As of March 31, 2011, PNG owned approximately 0.9 Bcf of natural gas inventory with a carrying value of approximately $3.4 million which is reflected as a component of other current assets on our condensed consolidated balance sheet.

Property and Equipment

     During the three months ended March 31, 2011, we received cash of approximately $7.2 million under a state incentive program for jobs creation. This incentive payment, which was determined based on applicable capital expenditures, was accounted for as a refund of sales tax previously paid and reduced the carrying value of our applicable property and equipment.

2. Recent Accounting Pronouncements

Standards Adopted as of January 1, 2010

     Other than as discussed below and in our 2010 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the three months ended March 31, 2011 that are of significance or potential significance to us.

     Fair Value Measurement Disclosure Requirements. In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. A fair value measurement is designated as level 1, 2 or 3 within the hierarchy based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, level 2 measurements generally reflect the use of significant observable inputs and level 3 measurements typically utilize significant unobservable inputs. This new guidance requires a gross presentation of activities within the level 3 roll-forward. This guidance was effective for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted this guidance on January 1, 2011. See Note 4 for additional disclosure. Our adoption did not have any material impact on our financial position, results of operations, or cash flows.

3. Acquisition

     On February 9, 2011, we completed the acquisition of SG Resources Mississippi, L.L.C., owner of the Southern Pines Energy Center natural gas storage facility (the “Southern Pines Acquisition”). The purchase price, which is subject to finalization of certain post-closing adjustments, was approximately $752 million, net of cash acquired.

     The allocation of fair value to the assets and liabilities acquired in the Southern Pines Acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired. Several factors contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired. Such factors include the strategic location of the Southern Pines facility, the limited alternative locations and the extended lead times required to develop and construct such facility, along with its operational flexibility, organic expansion capabilities and synergies anticipated to be obtained from combining Southern Pines with our existing asset base.

     The preliminary purchase price allocation is as follows (in millions):

						Average
						Depreciable
Description		Amount				Life (in years)
Inventory		$	14			n/a
PP&E			341			5—70
Base Gas			3			n/a
Other working capital, net of cash acquired			1			n/a
Intangible assets			92			2—10
Goodwill			301			n/a
Total		$	752

     Our purchase price allocation is preliminary pending completion of internal valuation procedures primarily related to the valuation of intangible assets and the various components of the property and equipment acquired. The preliminary allocation of fair value to intangible assets above is comprised of a tax abatement valued at approximately $15 million and contracts valued at approximately $77 million, which have lives ranging from 2 — 10 years. Amortization of customer contracts under the declining balance method of amortization is estimated to be approximately $12.8 million, $14.2 million, $13.3 million, $11.0 million and $8.3 million for the five full or partial calendar years following the acquisition date, respectively. Goodwill or indefinite lived intangible assets will not be subject to depreciation or amortization, but will be subject to periodic impairment testing and, if necessary, will be written down to fair value should circumstances warrant. We expect to finalize our purchase price allocation during 2011.

     In conjunction with the Southern Pines Acquisition, we arranged financing totaling approximately $800 million to fund the purchase price, closing costs and the first 18 months of expected expansion capital; the financing consisted of $200 million of borrowings under a promissory note from PAA (see Note 5) and approximately $600 million from the issuance of our common units (see Note 7).

     During the three months ended March 31, 2011, we incurred approximately $4.0 million of acquisition-related costs associated with the Southern Pines Acquisition. Such costs are reflected as a component of general and administrative expenses in our condensed consolidated statement of operations.

Goodwill included in our condensed consolidated balance sheets was approximately $326 million and $25 million as of March 31, 2011 and December 31, 2010, respectively.

Pro Forma Results

     Total revenues generated by our Southern Pines facility of approximately $5.7 million for period from February 9, 2011 (date of acquisition) through March 31, 2011 are included in our condensed consolidated statement of operations for the three months ended March 31, 2011. Disclosure of the earnings of our Southern Pines facility since the acquisition date is not practicable as it is not being operated as a standalone subsidiary.

     Selected unaudited pro forma results of operations for the three months ended March 31, 2011 and 2010, assuming the Southern Pines Acquisition had occurred on January 1, 2010, are presented below (in millions, except per share amounts):

		Three Months Ended March 31,
		2011				2010
Total revenues		$	54,383			$	28,805
Net income		$	7,549			$	5,279
Net income per limited partner unit(1)(2)
Basic		$	0.12				n/a
Diluted		$	0.12				n/a

4. Derivative Instruments and Risk Management Activities

     From time to time, we may utilize derivative instruments to (i) manage our price exposure associated with anticipated purchases or sales of natural gas, (ii) economically hedge the value of our natural gas storage facilities and (iii) manage our exposure to interest rate risk. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking hedges. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of a hedge and on an ongoing basis, we assess whether the derivatives used in such hedging transactions are highly effective in offsetting changes in cash flows of hedged items. FASB guidance requires us to recognize changes in the fair value of derivative instruments currently in earnings unless the derivatives meet specific cash flow hedge accounting requirements, in which case the effective portion of changes in the fair value of cash flow hedges are deferred in accumulated other comprehensive income (“AOCI”) and reclassified into earnings when the underlying hedged transaction affects earnings.

Commodity Price Risk Hedging

     We use derivative financial instruments to hedge the following commodity risks inherent in our business:

     Anticipated Purchases and Sales of Natural Gas — Our gas storage facilities require minimum levels of base gas to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of March 31, 2011, we have a long futures position of approximately 1 Bcf consisting of NYMEX futures, 2.6 Bcf of long NYMEX and ICE swaps, and a long call option position of approximately 0.7 Bcf related to anticipated base gas purchases. Additionally, our dedicated commercial optimization company captures short-term market opportunities by leasing a portion of our owned or leased storage capacity engaging in related commercial optimization activities. We use various derivatives to hedge anticipated purchases and sales of natural gas by our commercial optimization company. As of March 31, 2011, we have a short swap position of approximately 4.1 Bcf consisting of NYMEX and ICE swaps related to anticipated sales of natural gas, and an approximate 5.0 Bcf long swap position consisting of NYMEX and ICE swaps related to anticipated purchases of natural gas. As of March 31, 2011, all of our outstanding derivatives entered into for purposes of hedging anticipated purchases and sales of natural gas have been designated as cash flow hedges.

Summary of Financial Statement Impact

     Derivatives that qualify for hedge accounting are designated as cash flow hedges. Changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying hedged transaction impacts earnings. Derivatives that do not qualify for hedge accounting and the ineffective portion of cash flow hedges are recognized in earnings each period. Cash settlements associated with our derivative activities are reflected as operating cash flows in our consolidated statements of cash flows.

     We recognized an unrealized gain of approximately $0.6 million during three months ended March 31, 2010 associated with a natural gas calendar spread position, which was closed in June 2010 and did not qualify for hedge accounting. Such gain is reflected as

a component of other revenues in our accompanying condensed consolidated statements of operations. During the three months ended March 31, 2011, we did not have any material derivative positions that did not qualify for hedge accounting.

     A summary of the impact of our derivative activities in cash flow hedging relationships recognized in earnings for the three months ended March 31, 2011 is as follows (in thousands):

		Three Months Ended March 31, 2011
		Derivatives in				Derivatives not
		Hedging				Designated
Location of gain/(loss)		Relationships(1)(2)				as a Hedge(3)				Total
Commodity Derivatives
Natural Gas Sales		$	846			$	85			$	931
Other Revenues			39				—				39
Total Gain/(Loss) on
Derivatives Recognized in Net Income		$	885			$	85			$	970

     During the three months ended March 31, 2010, our earnings were not impacted from derivatives activities in cash flow hedging relationships.

     The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of March 31, 2011 (in thousands):

		Asset Derivatives						Liability Derivatives
		Balance Sheet						Balance Sheet
		Location		Fair Value				Location		Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives		Other current assets		$	2,844			Other current assets		$	(2,034	)
		Other long-term assets			1,003						—
Total derivatives designated as hedging instruments				$	3,847					$	(2,034	)

     The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of December 31, 2010 (in thousands):

Asset Derivatives

Liability Derivatives

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

Derivatives designated as hedging instruments:

Commodity derivatives

Other current assets

$

43

Other current assets

$

(4

)

     As of March 31, 2011, there was a net loss of approximately $0.2 million deferred in AOCI. During the three months ended March 31, 2011, we recognized a $1.3 million net deferred gain in AOCI which included approximately $2.1 million of unrealized derivative gains offset by approximately $0.8 million of amounts reclassified to current period earnings to coincide with the earnings impact of the respective hedged transaction. Amounts deferred in AOCI include amounts associated with terminated hedging instruments for which the underlying anticipated hedge transactions are still probable of occurring. The deferred loss in AOCI is expected to be reclassified to future earnings contemporaneously with the earnings recognition of the underlying hedged transactions. Certain underlying hedged transactions are for anticipated base gas purchases. As we account for base gas as a long-term asset, which is not subject to depreciation, amounts related to base gas will not be reclassified to future earnings until such gas is sold or in the event an impairment charge is recognized in the future. We expect to reclassify approximately $0.8 million of deferred gain as of March 31, 2011 into earnings during the next twelve months. Amounts deferred are based on market prices as of March 31, 2011, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. During the first quarter 2011, no amounts were reclassified from AOCI to earnings as a result of anticipated hedge transactions that were no longer considered to be probable of occurring.

     Our accounting policy is to offset fair value amounts associated with derivatives executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through a brokerage account and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of March 31, 2011, we had a net broker receivable of approximately $1.6 million (consisting of initial margin of $2.9 million decreased by $1.3 million of variation margin returned to us). At March 31, 2011, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact upon a change in our credit ratings.

     ASC 820, “Fair Value Measurements and Disclosures,” requires enhanced disclosures about assets and liabilities carried at fair value. As defined in ASC 820, fair value is the price that would be received from selling an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

     The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements, but also the impact of potential nonperformance risk on our liabilities. As of March 31, 2011 and December 31, 2010 and during the three months ended March 31, 2011 and 2010, all of our derivatives utilized consisted of exchange-traded or exchange-cleared instruments within active markets. We therefore consider all of our derivatives as of March 31, 2011 and December 31, 2010 and during the three months periods ended March 31, 2011 and 2010 to be Level 1 fair value measurements.

5. Debt

     Our three-year, $400 million senior unsecured credit facility, as amended, bears interest based on LIBOR plus an applicable margin and commitment fees (approximately 3.5% in the aggregate as of March 31, 2011) determined based on funded debt-to-EBITDA levels (as defined in the credit agreement). As of March 31, 2011, we were in compliance with the covenants required by our credit facility.

     On February 9, 2011, in connection with the Southern Pines Acquisition (see Note 3), the Partnership borrowed $200 million from PAA pursuant to a three-year promissory note bearing interest at an annual rate of 5.25% (the “PAA Promissory Note”). Interest on the PAA Promissory Note is paid semiannually on the last business day of June and December.

     Our credit facility includes the ability to issue letters of credit. As of March 31, 2011, we had no outstanding letters of credit.

     Capitalized interest for the three months ended March 31, 2011 and 2010 was approximately $2.7 million and $4.3 million, respectively.

     Also in connection with the Southern Pines Acquisition, the Partnership became the holder of the $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2009 and the $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2010 (collectively, the “GO Zone Bonds”), which mature in 2032 and 2035, respectively. The GO Zone Bonds were originally issued to fund the expansion of the Southern Pines facility. The Partnership has the ability to remarket the GO Zone Bonds in the future. As we are currently both the owner of and the ultimate obligor under the GO Zone Bonds, we have presented our investment in and obligation under the GO Zone Bonds on a net basis in our condensed consolidated balance sheet as of March 31, 2011.

6. Commitments and Contingencies

Environmental

     We may experience releases of natural gas, brine, crude oil or other contaminants into the environment, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such releases from our assets may substantially affect our business. As of March 31, 2011, we have not identified any such material obligations.

     A natural gas storage facility, associated pipeline header system and gas handling and compression facilities may suffer 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 or destruction of property, base gas, or equipment, pollution or environmental damage, or suspension of operations. We maintain insurance under PAA’s insurance program, of various types that we consider adequate to cover our operations and properties. Such insurance covers our assets in amounts management considers reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating natural gas storage facilities, associated pipeline header systems, and gas handling and compression facilities. The overall trend in the 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 insurance markets, we expect this trend to continue as we continue to grow and expand. Accordingly, we may elect to self-insure more of our 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 condition, results of operations or cash flows.

Insurance

     We participate in an insurance program managed by PAA. Due to recent increases in cost combined with stricter coverage limitations, we have decided to not purchase hurricane or windstorm related property damage coverage for 2011/12 and we will self insure this risk. This decision does not affect our third party liability insurance coverage which still covers hurricane related liability claims.

Litigation

     We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

7. Partners’ Capital and Distributions

Equity Issuances

     On February 8, 2011, in connection with the Southern Pines Acquisition, we completed the sale in a private placement of approximately 17.4 million common units to third-party purchasers and approximately 10.2 million common units to PAA for total proceeds of approximately $600 million, including PAA’s proportionate general partner contribution. We entered into Registration Rights Agreements with the third-party purchasers providing them with certain rights relating to registration of the common units under the Securities Act.

Outstanding Units

     From December 31, 2010 through March 31, 2011, changes in our issued and outstanding common, Series A subordinated and Series B subordinated units were as follows:

						Subordinated
		Common				Series A				Series B				Total
Balance, December 31, 2010			31,586,405				11,934,351				13,500,000				57,020,756
Units Issed in Private Placements			27,598,045				—				—				27,598,045
Balance, March 31, 2011			59,184,450				11,934,351				13,500,000				84,618,801

Distributions

     The following table details the distributions declared for or paid during the three months ended March 31, 2011 (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
April 11, 2011		May 13, 2011(1)				$	20.4			$	4.1			$	0.1			$	0.5			$	25.1			$	0.3450
January 12, 2011		February 14, 2011				$	10.9			$	4.1			$	0.1			$	0.3			$	15.4			$	0.3450

8. Comprehensive Income

     Comprehensive income includes net income and all other non-owner changes in equity. Components of comprehensive income (loss) are presented below (in thousands):

		Three Months				Three Months
		Ended March 31,				Ended March 31,
		2011				2010
Net income		$	6,345			$	3,123
Net unrealized gain/(loss) on cash flow hedges			1,340				(389	)
Total comprehensive income		$	7,685			$	2,734

9. Net Income per Limited Partner Unit

     Basic and diluted net income per unit is determined by dividing each class of limited partners’ interest in net income by the weighted average number of limited partner units for such class outstanding during the period. Pursuant to FASB guidance, the limited partners’ interest in net income is calculated by first reducing net income by the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter (including the incentive distribution right in excess of the 2.0% general partner interest). Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partner interests in accordance with the contractual terms of the partnership agreement. Diluted earnings per limited partner unit, where applicable, reflects the potential dilution that could occur if securities or other agreements to issue additional units of a limited partner class, such as phantom unit awards, were exercised, settled or converted into such units.

     The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2011 (amounts in thousands, except per unit data):

		Three Months Ended,
		March 31, 2011
Net income		$	6,345
Less: Incentive distributions due to general partner			83
Less: General partner’s 2% ownership interest			125
Net income available to limited partners		$	6,137
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income amongst limited partner interests:
Net income allocable to common units		$	4,905
Net income allocable to Series A subordinated units			1,232
Net income allocable to Series B subordinated units (1)			—
Net income available to limited partners		$	6,137
Denominator:
Basic weighted average number of limited partner units outstanding: (1)(2)(3)
Common units			47,532
Series A subordinated units			11,934
Series B subordinated units			13,500
Diluted weighted average number of limited partner units outstanding: (1)(2)(3)
Common units			47,546
Series A subordinated units			11,934
Series B subordinated units			13,500
Basic and diluted net income per limited partner unit: (1)(2)(3)
Common units		$	0.10
Series A subordinated units		$	0.10
Series B subordinated units		$	—

10. Equity Compensation Plans

Long Term Incentive Plan (“LTIP”)

     For discussion of our equity compensation awards, see Note 10 to our consolidated financial statements included in Part IV of our 2010 Annual Report on Form 10-K.

     Our equity compensation activity for awards denominated in PNG units is summarized in the following table (units in thousands):

						Weighted Average
						Grant Date
		Units				Fair Value per Unit
Outstanding, December 31, 2010			623			$	19.41
Granted			15				24.22
Vested			—				—
Cancelled or forfeited			—				—
Outstanding, March 31, 2011			638			$	19.53

     The table below summarizes the expense recognized and unit or cash settled vestings related to all of our equity compensation plans during the three months ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended March 31,
		2011				2010
Equity compensation expense (1) (2)		$	1,396			$	415
LTIP cash settled vestings		$	—			$	—
LTIP cash settled vestings		$	—			$	—
DER cash payments		$	19			$	—

11. Related Party Transactions

     We do not directly employ any personnel to manage or operate our business. These functions are provided by employees of Plains All American GP LLC (“GP LLC”), the general partner of Plains AAP, L.P. which is the sole member of PAA GP LLC, PAA’s general partner. References to PAA, unless the context otherwise requires, include GP LLC. We reimburse PAA for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by PAA in connection with the operation of our business. These expenses are recorded in general and administrative expenses and other operating costs on our income statement and include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf. We record these costs on the accrual basis in the period in which PAA’s general partner incurs them. We reimburse PAA for costs related to equity-based compensation awards upon vesting of the awards. Our agreement with PAA provides that PAA will determine the expenses allocable to us in any reasonable manner determined by PAA in its sole discretion. Total costs reimbursed by us to PAA for the three months ended March 31, 2011 and 2010 were $3.7 million and $5.0 million, respectively. Of these amounts approximately $0.9 million and $0.8 million, respectively, were allocated personnel costs for shared services and the remainder consisted of direct costs that PAA paid on our behalf along with our allocation of insurance premiums for participation in PAA’s insurance program.

As of March 31, 2011 and December 31, 2010, PNG had amounts due to PAA of approximately $1.0 million and $0.6 million, respectively, included in accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheet.

     As of March 31, 2011 and December 31, 2010, PNG’s obligation for unvested equity-based compensation awards for which we are required to reimburse PAA upon vesting and settlement was approximately $1.2 million and $1.0 million, respectively. Approximately $0.8 million and $0.6 million of such amounts were reflected in accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets as of March 31, 2011 and December 31, 2010, respectively, with the remaining balances included as a component of other long-term liabilities at each respective date.

     As of March 31, 2011, outstanding parental guarantees issued by PAA to third parties on behalf of PNG Marketing were approximately $10.0 million. No amounts were due to PAA as of March 31, 2011 under such guarantees and no payments were made to PAA under such guarantees during the three months ended March 31, 2011.

Relationship with our general partner

     Except as previously disclosed, we are not party to any material transactions with our general partner or any of its affiliates. Additionally, our general partner is not obligated to provide any direct or indirect financial assistance to us or to increase or maintain its capital investment in us.

12. Reporting Segment

     We manage our operations through three operating segments, Bluewater, Southern Pines and Pine Prairie. We have aggregated these operating segments into one reporting segment, Gas Storage. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including adjusted EBITDA, volumes, adjusted EBITDA per thousand cubic feet (“mcf”) and maintenance capital expenditures. We have aggregated our three operating segments into one reportable segment based on the similarity of their economic and other characteristics, including the nature of services provided, methods of execution and delivery of services, types of customers served and regulatory requirements. We define adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring. The measure above excludes depreciation, depletion and amortization as we believe that depreciation, depletion and amortization are largely offset by repair and maintenance capital investments. Maintenance capital consists of expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating capability, service capability, and/or functionality of our existing assets.

The following table reflects certain financial data for our reporting segment for the periods indicated (in thousands):

		Three Months Ended				Three Months Ended
		March 31, 2011				March 31, 2010
Revenues (1)		$	50,420			$	22,205
Adjusted EBITDA		$	19,500			$	8,916
Maintenance capital		$	106			$	199
Long-lived assets (1) (2)		$	1,709,457			$	914,798
Total assets (2)		$	1,746,445			$	929,451

     The following table reconciles Adjusted EBITDA to consolidated net income (in thousands):

		Three Months Ended				Three Months Ended
		March 31, 2011				March 31, 2010
Adjusted EBITDA		$	19,500			$	8,916
Selected items impacting Adjusted EBITDA:
Equity compensation expense			(1,396	)			(415	)
Mark-to-market of open derivative positions			39				600
Significant acquisition-related expenses			(3,995	)			—
Insurance deductible related to property damage incident			(500	)			—
Depreciation, depletion and amortization			(6,469	)			(2,941	)
Interest expense, net of capitalized interest			(834	)			(3,037	)
Net Income		$	6,345			$	3,123

13. Subsequent Event

     In May 2011, we entered into an agreement with the former owners of SG Resources Mississippi, LLC with respect to certain outstanding issues and purchase price adjustments as well as the distribution of the remaining 5% of the purchase price that was escrowed at closing (totaling $37.3 million). Pursuant to this agreement, we received approximately $10 million and the balance was remitted to the former owners. Funds received by us will be used to fund anticipated facility development and other related costs identified subsequent to closing. Additionally, the parties executed releases of any existing and future claims, subject to customary carve-outs.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2010 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the condensed consolidated financial statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

     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 further discussion regarding the Partnership’s initial public offering, please see the consolidated financial statements included in the Partnership’s 2010 Annual Report on Form 10-K.

Overview of Operating Results, Capital Spending and Significant Activities

     Adjusted EBITDA for the three months ended March 31, 2011 was approximately $19.5 million, a 119% increase over Adjusted EBITDA of approximately $8.9 million for three months ended March 31, 2010. 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 and the completion of the Southern Pines Acquisition on February 9, 2011. See “— Results of Operations” for further discussion and analysis of our operating results. Expansion capital expenditures for the three months ended March 31, 2011 were approximately $768 million including the acquisition of our Southern Pines facility and the ongoing development of our Pine Prairie facility.

     In conjunction with the Southern Pines Acquisition we arranged financing totaling approximately $800 million to fund the purchase price, closing costs and the first 18 months of expected expansion capital at the Southern Pines facility. Such financing included $200 million borrowed from PAA pursuant to a three-year promissory note bearing interest at an annual rate of 5.25% and approximately $600 million (including PAA’s proportionate general partner contribution) from the sale in a private placement of approximately 17.4 million common units to third-party purchasers and approximately 10.2 million common units to PAA.

Results of Operations

     The tables below summarize our results of operations for the periods indicated (in thousands, except working capacity and monthly operating metrics data):

		Three Months Ended								Favorable/(Unfavorable)
		March 31,								Variance (1)
		2011				2010				$				%
Revenues
Firm Storage Services
Reservation fees		$	27,382			$	17,493				9,889				57	%
Cycling fees and fuel-in-kind			1,742				1,180				562				48	%
Hub Services			2,401				1,656				745				45	%
Natural Gas Sales			18,096				—				18,096				—
Other			799				1,876				(1,077	)			(57	)%
Total revenue			50,420				22,205				28,215				127	%
Storage related costs			(5,807	)			(6,560	)			753				11	%
Natural gas sales costs			(17,599	)			—				(17,599	)			—
Operating costs (except those shown below)			(3,087	)			(2,004	)			(1,083	)			(54	)%
Fuel expense			(1,095	)			(521	)			(574	)			(110	)%
General and administrative expenses			(9,184	)			(4,014	)			(5,170	)			(129	)%
Interest income and other income (expense), net			—				(5	)			5				100	%
Significant acquisition-related expenses			3,995				—
Insurance deductible related to property			500				—
damage incident
Equity compensation expense			1,396				415
Mark-to-market of open derivative positions			(39	)			(600	)
Adjusted EBITDA		$	19,500			$	8,916				10,584				119	%
Reconciliation to net income Adjusted EBITDA		$	19,500			$	8,916				10,584				119	%
Depreciation, depletion and amortization			(6,469	)			(2,941	)			(3,528	)			(120	)%
Interest expense, net of capitalized interest			(834	)			(3,037	)			2,203				73	%
Equity compensation expense			(1,396	)			(415	)
Significant acquisition-related expenses			(3,995	)			—
Mark-to-market of open derivative positions			39				600
Insurance deductible related to property damage incident			(500	)			—
Net income		$	6,345			$	3,123				3,222				103	%
Operating Data:
Net revenue margin(2) (3)		$	26,975			$	15,045				11,930				79	%
Other operating expenses / G&A / Other			(7,475	)			(6,129	)			(1,346	)			(22	)%
Adjusted EBITDA		$	19,500			$	8,916				10,584				119	%
Average working capacity (Bcf)			59.1				44.1				14.9				34	%
Average Monthly Operating Metrics ($/Mcf):
Net revenue margin(2) (3)		$	0.15			$	0.12				0.03				25	%
Operating expenses / G&A / Other			(0.04	)		$	(0.05	)			0.01				20	%
Adjusted EBITDA		$	0.11			$	0.07				0.04				57	%

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):

		Three Months Ended March 31,
		2011				2010
Adjusted EBITDA reconciliation
Net income		$	6,345			$	3,123
Interest expense, net of amounts capitalized			834				3,037
Depreciation, depletion and amortization			6,469				2,941
Selected items impacting Adjusted EBITDA
Equity compensation expense			1,396				415
Significant acquisition-related expenses			3,995				—
Mark-to-market of open derivative positions			(39	)			(600	)
Insurance deductible related to property damage incident			500				—
Adjusted EBITDA		$	19,500			$	8,916
Distributable cash flow reconciliation
Net income		$	6,345			$	3,123
Depreciation, depletion and amortization			6,469				2,941
Significant acquisition-related expenses			3,995				—
Maintenance capital expenditures			(106	)			(199	)
Other non cash items:
Equity compensation expense, net of cash payments			1,377				415
Mark-to-market of open derivative positions			(39	)			(600	)
Distributable cash flow		$	18,041			$	5,680

Three Months Ended March 31, 2011 as Compared to the Three Months Ended March 31, 2010

     Revenues, Volumes and Storage Related Costs. As noted in the table above, our total revenue and storage related costs increased during the three months ended March 31, 2011 (the “2011 period”) when compared to the three months ended March 31, 2010 (the “2010 period”). The primary reasons for such increase are the completion of the Southern Pines Acquisition on February 9, 2011, the placement into service of an additional 10 Bcf of working gas storage capacity at our Pine Prairie facility in the second quarter of 2010 and additional leasing of third party storage and transportation assets impacting the 2011 period relative to the 2010 period. These and other significant variances related to these periods are discussed in more detail below:

	•		Firm storage reservation fees — Firm storage reservation fee revenues increased in the 2011 period as compared to the 2010 period, primarily due to the completion of the Southern Pines Acquisition and the placement into service of an additional 10 Bcf of working gas capacity at our Pine Prairie facility in April 2010, which resulted in approximately $9.9 million in incremental firm storage reservation fees in the 2011 period. Revenues from firm storage reservation fees were also positively impacted by additional revenue generating activities associated with improved utilization of leased storage and transportation capacity. See “— Storage related costs” below.
	•		Firm storage cycling fees and fuel-in-kind — Firm storage cycling fees and fuel-in-kind revenues increased in the 2011 period as compared to the 2010 period primarily due to the increase in working gas capacity in-service from 2010 to 2011 as a result of our expansion efforts at our Pine Prairie facility and the completion of the Southern Pines Acquisition. An increase in period-over-period average natural gas prices also contributed to the increased revenues in the 2011 period as compared to the 2010 period.

	•		Hub services — Hub services increased in the 2011 period as compared to the 2010 period. Our hub services activities are generally short-term in nature and their timing is influenced by weather, operating disruptions, import activities and other conditions that result in temporary disruptions in supply and demand. The increase in hub services revenues in the 2011 period as compared to the 2010 period is primarily due to usage of leased transportation assets and market conditions generally being more favorable in 2011 when compared to 2010.
	•		Natural gas sales — Natural gas sales of approximately $18.1 million during the 2011 period relate to revenues from sales of natural gas by PNG Marketing.
	•		Other — Other revenue for each of the periods consists primarily of crude oil sales and activities associated with natural gas storage-related futures derivative positions. Crude oil sales decreased in the 2011 period as compared to the 2010 period by approximately $0.5 million. The decrease in crude oil sales in the 2011 period as compared to the 2010 period is primarily attributable to a temporary stoppage in liquids removal efforts at our Bluewater facility as a result of the operational incident and related fire that occurred in January 2011. The 2010 period also includes approximately $0.6 million of unrealized gain associated with natural gas storage-related futures derivative positions which were not eligible for hedge accounting treatment. Such positions were terminated during the third quarter of 2010 and no similar natural gas storage-related derivative financial instruments have been entered into subsequent to that date.
	•		Storage related costs — Storage related costs decreased in the 2011 period as compared to the 2010 period. This decrease was principally due to the capacity release of leased transportation assets at our Pine Prairie facility during the third quarter of 2010.
	•		Natural gas sales costs — Natural gas sales costs of approximately $17.6 million during the 2011 period reflect the cost of natural gas sold by PNG Marketing.

     Other Costs and Expenses. The significant variances are discussed further below:

	•		Operating costs — Field operating costs increased in the 2011 period as compared to the 2010 period. The increase is primarily related to the increase in working gas capacity in-service from 2010 to 2011 as a result of our expansion efforts at our Pine Prairie facility and the completion of the Southern Pines Acquisition. The 2011 period includes approximately $0.5 million of expense for the property insurance deductible related to the January 2011 operational incident and fire at our Bluewater facility.
	•		Fuel expense — Fuel expense increased in the 2011 period as compared to 2010 due to increases in both the volume of fuel consumed and the market price of fuel.
	•		General and administrative expenses — General and administrative expenses increased in the 2011 period as compared to the 2010 period. The increase resulted from the continued expansion of our business and growth in personnel costs, including equity compensation expense and the establishment of our commercial optimization group, along with additional administrative costs associated with being a public company. Additionally, during the 2011 period we recognized approximately $1.1 million of equity compensation expense associated with awards granted by PAA. Although we will not bear the economic burden of these awards, we benefit from the services underlying these awards. The 2011 period also includes approximately $4.0 million of acquisition and integration costs incurred in conjunction with the Southern Pines Acquisition.
	•		Depreciation, depletion and amortization — Depreciation, depletion and amortization expense increased in the 2011 period as compared to the 2010 period. The increase resulted primarily from an increased amount of depreciable assets resulting from the Southern Pines acquisition and our internal growth projects, including the additional 10 Bcf of storage capacity placed into service at our Pine Prairie facility in April 2010. Additionally, amortization of intangible assets acquired in conjunction with the Southern Pines Acquisition was approximately $2.3 million during the 2011 period.
	•		Interest expense, net of capitalized interest — Interest expense decreased in the 2011 period when compared to the 2010 period. The decrease principally resulted from decreases in both average debt balances outstanding and average interest rates in the 2011 period as compared to 2010 period. Capitalized interest was approximately $2.7 million and $4.3 million in the 2011 and 2010 periods, respectively. Capitalized interest was impacted from the decreases in both average debt balances outstanding and average interest rates along with an increase in assets not yet in-service as a result of the Southern Pines Acquisition.

Outlook

     Following a multi-year period of favorable market conditions for natural gas storage providers, overall market conditions for both hub services and firm storage services softened throughout 2010 continuing into 2011. Factors we believe contributed to this deterioration include reduced spread and basis differentials and associated volatility, which we believe were impacted by a combination of factors, including weather patterns, shale gas production and pipeline infrastructure additions. Market conditions weakened progressively in the second half of 2010 continuing into 2011 with seasonal spreads, as reflected by the October 2011 to January 2012 NYMEX spread, decreasing to a five-year low of $0.432 per dekatherm during April 2011.

     We believe certain of the supply and demand factors contributing to the weakness are self-correcting over time and that the long-term demand for storage is positive. Additionally, we believe our asset base, contract profile, financial position and low risk, economically attractive expansion projects will enable us to continue to grow our cash flows for the next several years even if such conditions persist, albeit at lower levels of growth than would have been experienced in a strong market environment. We also believe we are reasonably well positioned to pursue and consummate additional acquisitions.

     However, if weak gas storage market conditions persist, in addition to adversely affecting hub services activities, they may adversely impact the lease rates our customers are willing to pay for firm storage services with respect to new capacity under construction as well as renewals of existing capacity upon expirations of existing term leases. Accordingly, although a significant portion of our existing capacity is underpinned by multi-year firm storage contracts, we will not be unaffected by adverse overall market conditions. Additionally, we can provide no assurance that our operating and financial results will not be adversely impacted by such conditions, or that our acquisition and organic growth efforts will be successful.

Liquidity and Capital Resources

Overview

     Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to storage costs incurred and other operating and general and administrative expenses, interest payments on our outstanding debt and distributions to our owners, (ii) maintenance and expansion capital expenditures, including purchases of base gas, (iii) acquisitions of assets or businesses and (iv) repayment of principal on our long-term debt. We generally expect to fund our short-term cash requirements through our primary sources of liquidity, which consist of our cash flow generated from operations as well as borrowings under our credit facility. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions, through a variety of sources (either separately or in combination), which may include operating cash flows, borrowings under our credit facilities, and/or proceeds from the issuance of additional equity or debt securities.

     In conjunction with the closing of our initial public offering on May 5, 2010, the Partnership entered into a three-year, $400 million senior unsecured revolving credit facility, which may be expanded to $600 million with approval of the administrative agent. At March 31, 2011, we had $207.5 million outstanding under this facility. The extent to which we can borrow against the remaining $192.5 million depends on our ability to maintain various financial ratios, including a debt-to-EBITDA coverage ratio of less than 4.75 to 1.00 on outstanding debt (5.50 to 1.00 on all outstanding debt during an acquisition period) and an interest-to-EBITDA coverage ratio of no less than 3.00 to 1.00 (in each case, as such terms are defined in the credit agreement). As of March 31, 2011, we were in compliance with the covenants, including the financial ratios, contained in our credit agreement. Based on the most restrictive covenant, at March 31, 2011 our total available debt would be limited to approximately $359 million of the $400 million. Notably, the restriction on debt incurrence does not limit our ability to incur hedged inventory debt. Also, the formula for determining EBITDA in the context of the financial ratios allows for inclusion of proforma EBITDA arising from certain capital investments, including for acquisitions and certain capital expenditures related to our Pine Prairie and Southern Pines expansions. We believe our credit facility and available debt capacity is adequate to fund our current capital program.

     PAA may elect, but is not obligated, to provide financial support to us under certain circumstances, such as in connection with an acquisition or expansion capital project. Our partnership agreement contains provisions designed to facilitate PAA’s ability to provide us with financial support while reducing concerns regarding conflicts of interest by defining certain potential financing transactions between PAA and us as fair to our unitholders. As further defined in our partnership agreement, potential PAA financial support can include, but is not limited to, our issuance of common units to PAA, our borrowing of funds from PAA or guaranties or trade credit support to support the ongoing operations of us or our subsidiaries. We have no obligation to seek financing or support from PAA or to accept such financing or support if offered to us.

     During 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which includes provisions regarding the use of derivative financial instruments. The scope and applicability of these provisions is not entirely clear and regulations implementing all the various aspects of the Act have not yet been issued. Our current assessment is that we may have additional documentation requirements. We will continue to monitor the final rules and regulations as they develop.

Historical Cash Flow

     As of March 31, 2011, we had a working capital surplus of approximately $15.2 million, including approximately $2.4 million of cash which is restricted for Southern Pines capital expenditures.

     The following table presents a summary of our cash flows for the three months ended March 31, 2011 and 2010 (in thousands):

		Three Months Ended March 31,
		2011				2010
Net cash provided by (used in):
Operating activities		$	18,281			$	10,170
Investing activities			(750,374	)			(24,128	)
Financing activities			732,080				14,000
Net increase/(decrease) in cash		$	(13	)		$	42
Adjusted EBITDA		$	19,500			$	8,916

     Operating Activities. The primary drivers of cash flow from our operations are (i) the collection of amounts related to the storage of natural gas, and (ii) the payment of amounts related to expenses, principally storage and transportation related costs, field operating costs and general and administrative expenses.

     Investing Activities. Our investing activities for each of the periods listed above primarily relate to the continued expansion of our Pine Prairie facility and the acquisition of the related base gas required to operate the facility. The 2011 period includes the Southern Pines Acquisition.

     Financing Activities. Our financing activities for each of the periods listed above primarily relate to the funding of the investing activities discussed above. To fund these expenditures we made borrowings under our available debt facilities, including borrowings from PAA, and received capital contributions from our equity owners.

Capital Requirements

     We use cash primarily for our acquisition activities, internal growth projects and distributions paid to our unitholders and general partner. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations and the financing activities discussed above.

     Estimated Capital Expenditures. Excluding acquisitions, we estimate we will spend approximately $103 million in expansion capital, including capitalized interest, during 2011, of which approximately $16 million was incurred through March 31, 2011. Maintenance capital expenditures for 2011 are estimated to be approximately $0.8 million, of which approximately $0.1 million was incurred through March 31, 2011.

     Distributions to Unitholders and General Partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On May 13, 2011, we will pay a quarterly distribution of $0.3450 per unit on our common units and Series A subordinated units.

     We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however,

subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Contingencies

     See Note 6 to the condensed consolidated financial statements.

Commitments

     Contractual Obligations. In the ordinary course of doing business, we lease storage and transportation capacity from third parties, incur debt and interest payments and enter into purchase commitments in conjunction with our operations and our capital expansion program.

     The following table includes our best estimate of the amount and timing of the payments due under our contractual obligations as of March 31, 2011 (in millions):

		Total				2011				2012				2013				2014				2015				Thereafter
Long-term debt, interest and fees(1)		$	457			$	13			$	18			$	225			$	201			$	—			$	—
Leases — storage, transportation, other			32				9				11				6				4				2				—
Capital commitments			33				15				2				2				2				2				10
Subtotal			522				37				31				233				207				4				10
Natural gas purchases (2)			11				11				—				—				—				—				—
Total		$	533			$	48			$	31			$	233			$	207			$	4			$	10

     Letters of Credit. In connection with our use of certain leased storage and transportation assets, we have periodically provided certain suppliers with irrevocable standby letters of credit to secure our obligations for the purchase of these services. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the services are provided. Our $400.0 million senior unsecured revolving credit facility provides us with the ability to issue letters of credit. No letters of credit were outstanding as of March 31, 2011.

Off-Balance Sheet Arrangements

     We have no significant off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Recent Accounting Pronouncements

     See Note 2 to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates

     For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2010 Annual Report on Form 10K.

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.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

     The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included in our 2010 Annual Report on Form 10-K. There have been no material changes to that information other than as discussed below. Also, see Note 4 to the condensed consolidated financial statements for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

     The fair value of our outstanding natural gas derivatives as of March 31, 2011 was a net asset of approximately $1.8 million. A 10% increase in natural gas prices would result in a net asset of approximately $3.9 million. A 10% decrease in natural gas prices would result in a net liability of approximately $0.3 million.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

     We maintain written disclosure controls and procedures, “which we refer to as our “DCP”. Our DCP is designed to ensure that (i) information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (“the Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

     Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of the end of the period covered by this report, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

Changes in Internal Control over Financial Reporting

     In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting. Although we have made various enhancements to our controls, there have been no changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Certifications

     The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

PART II.
OTHER INFORMATION

Item 1. Legal Proceedings

     We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. Also, see Note 6 to the condensed consolidated financial statements for additional discussion regarding legal proceedings.

Item 1A. Risk Factors

     For a discussion regarding our risk factors, see Item 1A of our 2010 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     On February 8, 2011, in connection with the Southern Pines Acquisition, we completed the sale in a private placement of approximately 17.4 million Partnership common units to third-party purchasers and approximately 10.2 million Partnership common units to PAA for total proceeds of approximately $600 million, including PAA’s proportionate general partner contribution. We entered into Registration Rights Agreements with the third-party purchasers providing them with certain rights relating to registration of the common units under the Securities Act. The sale of the common units was made in reliance upon the exemption from the registration requirements of the Securities Act contained in Section 4(2) thereof.

Item 3. Defaults Upon Senior Securities

     None.

Item 4. [Removed and Reserved]

Item 5. Other Information

     None.

Item 6. Exhibits

2.1		—		Purchase and Sale Agreement dated December 28, 2010 by and among SGR Holdings, L.L.C., Southern Pines Energy Investment Co., LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 30, 2010).
2.2*		—		Amendment dated May 2, 2011 to Purchase and Sale Agreement dated December 28, 2010.
3.1		—		Certificate of Limited Partnership of PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).
3.2		—		Second Amended and Restated Agreement of Limited Partnership of PAA Natural Gas Storage, L.P. dated August 16, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on August 20, 2010).
3.3		—		Certificate of Formation of PNGS GP LLC (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).
3.4		—		Amended and Restated Limited Liability Company Agreement of PNGS GP LLC dated May 5, 2010 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q filed on August 6, 2010).
4.1		—		Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 30, 2010).
4.2		—		Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 20, 2011).

10.1		—		Common Unit Purchase Agreement dated December 23, 2010 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 30, 2010).
10.2		—		Common Unit Purchase Agreement dated January 19, 2011 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 20, 2011).
10.3		—		Note Payable to PAA dated February 9, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 14, 2011).
10.4		—		First Amendment to Credit Agreement dated as of March 10, 2011, by and among PAA Natural Gas Storage, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by referenced to Exhibit 10.1 to the Current Report on Form 8-K filed on March 15, 2011).
31.1*		—		Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
31.2*		—		Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
32.1*		—		Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.
32.2*		—		Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

SIGNATURES

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

EXHIBIT INDEX

2.1		—		Purchase and Sale Agreement dated December 28, 2010 by and among SGR Holdings, L.L.C., Southern Pines Energy Investment Co., LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 30, 2010).
2.2*		—		Amendment dated May 2, 2011 to Purchase and Sale Agreement dated December 28, 2010.
3.1		—		Certificate of Limited Partnership of PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).
3.2		—		Second Amended and Restated Agreement of Limited Partnership of PAA Natural Gas Storage, L.P. dated August 16, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on August 20, 2010).
3.3		—		Certificate of Formation of PNGS GP LLC (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).
3.4		—		Amended and Restated Limited Liability Company Agreement of PNGS GP LLC dated May 5, 2010 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q filed on August 6, 2010).
4.1		—		Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 30, 2010).
4.2		—		Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 20, 2011).
10.1		—		Common Unit Purchase Agreement dated December 23, 2010 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 30, 2010).
10.2		—		Common Unit Purchase Agreement dated January 19, 2011 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 20, 2011).
10.3		—		Note Payable to PAA dated February 9, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 14, 2011).
10.4		—		First Amendment to Credit Agreement dated as of March 10, 2011, by and among PAA Natural Gas Storage, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by referenced to Exhibit 10.1 to the Current Report on Form 8-K filed on March 15, 2011).
31.1*		—		Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
31.2*		—		Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).
32.1*		—		Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.
32.2*		—		Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.