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

Commission file number: 1-34722

PAA Natural Gas Storage, L.P.

(Exact name of registrant as specified in its charter)

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

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

     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 No

     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 August 2, 2010, there were 31,584,529 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: June 30, 2010 and December 31, 2009			3
Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 2010 and 2009			4
Condensed Consolidated Statement of Changes in Partners’ Capital and Members’ Capital: For the six months ended June 30, 2010			5
Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 2010 and 2009			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. Derivative Instruments and Risk Management Activities			8
4. Debt			11
5. Commitments and Contingencies			12
6. Partners’ Capital and Distributions			12
7. Comprehensive Income			15
8. Net Income per Limited Partner Unit			15
9. Equity Compensation Plans			16
10. Related Party Transactions			18
11. Reporting Segment			19
12. Subsequent Events			20
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			21
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			30
Item 4. CONTROLS AND PROCEDURES			30
PART II. OTHER INFORMATION			31
Item 1. LEGAL PROCEEDINGS			31
Item 1A. RISK FACTORS			31
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			31
Item 3. DEFAULTS UPON SENIOR SECURITIES			31
Item 4. [REMOVED AND RESERVED]			32
Item 5. OTHER INFORMATION			32
Item 6. EXHIBITS			32
SIGNATURES			33
EX-3.4
EX-10.9
EX-10.10
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidated Balance Sheets
(in thousands, except units)

		June 30,				December 31,
		2010				2009
		(unaudited)
ASSETS
Current assets
Cash and cash equivalents		$	1,532			$	3,124
Accounts receivable			8,002				6,439
Natural gas imbalance receivables			1,400				400
Other current assets			6,666				2,280
Total current assets			17,600				12,243
Property and equipment
Property and equipment			860,698				816,267
Less: Accumulated depreciation, depletion and amortization			(8,457	)			(3,004	)
Property and equipment, net			852,241				813,263
Other assets
Base gas			37,497				27,927
Goodwill and intangibles, net			48,521				46,974
Total other assets, net			86,018				74,901
Total assets		$	955,859			$	900,407
LIABILITIES, PARTNERS’ CAPITAL AND MEMBERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities		$	19,981			$	14,034
Natural gas imbalance payables			1,400				400
Accrued income and other taxes			820				1,610
Total current liabilities			22,201				16,044
Long-term liabilities
Note payable to PAA			—				450,523
Long-term debt under credit facility			204,500				—
Other long-term liabilities			561				1,096
Total long-term liabilities			205,061				451,619
Total liabilities			227,262				467,663
Commitments and contingencies (Note 5)
Partners’ capital and members’ capital
Common unitholders (31,584,529 units issued and outstanding at June 30, 2010)			478,254				—
Subordinated unitholders (25,434,351 units issued and outstanding at June 30, 2010)			238,454				—
General partner			12,248				—
Members’ capital			—				432,744
Accumulated other comprehensive loss			(359	)			—
Total partners’ capital and members’ capital			728,597				432,744
Total liabilities, partners’ capital and members’ capital		$	955,859			$	900,407

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

Condensed Consolidated Statements of Operations
(in thousands, except per unit data)

		Three Months Ended June 30,									Six Months Ended June 30,
		2010					2009				2010					2009
		PNG					PNG Predecessor				PNG					PNG Predecessor
		(See Note 1)					(See Note 1)				(See Note 1)					(See Note 1)
		(unaudited)									(unaudited)
Revenues
Firm storage services		$	23,611				$	17,560			$	42,284				$	30,672
Hub services			1,280					952				2,936					2,506
Other			(733	)				598				1,143					1,291
Total revenues			24,158					19,110				46,363					34,469
Costs and expenses
Storage related costs			4,963					2,649				11,523					6,668
Other operating costs (except those shown below)			1,420					1,840				3,424					3,568
Fuel expense			533					608				1,054					1,776
General and administrative expenses			3,740					1,522				7,754					2,781
Depreciation, depletion and amortization			3,515					3,578				6,456					6,167
Total costs and expenses			14,171					10,197				30,211					20,960
Operating income			9,987					8,913				16,152					13,509
Other income/(expense)
Interest expense, net of capitalized interest			(2,754	)				(2,929	)			(5,791	)				(3,676	)
Interest income			—					41				1					126
Income tax expense			—					(140	)			—					(354	)
Gain on interest rate swaps			—					172				—					336
Other income (expense)			(1	)				(3	)			(7	)				(16	)
Net income		$	7,232				$	6,054			$	10,355				$	9,925
Calculation of Limited Partner Interest in Net Income: (1)
Net income		$	4,927					n/a			$	4,927					n/a
Less general partner interest in net income			99					n/a				99					n/a
Limited partner interest in net income		$	4,828					n/a			$	4,828					n/a
Net income per limited partner unit (basic and diluted) (1)
Common and Series A subordinated units (2)		$	0.11					n/a			$	0.11					n/a
Limited partner units outstanding(1)
Common and Series A subordinated units (2) (Basic)			45,519					n/a				45,519					n/a
Common and Series A subordinated units (2) (Diluted)			45,525					n/a				45,525					n/a

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

Condensed Consolidated Statement of Changes in Partners’ Capital and Members’ Capital
(unaudited)
(in thousands)

						Partners’ Capital																Accumulated
						Limited Partners																Other
		Members’								Subordinated								General				Comprehensive
		Capital				Common				Series A				Series B				Partner				Loss				Total
Balance at December 31, 2009		$	432,744			$	—			$	—			$	—			$	—			$	—			$	432,744
Net income attributable to the period from January 1, 2010 through May 4, 2010			5,428				—				—				—				—				—				5,428
Extinguishment of related party note payable to PAA			16,375				—				—				—				—				—				16,375
Contribution of net assets to PAA Natural Gas Storage, L.P.			(454,547	)			205,422				158,088				78,888				12,149				—				—
Issuance of common units to public, net of offering and other costs			—				268,161				—				—				—				—				268,161
Equity compensation expense			—				140				—				—				—				—				140
Modification of LTIP awards			—				1,181				—				—				—				—				1,181
Net income attributable to the period from May 5, 2010 through June 30, 2010			—				3,350				1,478				—				99				—				4,927
Net deferred loss on cash flow hedges			—				—				—				—				—				(359	)			(359	)
Balance at June 30, 2010		$	—			$	478,254			$	159,566			$	78,888			$	12,248			$	(359	)		$	728,597

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

		Six Months Ended June 30,
		2010					2009
		PNG					PNG Predecessor
		(See Note 1)					(See Note 1)
		(unaudited)					(unaudited)
Cash flows from operating activities
Net income		$	10,355				$	9,925
Adjustments to reconcile to cash flow from operations
Depreciation, depletion and amortization			6,456					6,167
Non-cash change in fair market value of derivative instruments			435					(335	)
Non-cash interest expense on borrowings from parent, net			5,081					—
Change in assets and liabilities
Accounts receivable and other assets			(1,978	)				(186	)
Accounts payable and accrued liabilities			4,214					(1,335	)
Net cash provided by operating activities			24,563					14,236
Cash flows from investing activities
Additions to property and equipment			(43,447	)				(36,705	)
Cash paid for base gas			(8,578	)				—
Other investing activities			4					177
Net cash used in investing activities			(52,021	)				(36,528	)
Cash flows from financing activities
Repayments on term loan agreement			—					(1,225	)
Borrowings on revolving credit facility, net			204,500					33,500
Borrowings from parent			24,000					—
Repayment of borrowings from parent			(468,363	)				—
Net proceeds from issuance of common units			268,161					—
Costs incurred in connection with financing arrangements			(2,432	)				(4,639	)
Contributions from members			—					8,500
Distributions to members			—					(8,500	)
Net cash provided by financing activities			25,866					27,636
Net increase/(decrease) in cash and cash equivalents			(1,592	)				5,344
Cash and cash equivalents
Beginning of period			3,124					32,650
End of period		$	1,532				$	37,994
Cash paid for interest, net of amounts capitalized		$	711				$	3,911
Cash paid for income taxes		$	—				$	795
Non-cash items
Change in non-cash asset purchases included in accounts payable		$	(3,590	)			$	4,106
Non-cash interest capitalized on borrowings from parent		$	5,130				$	—

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

Notes to the Condensed Consolidated Financial Statements
(unaudited)

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 two natural gas storage facilities located in Louisiana and Michigan.

     Our Pine Prairie facility is a recently constructed, high-deliverability salt cavern natural gas storage complex located in Evangeline Parish, Louisiana. As of June 30, 2010, Pine Prairie had a total working gas storage capacity of approximately 24.0 billion cubic feet (“Bcf”) in three caverns. Our Bluewater facility is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. As of June 30, 2010, Bluewater had a total working gas storage capacity of approximately 26.0 Bcf in two depleted reservoirs.

     As further discussed in Note 6, 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 on May 5, 2010, 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. For periods prior to our initial public offering, the accompanying condensed consolidated financial statements of PNG reflect the predecessor financial statements of the Partnership, which are based on the historical ownership percentages of PAA and its subsidiaries in the PNGS operations that were contributed to the Partnership in conjunction with the IPO. Prior to the IPO, the financial statements of the Partnership consisted of total assets of $1,000 and the Partnership had not conducted any activity since its formation on January 15, 2010. The accompanying condensed consolidated financial statements, to the extent they relate to periods prior to the IPO, have been prepared from the separate financial records maintained by PNGS or its predecessor, as applicable, and may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership had operated separately during those periods. As of June 30, 2010, PAA owned approximately 77.0% of the equity interests in the Partnership including our 2.0% general partner interest and limited partner interests consisting of 18,106,529 common units, 13,934,351 Series A subordinated units and 11,500,000 Series B subordinated units.

     On September 3, 2009, PAA became the sole owner of PNGS by acquiring Vulcan Capital’s 50.0% interest in PNGS (“PAA Ownership Transaction”) for an aggregate purchase price of $215.0 million. Although PNGS continued as the same legal entity after the PAA Ownership Transaction, all of its assets and liabilities were adjusted to fair value at the time of the transaction in accordance with push-down accounting requirements. The remeasurement of PNGS’s assets and liabilities to fair value resulted in changes in carrying value for certain of PNGS’s assets and liabilities. The changes in carrying value are summarized as follows (in thousands):

PP&E, net		$	153,800
Base gas			(38,338	)
Goodwill			(61,398	)
Other long term assets			(4,546	)
		$	49,518

     As a result of the push-down accounting requirements applied in conjunction with the PAA Ownership Transaction, the financial information of PNG for periods preceding (designated as “PNG Predecessor”) and succeeding (designated as “PNG”) the PAA Ownership Transaction have been prepared under two different cost bases of accounting. Where applicable, a vertical line separates financial information for periods preceding and succeeding the PAA Ownership Transaction to highlight the fact that such information was prepared under different bases of accounting.

     The accompanying condensed consolidated interim financial statements should be read in conjunction with the Partnership’s final prospectus dated April 29, 2010 (the “Final Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-164492). These financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission (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 interim periods have been reflected. The condensed balance sheet data as of December 31, 2009 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. The results of operations for the three and six months ended June 30, 2010 should not be taken as indicative of 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.

     Subsequent events have been evaluated through the financial statements issuance date and have been included in Note 12.

     During the quarter ended June 30, 2010, we purchased approximately 1.0 Bcf of natural gas for approximately $4.6 million for use in the dewatering of our Pine Prairie facility. This gas, which was acquired for operational purposes, is reflected as a component of other current assets in our accompanying condensed consolidated balance sheet as of June 30, 2010. We anticipate that this gas will be sold upon completion of dewatering procedures. In July 2010, we entered into derivative instruments, which were designated as cash flow hedges, to manage our exposure to changes in natural gas prices associated with this anticipated sale.

Standards Adopted as of January 1, 2010

     In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance that requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest(s) provide a controlling financial interest in a variable interest entity (“VIE”). This analysis identifies the primary beneficiary of a VIE as the enterprise that has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could potentially be significant to the VIE. This guidance also (i) requires such assessments to be ongoing, (ii) amends certain guidance for determining whether an entity is a VIE and (iii) enhances disclosures that will provide users of financial statements with more transparent information regarding an enterprise’s involvement in a VIE. We adopted this guidance as of January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations or cash flows.

     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 additional disclosures regarding transfers into and out of Level 1 and Level 2 measurements and requires a gross presentation of activities within the Level 3 roll forward. This guidance was effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance, which is effective for the first interim or annual reporting period beginning after December 15, 2009, as of January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations, or cash flows. We will adopt the guidance that will be effective for annual reporting periods beginning after December 15, 2010 on January 1, 2011. We do not expect that adoption of this guidance will have any material impact on our financial position, results of operations, or cash flows.

     From time to time, we may utilize derivative instruments to (i) manage our price exposure associated with anticipated purchases of natural gas, (ii) economically hedge the intrinsic 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 certain commodity risks inherent in our business which can be summarized into the following two categories:

     Intrinsic Value of Storage Facilities — The capacity of our natural gas storage facilities may be fully committed in future periods through contractual arrangements with customers. When our storage capacity is fully committed, we no longer have the ability to participate in market upside associated with widening time spreads in the natural gas market. We may utilize natural gas derivatives to mitigate the potential opportunity cost associated with fully committing our storage capacity in future periods consistent with our risk management policies, objectives and limits. During the fourth quarter of 2009, in connection with the execution of three-year leases covering 3.0 Bcf of storage capacity, we entered into a seasonal natural gas calendar spread position consisting of New York Mercantile Exchange (“NYMEX”) futures with a notional volume of approximately 3.0 Bcf. In the aggregate, these derivatives, which consist of offsetting purchases and sales between two different months, confine our exposure to the price spreads between such months and do not result in exposure to outright price movements. During the second quarter of 2010, we closed out these positions at a realized loss of approximately $0.8 million.

     Anticipated Purchases 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 June 30, 2010, we have a long futures position of approximately 1.0 Bcf consisting of NYMEX futures and a long call option position of approximately 0.7 Bcf. Such positions were entered into during the first quarter of 2010.

Interest Rate Risk Hedging

     Prior to the PAA Ownership Transaction, we had previously entered into a series of interest rate swap agreements that were designated as cash flow hedges. These interest rate swaps were utilized to mitigate exposure to changes in cash flows associated with variable rate interest payments on certain debt obligations. In conjunction with the PAA Ownership Transaction, all of the associated debt obligations were settled and all of these interest rate swap agreements were terminated. Subsequent to the PAA Ownership Transaction, we have not entered into any additional interest rate swap agreements.

Summary of Financial Statement Impact

     Derivatives that qualify for hedge accounting are designated as cash flow hedges and the corresponding 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 unrealized losses of approximately $1.0 million and $0.4 million during the three and six months ended June 30, 2010, respectively, associated with our 3.0 Bcf natural gas calendar spread position, which was closed in June 2010 and did not qualify for hedge accounting. Such losses are reflected as a component of other revenues in our accompanying condensed consolidated statements of operations. During the three and six months ended June 30, 2009, we did not have any derivative positions which did not qualify for hedge accounting.

     Our earnings were not impacted by derivatives that were classified as cash flow hedges during the three and six months ended June 30, 2010.

     A summary of the impact of our derivative activities in cash flow hedging relationships recognized in earnings for the three and six months ended June 30, 2009 is as follows (in thousands, losses designated in parenthesis):

				Three Months Ended
				June 30, 2009
				Amount of Gain/(Loss)				Amount of Gain/(Loss)
				Reclassified from AOCI				Recognized in Income
				into Income (Effective				on Derivatives
		Location of Gain/(Loss)		Portion)(1)				(Ineffective Portion)(2)				Total
Interest Rate Derivatives		Interest expense		$	(2,373	)		$	—			$	(2,373	)
		Gain on interest rate swaps			—				172				172
Total				$	(2,373	)		$	172			$	(2,201	)

				Six Months Ended
				June 30, 2009
				Amount of Gain/(Loss)				Amount of Gain/(Loss)
				Reclassified from AOCI				Recognized in Income
				into Income (Effective				on Derivatives
		Location of Gain/(Loss)		Portion)(1)				(Ineffective Portion)(2)				Total
Interest Rate Derivatives		Interest expense		$	(4,532	)		$	—			$	(4,532	)
		Gain on interest rate swaps			—				336				336
Total				$	(4,532	)		$	336			$	(4,196	)

     The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of June 30, 2010 (in thousands):

Asset Derivatives

Liability Derivatives

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

Commodity derivatives designated as hedging instruments

Other long-term liabilities

$

186

Other long-term liabilities

$

545

     The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of December 31, 2009 (in thousands):

Asset Derivatives

Liability Derivatives

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

Commodity derivatives not designated as hedging instruments

Accounts payable and Accrued liabilities

$

37

Accounts payable and Accrued liabilities

$

407

     As of June 30, 2010, there was a net loss of approximately $0.4 million deferred in AOCI (no amounts were deferred in AOCI as of December 31, 2009). The deferred loss in AOCI is expected to be reclassified to future earnings contemporaneously with the earnings recognition of the underlying hedged transactions. The underlying hedged transactions are for 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 do not expect to reclassify any of this deferred loss into earnings over the next twelve months. The deferred loss is based on market prices as of June 30, 2010, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. During the three and six months ended June 30, 2010 and the three and six

months ended June 30, 2009, 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. As of June 30, 2010 and December 31, 2009, we did not have an obligation to pay or a right to receive cash collateral associated with our derivatives. At June 30, 2010 and December 31, 2009, 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 June 30, 2010 and December 31, 2009, all of our derivatives consisted of exchange-traded instruments within active markets. We therefore consider all of our derivatives as of June 30, 2010 and December 31, 2009 to be Level 1 fair value measurements.

4. Debt

     In April 2010, subject to consummation of our initial public offering, we entered into a three-year, $400.0 million senior unsecured revolving credit facility that matures in May 2013. This credit facility, which bears interest based on LIBOR plus an applicable margin (approximately 2.8% in the aggregate as of June 30, 2010) determined based on funded debt-to-EBITDA levels (as defined in the credit agreement), may be expanded to $600.0 million, subject to additional lender commitments and with approval of the administrative agent for the credit facility.

     This credit facility restricts, among other things, the Partnership’s ability to make distributions of available cash to unitholders if any default or event of default, as defined in the credit agreement, exists or would result therefrom. In addition, the credit facility contains restrictive covenants, including those that restrict our ability to incur additional indebtedness, engage in certain transactions with affiliates, grant (or permit to exist) liens or enter into certain restricted contracts, make any material change to the nature of our business, make a disposition of all or substantially all of our assets or enter into a merger, consolidate, liquidate, wind up or dissolve. Also, the credit facility contains certain financial covenants which, among other things, requires us to maintain a debt-to-EBITDA coverage ratio that will not be greater than 4.75 to 1.00 on outstanding debt (5.50 to 1.00 on all outstanding debt during an acquisition period) and also requires that we maintain an interest-to-EBITDA coverage ratio that will not be less than 3.00 to 1.00, as such terms are defined in the credit agreement. As of June 30, 2010, we were in compliance with the covenants contained in our credit agreement.

     We incurred approximately $2.4 million of costs, reflected as a component of goodwill and intangibles, net in our accompanying condensed consolidated balance sheet as of June 30, 2010, in connection with the establishment of our senior unsecured revolving credit facility. Such costs were capitalized and will be amortized over the term of the credit facility using the straight-line method of amortization. Amortization of debt issuance costs is reflected as a component of depreciation, depletion and amortization expenses in our accompanying condensed consolidated statements of operations. At June 30, 2010, we estimate that the carrying value of outstanding borrowings on our credit facility approximates fair value as interest rates reflect current market rates.

     Our credit facility includes the ability to issue letters of credit. As of June 30, 2010, we had no outstanding letters of credit.

     As of December 31, 2009, approximately $450.5 million was outstanding on a related party note payable to PAA, entered into in conjunction with the PAA Ownership Transaction. The note accrued interest and was payable in kind, at a rate of 6.5%. As discussed in Note 6, net proceeds of the IPO, along with borrowings under the new credit facility, were used to repay approximately $468.4 million of the related party note, which included additional borrowings and interest accrued through May 5, 2010. The remaining balance of approximately $16.4 million was extinguished and treated as a capital contribution by PAA as part of PAA’s initial investment in the Partnership.

     Capitalized interest for the three and six months ended June 30, 2010, was $1.2 million and $5.5 million, respectively, and $2.5 million and $6.9 million for the three and six months ended June 30, 2009, respectively.

5. 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 June 30, 2010, 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.

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.

6. Partners’ Capital and Distributions

Initial Public Offering

     As discussed in Note 1, immediately prior to the closing of the IPO on May 5, 2010, PAA and its subsidiaries contributed 98.0% of the equity interests in PNGS to the Partnership in exchange for certain limited partner interests. In addition, PNGS GP LLC, the general partner of the Partnership and a subsidiary of PAA, contributed 2.0% of the equity interests in PNGS to the Partnership in exchange for a 2.0% general partner interest in the Partnership as well as all of our incentive distribution rights, which entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3375 per quarter.

     On May 5, 2010, the Partnership issued approximately 13.5 million common units to the public, which included approximately 1.8 million common units issued pursuant to the full exercise of the underwriters’ over-allotment option, through an underwritten initial public offering representing an approximate 23.0% limited partner interest in us. Upon closing of the initial public offering and after giving effect to the exercise of the underwriters’ over-allotment option, PAA and its subsidiaries retained an approximate 77.0% equity interest in the Partnership, consisting of approximately 18.1 million common units, approximately 13.9 million Series A subordinated units, 11.5 million Series B subordinated units and a 2.0% general partner interest in us. Total proceeds of the initial public offering were approximately $289.8 million. After deducting underwriting discounts and commissions and direct offering expenses, net proceeds of the offering were approximately $268.2 million. Net proceeds of the offering, along with $200.0 million of borrowings under the Partnership’s new $400.0 million senior unsecured revolving credit facility, were used to repay intercompany indebtedness owed to PAA. The remaining balance of the intercompany indebtedness owed to PAA of approximately $16.4 million was extinguished and treated as a capital contribution and part of PAA’s initial investment in the Partnership.

     From the closing of our initial public offering on May 5, 2010 through June 30, 2010, there were 31,584,529, 13,934,351 and 11,500,000 issued and outstanding common, Series A subordinated and Series B subordinated units, respectively.

Series A subordinated units

     All of our Series A subordinated units are owned by PAA. The principal difference between our common units and Series A subordinated units is that in any quarter during the subordination period, holders of the Series A subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Series A subordinated units will not accrue arrearages.

     At any time on or after June 30, 2013, the subordination period for the Series A subordinated units will end on the first business day following the quarter in respect of which we have, for each of three consecutive, non-overlapping four quarter periods (i) generated from distributable cash flow at least $1.35 (the minimum quarterly distribution on an annualized basis) on the weighted average number of outstanding common units and Series A subordinated units on a fully diluted basis, plus the corresponding distribution on our general partner’s 2.0% interest and (ii) paid from available cash at least $1.35 on all outstanding common units and Series A subordinated units, plus the corresponding distribution on our general partner’s 2.0% interest. Additionally, at any time on or after June 30, 2011, if we have, for a period of four consecutive quarters (i) generated from distributable cash flow at least $0.5063 per quarter (150.0% of the minimum quarterly distribution, which is approximately $2.03 on an annualized basis) on the weighted average number of outstanding common units and Series A subordinated units on a fully diluted basis, plus the corresponding distributions on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights and (ii) paid from available cash at least $0.5063 per quarter (150.0% of the minimum quarterly distribution, which is approximately $2.03 on an annualized basis) on all outstanding common units and Series A subordinated units, plus the corresponding distribution on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights, the subordination period will end.

     In addition, the subordination period will end upon the removal of our general partner other than for cause, if the units held by our general partner and its affiliates are not voted in favor of such removal.

     When the subordination period ends, all Series A subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

Series B subordinated units

     All of our Series B subordinated units are owned by PAA. The Series B subordinated units will not be entitled to participate in our quarterly distributions until they convert into Series A subordinated units or common units.

     The Series B subordinated units will convert into Series A subordinated units upon satisfaction of the following operational and financial conditions:

	•		4,600,000 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 29.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.36 per unit (representing an annualized distribution of $1.44 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and (c) we make a quarterly distribution of available cash of at least $0.36 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights;
	•		3,833,333 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 35.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.3825 per unit (representing an annualized distribution of $1.53 per unit) on the weighted average number of outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior bullet, and (c) we make a quarterly distribution of available cash of at least $0.3825 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights; and
	•		3,066,667 Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 41.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $0.4075 per unit (representing an annualized distribution of $1.63 per unit) on the weighted average number of

outstanding common units and Series A subordinated units and all of such Series B subordinated units and, if any, the Series B subordinated units described in the prior two bullets, and (c) we make a quarterly distribution of available cash of at least $0.4075 per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units and the corresponding distributions on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights.

     Our general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the operational tests described above are satisfied prior to or during the two-quarter period applicable to the financial tests described above, the holder of the Series B subordinated units subject to conversion will be entitled to receive the quarterly distribution payable with respect to the second quarter of such two-quarter period. In all other circumstances, where the operational tests are satisfied following the two-quarter period applicable to the financial tests, the holder of the Series B subordinated units subject to conversion will be entitled to receive any distribution payable following the satisfaction of such operational tests.

     Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled.

     Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.

     If at the time the above operational and financial tests are satisfied, the subordination period has already ended and all outstanding Series A subordinated units have converted into common units, the Series B subordinated units will instead convert directly into common units on a one-for-one basis and participate in the quarterly distribution payable to common units.

Distributions

     Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2010, we distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. The minimum quarterly distribution is pro-rated for the period beginning on May 5, 2010 and ending on June 30, 2010. Please refer to Note 12 for information regarding the quarterly distribution for the period ending June 30, 2010.

     Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:

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

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

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

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

7. 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 Ended									Six Months Ended
		June 30,									June 30,
		2010					2009				2010					2009
		PNG					PNG Predecessor				PNG					PNG Predecessor
		(See Note 1)					(See Note 1)				(See Note 1)					(See Note 1)
Net income		$	7,232				$	6,054			$	10,355				$	9,925
Net derivative gain/(loss) on cash flow hedges			30					—				(359	)				—
Total comprehensive income		$	7,262				$	6,054			$	9,996				$	9,925

8. 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 period from May 5, 2010 (the closing of our initial public offering) through June 30, 2010 (amounts in thousands, except per unit data):

		May 5, 2010 to
		June 30, 2010
Net income		$	4,927
Less: General partner’s incentive distribution paid (1)			—
Less: General partner 2.0% ownership			99
Net income available to limited partners		$	4,828
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income amongst limited partner interests:
Net income allocable to common units		$	3,350
Net income allocable to Series A subordinated units			1,478
Net income allocable to Series B subordinated units (2)			—
Net income available to limited partners		$	4,828
Denominator:
Basic weighted average number of limited partner units outstanding: (2)(3)(4)
Common units			31,585
Series A subordinated units			13,934
Series B subordinated units			11,500
Diluted weighted average number of limited partner units outstanding: (2)(3)(4)
Common units			31,591
Series A subordinated units			13,934
Series B subordinated units			11,500
Basic and diluted net income per limited partner unit: (2)(3)(4)
Common units		$	0.11
Series A subordinated units		$	0.11
Series B subordinated units		$	—

9. Equity Compensation Plans

Long Term Incentive Plan (“LTIP”)

     On April 27, 2010, PNGS GP LLC, the general partner of the Partnership, adopted the PAA Natural Gas Storage, L.P. 2010 Long Term Incentive Plan (the “2010 LTIP Plan”) for the employees, directors and consultants of our general partner and its affiliates, including PAA, who perform services on our behalf. The 2010 LTIP Plan consists of restricted units, phantom units, unit options, unit appreciation rights and unit awards. The 2010 LTIP Plan limits the number of common units that may be delivered pursuant to awards under the plan to 3,000,000 units.

     During the second quarter of 2010, 658,500 phantom units were granted under the 2010 LTIP Plan to directors, officers and other employees, a portion of which were granted upon conversion of outstanding awards denominated in common units of PAA. Of this total, (i) 30,000 phantom units will vest annually in 25.0% increments and have an automatic re-grant feature such that as they vest, an equivalent amount is granted; (ii) 326,000 phantom units will vest in one-third increments upon the later of (a) the May 2012 distribution date and the date we pay a quarterly distribution of at least $0.3875, (b) the May 2013 distribution date and the date we pay a quarterly distribution of at least $0.4500, and (c) the May 2014 distribution date and the date we pay a quarterly distribution of at least $0.4750; and (iii) 302,500 phantom units will vest in 25.0% increments in connection with the conversion of our Series A subordinated units and the conversion of each of the three outstanding tranches of our Series B subordinated units (see Note 6). Distribution equivalent rights were also awarded with respect to 342,500 of the phantom unit grants.

     Our LTIP activity for awards issued under the 2010 LTIP Plan is summarized in the following table (in thousands, except per unit data):

						Weighted Average
						Grant Date
		Units				Fair Value per Unit
Outstanding, May 5, 2010			—			$	—
Granted (1)			659				19.72
Vested			—				—
Cancelled or forfeited			—				—
Outstanding, June 30, 2010			659			$	19.72

     Prior to our initial public offering and adoption of the 2010 LTIP Plan, certain of our officers and other individuals providing direct services on our behalf were granted LTIP awards under LTIP plans sponsored by PAA’s general partner (“PAA LTIP Awards”). Such awards, which allow settlement in cash or PAA common units upon vesting at the election of PAA’s general partner, generally contained performance conditions based on the attainment of certain annualized PAA distribution levels or the attainment of specific PNG EBITDA levels and vested upon the later of a certain date or the attainment of such levels. In connection with the second quarter grants under the 2010 LTIP Plan, substantially all of the then outstanding liability-classified PAA LTIP awards held by PNG management were converted to equity-classified PNG common unit denominated awards, which resulted in a reclassification to Partners’ capital of approximately $1.2 million of compensation expense recognized on such awards through the modification date. As of June 30, 2010, we are obligated to reimburse PAA, upon vesting, for approximately 25,000 units of currently outstanding PAA LTIP Awards. We reimbursed PAA approximately $154,000 for PAA LTIP awards which vested during the three months ended June 30, 2010.

     The fair value of our liability classified awards is calculated based on the closing price of the underlying PAA or PNG units as of each balance sheet date and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients. The fair value of our equity classified awards is calculated based on the closing price of our common units as of the respective grant dates and adjusted for the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipient. The fair value of these awards is recognized as compensation expense over the service period. For awards with performance conditions, we recognize compensation expense only if the achievement of the performance condition is considered probable and amortize that expense over the service period. When awards with performance conditions that were not previously considered probable of occurring become probable of occurring, we incur additional equity compensation expense necessary to adjust the life-to-date accrued expense associated with these awards. Substantially all of our equity compensation expense is reflected as a component of general and administrative expenses in our accompanying condensed consolidated statements of operations.

     Our accrued liability at June 30, 2010 related to all outstanding liability classified LTIP awards is approximately $1.3 million. We have also recognized $1.3 million in Partners’ capital related to all outstanding equity classified LTIP awards. Compensation expense recognized on 2010 LTIP Plan awards reflects our assessment that an annualized PNG distribution of $1.45 and the conversion of our Series A subordinated units and the first tranche of our Series B subordinated units are probable of occurring. We have not deemed an annualized distribution of more than $1.45 to be probable as of June 30, 2010, nor have we deemed the conversion of the second or the third tranche of our Series B subordinated units to be probable as of June 30, 2010.

Other Consolidated Equity Compensation Information

     The table below summarizes the expense recognized and the value of vested awards (settled both in PAA units and cash) related to our equity compensation plans (in thousands):

		Three Months Ended
		June 30,
		2010
		Liability Awards				Equity Awards
Equity compensation expense		$	288			$	140
LTIP cash settled vestings		$	154			$	—

		Six Months Ended
		June 30,
		2010
		Liability Awards				Equity Awards
Equity compensation expense		$	703			$	140
LTIP cash settled vestings		$	154			$	—

     Based on the June 30, 2010 fair value measurement and probability assessment regarding future distributions, we expect to recognize approximately $2.7 million of additional expense over the estimated service period of our outstanding awards related to the remaining unrecognized fair value. For our liability classified awards, this estimate is based on the fair value of the outstanding awards as of June 30, 2010. For our equity classified awards, this estimate is based on the grant date fair value of such awards. Actual amounts may materially differ as a result of a change in the market price of our units and/or probability assessment regarding future distributions. We estimate that the remaining fair value will be recognized in expense as shown below (in thousands):

		Equity Compensation
		Plan Fair Value
Year		Amortization(1)
2010 (2)		$	521
2011			1,300
2012			598
2013 and thereafter			318
Total		$	2,737

10. 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 and six months ended June 30, 2010, were approximately $5.9 million and $11.4 million, respectively; and $2.7 million and $5.5 million for the three and six months ended June 30, 2009, respectively. Of these amounts approximately $1.0 million and $1.8 million and $0.4 million and $0.8 million, during the three and six month periods ended June 30, 2010 and 2009, 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 June 30, 2010 and December 31, 2009, PNG had a liability to PAA of approximately $1.7 million and $0.8 million, respectively, included in accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheet.

As of June 30, 2010 and December 31, 2009, PNG’s obligation for unvested equity-based compensation awards was approximately $1.3 million and $1.8 million, respectively. Approximately $1.1 million and $0.7 million of such amounts were reflected in accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009, respectively, with the remaining balances included as a component of other long-term liabilities at each respective date.

     In conjunction with our initial public offering in May 2010, we entered into an omnibus agreement with PAA and certain of its affiliates, pursuant to which we agreed upon certain aspects of our relationship with them, including, among other things (1) the provision by PAA’s general partner to us of certain general and administrative services and our agreement to reimburse PAA’s general partner for such services, (2) the provision by PAA’s general partner of such personnel as may be necessary to operate and manage our business, and our agreement to reimburse PAA’s general partner for the expenses associated with such personnel, (3) certain indemnification obligations, and (4) our use of the name “PAA” and related marks. Under this agreement, PAA indemnifies us against certain environmental liabilities, tax matters, and title or permitting defects generally for a period of three years after the closing of our initial public offering. The environmental indemnifications are subject to a cap of $15.0 million and require us to pay the first $250.0 thousand of costs incurred. In addition, we have indemnified PAA against any losses, costs or damages incurred by PAA or its general partner that are attributable to the ownership and operation of our assets following the close of the initial public offering.

     In conjunction with our initial public offering in May 2010, we entered into a tax sharing agreement with PAA, pursuant to which we and PAA agreed on the method of allocation among us and our subsidiaries, on the one hand, and PAA and its subsidiaries (other than us and our subsidiaries) on the other, of the responsibilities, liabilities and benefits relating to any taxes for which a combined return is filed for taxable periods including or beginning on May 5, 2010. Subsequent to the PAA Ownership Transaction, income tax expense allocated to us under applicable allocation methodologies has not been material.

11. Reporting Segment

     We manage our operations through two operating segments, Bluewater 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 investment. We have aggregated our two 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 and amortization as we believe that depreciation 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									Six Months Ended
		June 30,									June 30,
		2010					2009				2010					2009
		PNG					PNG Predecessor				PNG					PNG Predecessor
		(See Note 1)					(See Note 1)				(See Note 1)					(See Note 1)
Revenues (1)		$	24,158				$	19,110			$	46,363				$	34,469
Adjusted EBITDA		$	14,159				$	12,896			$	23,075				$	20,426
Maintenance capital		$	18				$	105			$	217				$	214
Long-lived assets (1), (2)		$	938,259				$	796,285			$	938,259				$	796,285
Total assets (2)		$	955,859				$	854,960			$	955,859				$	854,960

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

		Three Months Ended									Six Months Ended
		June 30,									June 30,
		2010					2009				2010					2009
		PNG					PNG Predecessor				PNG					PNG Predecessor
		(See Note 1)					(See Note 1)				(See Note 1)					(See Note 1)
Adjusted EBITDA		$	14,159				$	12,896			$	23,075				$	20,426
Selected items impacting Adjusted EBITDA:
Equity compensation charge			(428	)				(195	)			(843	)				(304	)
Mark-to-market of open derivative positions			(230	)				—				370					—
Depreciation, depletion and amortization			(3,515	)				(3,578	)			(6,456	)				(6,167	)
Interest expense			(2,754	)				(2,929	)			(5,791	)				(3,676	)
Income tax expense			—					(140	)			—					(354	)
Net Income		$	7,232				$	6,054			$	10,355				$	9,925

12. Subsequent Events

     On July 13, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.2114 per unit on all common units and Series A subordinated units, which amount is equivalent to the minimum quarterly distribution of $0.3375 per unit prorated from the May 5, 2010 closing date of the IPO through June 30, 2010. The cash distribution is expected to be paid on August 13, 2010 to unitholders of record at the close of business on August 3, 2010. See Note 6 for further information regarding the distribution.

     In July of 2010, the Board of Directors of PNG’s general partner authorized the issuance of 165,000 Class B Units (“PNGS Class B Units”) of PNGS GP LLC (PNG’s general partner) in order to create long term incentives for our management. The entire economic burden of the PNGS Class B Units, which will be equity classified, will be borne solely by our general partner and will not impact our cash or our units outstanding. We will recognize the grant date fair value of the PNGS Class B Units as a compensation expense over the service period, with such expense recognized as a capital contribution. We will not be obligated to reimburse our general partner for such costs and any distributions made on the PNGS Class B Units will not reduce the amount of cash available for distribution to our unitholders.

     Approximately 98,000 PNGS Class B units were granted in July 2010 and the remaining units are reserved for future grants. The PNGS Class B Units earn the right to participate in distributions (i.e, become “earned”) in 25% increments 180 days following the payment by PNG of quarterly distributions that equate to annualized distribution levels of $2.00, $2.30, $2.50 and $2.70. When PNGS Class B Units become earned units, they will participate in quarterly distributions paid to our general partner in excess of $2,500,000. In addition, 50% of the applicable earned units vest immediately upon becoming earned units and the remaining 50% vest on the fifth anniversary of the date of grant. If PNGS Class B Units become earned units after the fifth anniversary of the date of grant, 100% of such units will vest immediately upon becoming earned units. Assuming all 165,000 PNGS Class B Units were granted and earned, the maximum participation rate would be 6% of PNG’s quarterly general partner distribution in excess of $2,500,000.

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

     The following discussion analyzes the financial condition and results of operations of the Partnership, including periods prior to our initial public offering on May 5, 2010. Such analysis should be read in conjunction with the historical audited financial statements, and the notes thereto, included in the final prospectus dated April 29, 2010 (the “Final Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-164492). For ease of reference, we refer to the historical financial results of PAA Natural Gas Storage, LLC (“PNGS”) prior to our initial public offering as being “our” historical financial results. Unless the context otherwise requires, references to “we,” “us,” “our,” and “the Partnership” are intended to mean the business and operations of PAA Natural Gas Storage, L.P. (the “Partnership” or “PNG”) and its consolidated subsidiaries since May 5, 2010. When used in the historical context (i.e. prior to May 5, 2010), these terms are intended to mean the business and operations of PNGS. Unless the context indicates otherwise, for purposes of the following discussion “PAA” refers to Plains All American Pipeline, L.P. (the owner of our general partner) (NYSE: PAA) and its consolidated subsidiaries and affiliates other than the Partnership and its general partner and their respective subsidiaries.

     For periods prior to our initial public offering, the historical condensed consolidated financial statements included in this Quarterly Report on Form 10-Q are those of PNGS. Through the contribution of all of the equity interest of PNGS to us in connection with the closing of our initial public offering on May 5, 2010, all of the assets, liabilities and operations of PNGS were contributed directly or indirectly by PAA to the Partnership. For further discussion regarding the Partnership’s initial public offering, please see Notes 1 and 6 to the condensed consolidated financial statements.

     As further discussed in Note 1 to the condensed consolidated financial statements, PNGS became a wholly owned subsidiary of PAA in September 2009 when PAA acquired an additional 50.0% interest in PNGS from Vulcan Capital (the “PAA Ownership Transaction”). Application of push-down accounting from PAA to PNGS resulted in a change in carrying value for certain assets and liabilities of PNGS. Accordingly, the following discussion refers to Predecessor and Successor periods, which relate to the accounting periods preceding and succeeding the PAA Ownership Transaction. In the presentation set forth below, the Predecessor and Successor periods have been separated by a vertical line in order to highlight the fact that the financial information for such periods was prepared under two different cost bases of accounting.

Overview of Operating Results, Capital Spending and Significant Activities

     During the second quarter of 2010, we received the necessary regulatory approvals to place our third cavern into service at our Pine Prairie facility. This 10.0 Bcf cavern increases the Partnership’s working gas storage capacity at Pine Prairie by approximately 70.0% from 14.0 Bcf to 24.0 Bcf and increases the Partnership’s aggregate working capacity by 25.0% from 40.0 Bcf to approximately 50.0 Bcf.

     In June 2010, we established a commercial optimization group. Without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year firm storage contracts at attractive rates, our dedicated commercial marketing group will capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Consistent with PAA’s experience in marketing crude oil and refined products, we believe a dedicated commercial marketing group that has a consistent presence in our markets will enhance our ability to properly price our storage and hub service offerings and will increase our cash flow by capitalizing on volatility and inefficiencies in the natural gas markets. We will conduct these commercial activities within pre-defined risk parameters, and our general policy will be (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.

		Three Months Ended									Favorable/ (Unfavorable)								Six Months Ended									Favorable/ (Unfavorable)
		June 30,									Variance								June 30,									Variance
		2010					2009												2010					2009
		(Successor)					(Predecessor)				$				%				(Successor)					(Predecessor)				$				%
Revenues
Firm Storage Services
Reservation fees		$	22,192				$	16,097			$	6,095				38	%		$	39,685				$	28,400			$	11,285				40	%
Cycling fees and fuel-in-kind			1,419					1,463				(44	)			-3	%			2,599					2,272				327				14	%
Hub Services			1,280					952				328				34	%			2,936					2,506				430				17	%
Other			(733	)				598				(1,331	)			-223	%			1,143					1,291				(148	)			-11	%
Total revenue			24,158					19,110				5,048				26	%			46,363					34,469				11,894				35	%
Storage related costs			(4,963	)				(2,649	)			(2,314	)			-87	%			(11,523	)				(6,668	)			(4,855	)			-73	%
Operating costs (except those shown below)			(1,420	)				(1,840	)			420				23	%			(3,424	)				(3,568	)			144				4	%
Fuel expense			(533	)				(608	)			75				12	%			(1,054	)				(1,776	)			722				41	%
General and administrative expenses			(3,740	)				(1,522	)			(2,218	)			-146	%			(7,754	)				(2,781	)			(4,973	)			-179	%
Interest income and other income (expense), net			(1	)				210				(211	)			-100	%			(6	)				446				(452	)			-101	%
Equity compensation expense			428					195												843					304
Mark-to-market of open derivative positions			230					—												(370	)				—
Adjusted EBITDA		$	14,159				$	12,896			$	1,263				10	%		$	23,075				$	20,426			$	2,649				13	%
Reconciliation to net income
Depreciation, depletion and amortization			(3,515	)				(3,578	)			63				-2	%			(6,456	)				(6,167	)			(289	)			5	%
Interest expense, net of capitalized interest			(2,754	)				(2,929	)			175				-6	%			(5,791	)				(3,676	)			(2,115	)			58	%
Income tax expense			—					(140	)			140				-100	%			—					(354	)			354				-100	%
Equity compensation expense			(428	)				(195	)											(843	)				(304	)
Mark-to-market of open derivative positions			(230	)				—												370					—
Net income		$	7,232				$	6,054			$	1,178				19	%		$	10,355				$	9,925			$	430				4	%
Operating Data:
Net revenue margin (1)			19,195					16,461				2,734				17	%			34,840					27,801				7,039				25	%
Operating expenses / G&A / Other			(5,036	)				(3,565	)			(1,471	)			41	%			(11,765	)				(7,375	)			(4,390	)			60	%
Adjusted EBITDA		$	14,159				$	12,896			$	1,263				10	%		$	23,075				$	20,426			$	2,649				13	%
Average working storage capacity (Bcf)			50.0					40.0				10.0				25	%			45.0					35.0				10.0				29	%
Average Monthly Operating Metrics ($/Mcf)
Net Revenue Margin		$	0.13				$	0.14			$	(0.01	)			-7	%		$	0.13				$	0.13			$	—				0	%
Operating expenses / G&A / Other		$	(0.03	)			$	(0.03	)		$	—				0	%		$	(0.04	)			$	(0.03	)		$	(0.01	)			33	%
Adjusted EBITDA		$	0.10				$	0.11			$	(0.01	)			-9	%		$	0.09				$	0.10			$	(0.01	)			-10	%

     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 June 30, 2010 (the “Successor Second Quarter of 2010”) when compared to the three months ended June 30, 2009 (the “Predecessor Second Quarter of 2009”). The primary reasons for such increase are the placement into service of an additional 10.0 Bcf of working gas storage capacity at our Pine Prairie facility in April 2010 and additional leasing of third party storage and transportation assets impacting the Successor Second Quarter of 2010 relative to the Predecessor Second Quarter of 2009. 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 for the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009, primarily due to the placement into service of an additional 10.0 Bcf of working gas capacity at our Pine Prairie facility in April 2010, which resulted in approximately $5.1 million in incremental revenues generated by our Pine Prairie facility for the Successor Second Quarter of 2010. Revenues from firm storage reservation fees were also positively impacted by loan activities and additional revenue generating activities associated with increased amounts 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 were relatively constant in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009. An increase in the period-over-period average natural gas price of approximately 19.0% in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009 increased our fuel-in-kind revenues. Such increase was approximately offset by a lower volume of natural gas injections into our facilities during 2010 as compared to 2009 which was generally the result of warmer weather conditions increasing the market demand for natural gas that would otherwise have been injected into storage.
	•		Hub services — Hub services increased in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009. This increase primarily related to increased wheeling and balancing services as a result of utilizing leased transportation capacity during the 2010 Successor period to augment the service capabilities of our owned assets. See “— Storage related costs” below. 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. In the Successor Second Quarter of 2010, market conditions were generally less favorable for the value of hub services activities as compared to the Predecessor Second Quarter of 2009.
	•		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 Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009 by approximately $0.3 million. The decrease was a result of lower production in 2010 versus the prior year period, partially offset by higher average realized prices in 2010. The Successor Second Quarter of 2010 also includes a loss of approximately $1.0 million associated with changes in the fair market value of a natural gas storage related futures derivative position. No such derivative financial instruments were in place during the Predecessor Second Quarter of 2009. During the second quarter of 2010, we closed out these positions at a realized loss of approximately $0.8 million.
	•		Storage related costs — Storage related costs increased in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009 due to an increase in the amount of storage and transportation capacity leased from third parties. In addition, we experienced higher costs as a result of increased loan transactions in 2010 as compared to 2009.
		Other Costs and Expenses. The significant variances are discussed further below:
	•		Operating costs — Field operating costs decreased in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009. The decrease is primarily related to a revision in our estimate of previously recognized property tax expense of approximately $0.4 million.
	•		Fuel expense — Fuel expense decreased in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009 primarily due to a decrease in fuel volumes used of approximately 26%. Such decrease was primarily driven by operational improvements in managing customer movements and was partially offset by increases in fuel prices in the 2010 period over the 2009 period.
	•		General and administrative expenses — General and administrative expenses increased in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009. The increase resulted from the continued expansion of our business and growth in personnel costs, including equity compensation expense, along with additional administrative costs incurred associated with being a public company. General and administrative expense for the 2010 period also reflects non-recurring costs of approximately $0.7 million associated with the start-up of our commercial optimization group and general and administrative expenses associated with our initial public offering efforts. Additionally, expense for the 2010 period reflects an increase of approximately $0.3 million due to an increased cost allocation from PAA as a result of PAA personnel devoting additional time and effort to our operations and an agreement in place with our former joint venture partner prior to the PAA Ownership Transaction which did not allow PAA to charge us for executive officer expenses during the prior year period.
	•		Interest income and other income (expense), net — Interest income and other income (expense), net for the Predecessor Second Quarter of 2009 was comprised primarily of interest income and ineffectiveness associated with an interest rate swap agreement. The reduction of interest income and other income (expense), net for the Successor Second Quarter of 2010 was driven by the termination of the swap agreement in conjunction with the PAA Ownership Transaction and, following the PAA Ownership Transaction, a significant reduction in the amount of cash balances carried by us, which resulted in a decrease in interest income.
	•		Depreciation, depletion and amortization — Depreciation, depletion and amortization expense decreased in the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009. Depreciation expense increased by approximately $0.4 million. The increase resulted primarily from an increased amount of depreciable assets resulting from our internal growth projects (including the additional 10.0 Bcf of storage capacity placed into service in April 2010) along with an increase in the basis of property and equipment as a result of fair value adjustments recorded in connection with the PAA Ownership Transaction. These increases were partially offset by adjustments to the estimated useful lives of our property and equipment made in conjunction with the PAA Ownership Transaction, which lengthened the estimated useful lives of most of our more significant components of property and equipment. The increase in depreciation expense was partially offset by decreases in depletion and amortization expense in 2010 as compared to 2009. Depreciation, depletion and amortization expense includes amortization of debt issue costs and intangibles of $0.6 million and $0.7 million, in 2010 and 2009, respectively.

	•		Interest expense, net of capitalized interest — Interest expense decreased in the Successor Second Quarter of 2010 when compared to the Predecessor Second Quarter of 2009. The decrease principally resulted from decreases in both average debt balances outstanding and average interest rates in 2010 as compared to 2009. Capitalized interest was approximately $1.2 million and $2.5 million in the 2010 and 2009 periods, respectively. Capitalized interest was impacted from the decreases in both average debt balances outstanding and average interest rates along with an increase in the in-service capacity at our Pine Prairie facility period over period.
	•		Income tax expense — As a partnership, and then as a publicly traded partnership subsequent to our IPO, we are not subject to U.S. federal income taxes, rather, the tax effect of our operations is passed through to our partners and now our unitholders. Our income tax expense consists principally of state income taxes calculated on an apportionment basis. The income tax expense is lower in the Successor Second Quarter of 2010 when compared to the Predecessor Second Quarter of 2009 due to the combined impact of the expansion in our areas of operations outside of the applicable state, and ownership changes that resulted in our inclusion as a consolidated subsidiary of PAA.

Six Months Ended June 30, 2010 as Compared to the Six Months Ended June 30, 2009

     Revenues, Volumes and Storage Related Costs. As noted in the table above, our total revenue and storage related costs increased during the six months ended June 30, 2010 (the “Successor Six Month Period of 2010”) when compared to the six months ended June 30, 2009 (the “Predecessor Six Month Period of 2009”). The primary reasons for such increases are the placement into service of an additional 8.0 Bcf and 10.0 Bcf of working gas storage capacity at our Pine Prairie facility in April 2009 and 2010, respectively, and additional leasing of third party storage and transportation assets impacting the Successor Six Month Period of 2010 relative to the Predecessor Six Month Period of 2009. 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 for the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009, primarily due to the placement into service of an additional 8.0 Bcf and 10.0 Bcf of working gas capacity at our Pine Prairie facility in April 2009 and 2010, respectively, which resulted in approximately $9.5 million in incremental revenues generated by our Pine Prairie facility for the Successor Six Month Period of 2010. Revenues from firm storage reservation fees were also positively impacted by loan activities and additional revenue generating activities associated with increased amounts 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 Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009. The increase was primarily driven by an increase in the period-over-period average natural gas price of approximately 17.0% in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009, which increased our fuel-in-kind revenues. Such increase was partially offset by a lower volume of natural gas injections into our facilities during the Successor Second Quarter of 2010 as compared to the Predecessor Second Quarter of 2009 which was generally the result of warmer weather conditions increasing the market demand for natural gas that would otherwise have been injected into storage.
	•		Hub services — Hub services increased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009. This increase primarily related to increased wheeling and balancing services as a result of utilizing leased transportation capacity during the 2010 Successor period to augment the service capabilities of our owned assets. See “— Storage related costs” below. 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. In the Successor Six Month Period of 2010, market conditions were generally less favorable for the value of hub services activities as compared to the Predecessor Six Month Period of 2009.
	•		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 increased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009 by approximately $0.3 million. The increase reflected higher average realized prices in 2010 versus the prior year period, partially offset by a decrease in production in 2010. The Successor Six Month Period of 2010 also includes losses of approximately $0.4 million associated with changes in the fair market value of a natural gas storage related futures derivative position. No such derivative financial instruments were in place during the Predecessor Six Month Period of 2009. During the second quarter of 2010, we closed out these positions at a realized loss of approximately $0.8 million.

•

Storage related costs — Storage related costs increased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009 due to an increase in the amount of storage and transportation capacity leased from third parties. In addition, we experienced higher costs as a result of increased loan transactions in 2010 as compared to 2009.

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

	•		Operating costs — Field operating costs decreased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009. The decrease is primarily related to a revision in our estimate of previously recognized property tax expense of approximately $0.4 million. Such decrease was partially offset by an increase in maintenance activities during the first quarter of 2010 as compared to the first quarter of 2009.
	•		Fuel expense — Fuel expense decreased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009 primarily due to a decrease in fuel volumes used of approximately 25.0%. Such decrease was primarily driven by operational improvements in managing customer movements and was partially offset by increases in fuel prices in the 2010 period over the 2009 period. Additionally, the Predecessor Six Month Period of 2009 includes a lower of cost or market charge of approximately $0.2 million which was recognized during the first quarter of 2009.
	•		General and administrative expenses — General and administrative expenses increased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009. The increase resulted from the continued expansion of our business and growth in personnel costs, including equity compensation expense, along with additional administrative costs incurred associated with being a public company. General and administrative expense for the 2010 period reflects approximately $2.1 million associated with acquisition evaluation expenses, the start-up of our commercial optimization group and general and administrative expenses associated with our initial public offering efforts. Additionally, expense for the 2010 period reflects an increase of approximately $0.8 million due to an increased cost allocation from PAA as a result of PAA personnel devoting additional time and effort to our operations and an agreement in place with our former joint venture partner prior to the PAA Ownership Transaction which did not allow PAA to charge us for executive officer expenses during the prior year period.
	•		Interest income and other income (expense), net — Interest income and other income (expense), net for the Predecessor Six Month Period of 2009 was comprised primarily of interest income and ineffectiveness associated with an interest rate swap agreement. The reduction of interest income and other income (expense), net for the Successor Six Month Period of 2010 was driven by the termination of the swap agreement in conjunction with the PAA Ownership Transaction and, following the PAA Ownership Transaction, a significant reduction in the amount of cash balances carried by us, which resulted in a decrease in interest income.
	•		Depreciation, depletion and amortization — Depreciation, depletion and amortization expense increased in the Successor Six Month Period of 2010 as compared to the Predecessor Six Month Period of 2009. Depreciation increased by approximately $0.9 million, primarily as a result of an increased amount of depreciable assets resulting from our internal growth projects (including the additional 8.0 Bcf and 10.0 Bcf of storage capacity placed into service in April 2009 and April 2010, respectively) along with an increase in the basis of property and equipment as a result of fair value adjustments recorded in connection with the PAA Ownership Transaction. These increases were partially offset by adjustments to the estimated useful lives of our property and equipment made in conjunction with the PAA Ownership Transaction, which lengthened the estimated useful lives of most of our more significant components of property and equipment. The increase in depreciation expense was partially offset by decreases in depletion and amortization expense. Depreciation, depletion and amortization expense includes amortization of debt issue costs and intangibles of $1.0 million and $1.3 million, in 2010 and 2009, respectively.
	•		Interest expense, net of capitalized interest — Interest expense increased in the Successor Six Month Period of 2010 when compared to the Predecessor Six Month Period of 2009. The increase principally resulted from increases in both average debt balances outstanding and average interest rates in 2010 as compared to 2009. Capitalized interest was approximately $5.5 million and $6.9 million in the 2010 and 2009 periods, respectively, with increases in both average debt balances outstanding and average interest rates being partially offset by an increase in in-service capacity at our Pine Prairie facility period over period.
	•		Income tax expense — As a partnership, and then as a publicly traded partnership subsequent to our IPO, we are not subject to U.S. federal income taxes, rather, the tax effect of our operations is passed through to our partners and now our unitholders. Our income tax expense consists principally of state income taxes calculated on an apportionment basis. The income tax expense is lower in the Successor Six Month Period of 2010 when compared to the Predecessor Six Month Period of 2009 due to the combined impact of the expansion in our areas of operations outside of the applicable state, and ownership changes that resulted in our inclusion as a consolidated subsidiary of PAA.

 

 

     The market for hub services activities softened during late 2009 and the first half of 2010, primarily due to reduced spread and basis differentials resulting from what we believe to be a combination of factors, including weather, the impact of shale gas production, and pipeline infrastructure additions. Market conditions weakened further in the third quarter with seasonal spreads, as reflected by the October 2010 to January 2011 NYMEX spread, decreasing to a recent level of $0.46 per mcf on July 30, 2010, which is a five-year low on a prompt basis.

 

     We expect that the adverse market conditions may be temporary, but if such conditions continue, in addition to adversely affecting hub services activities, they may adversely impact lease rates our customers are willing to pay for firm storage leases for new capacity under construction and, to a lesser extent, 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. We believe our asset base, business model, and strong financial capabilities position us to actively pursue acquisitions and to continue to execute our organic growth program, which includes the ability to construct incremental storage capacity at low costs, which we expect will generate attractive economic returns even at lower lease rates. However, we can provide no assurance that our operating and financial results won’t be adversely impacted, or that our acquisition and organic growth efforts will be successful. See the “Risk Factors” section of the Final Prospectus.

Liquidity and Capital Resources

Overview

     Our ability to finance our operations, including funding capital expenditures, making acquisitions, making cash distributions and satisfying any indebtedness obligations, will depend on our ability to generate cash in the future. Our ability to generate cash remains subject to a number of factors, some of which extend beyond our control. See “Risk Factors” in the Final Prospectus for further discussion regarding such risks that may affect our liquidity and capital resources.

     Prior to September 3, 2009, our activities were conducted in a joint venture arrangement. Accordingly, cash flow from operations, borrowings under our Predecessor’s credit facilities and contributions from equity owners were our primary sources of liquidity. On September 3, 2009, PAA became the sole owner of PNGS by acquiring Vulcan Capital’s 50.0% interest in us. In conjunction with that transaction, PNGS entered into a note payable to PAA for approximately $421.0 million. The proceeds of the note payable were used to repay amounts borrowed under our Predecessor’s credit facilities and related interest rate swaps. Such credit facilities were terminated following their repayment. The note payable to PAA accrued interest, which was payable in kind, at a rate of 6.5%.

     In April 2010, subject to consummation of the Partnership’s initial public offering, the Partnership entered into a three-year, $400.0 million senior unsecured revolving credit facility. This credit facility, which bears interest based on LIBOR plus an applicable margin determined based on funded debt-to-EBITDA levels, may be expanded to $600.0 million with approval of the administrative agent for the credit facility. This credit facility restricts, among other things, the Partnership’s ability to make distributions of available cash to unitholders if any default or event of default, as defined in the agreement, exists or would result therefrom. In addition, the credit facility contains restrictive covenants, including those that restrict our ability to incur additional indebtedness, engage in transactions with affiliates, grant (or permit to exist) liens or enter into certain restricted contracts, make any material change to the nature of our business, make a disposition of all or substantially all of our assets or enter into a merger, consolidate, liquidate, wind up or dissolve. Also, the credit facility contains certain financial covenants requiring us to maintain certain financial ratios related to our consolidated EBITDA, consolidated interest charges and consolidated funded indebtedness, as such terms are defined in the credit agreement.

     In conjunction with the closing of our initial public offering on May 5, 2010, the Partnership borrowed approximately $200.0 million under the $400.0 million senior unsecured revolving credit facility. These borrowings, along with the net proceeds from the initial public offering, were used to repay a portion of the note payable to PAA. The portion of the note not repaid was extinguished and treated as a capital contribution and part of PAA’s investment in the Partnership. At June 30, 2010, we had $204.5 million outstanding under this facility. The extent to which we can borrow against the remaining $195.5 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 June 30, 2010, we were in compliance with the covenants, including the financial ratios, contained in our credit agreement. Based on the most restrictive covenant, at June 30, 2010 our total available debt would be limited to approximately $275.0 million of the $400.0 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 for certain capital investments we may make in the future, including for acquisitions and certain capital expenditures related to our Pine Prairie expansion. We believe our credit facility and available debt capacity is adequate to fund our current capital program.

     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.

     Congress recently 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 the various aspects of the Act have not yet been issued. We are currently reviewing the provisions of this legislation and its potential impact on our business, and will continue to monitor the final rules and regulations as they develop.

Historical Cash Flow

     As of June 30, 2010, we had a working capital deficit of approximately $4.6 million. The following discussion summarizes our cash flow activity for the six months ended June 30, 2010 and 2009.

     The following table presents a summary of our cash flows for the six months ended June 30, 2010 and 2009 (in thousands):

		Six Months Ended June 30,
		2010					2009
		(Successor)					(Predecessor)
		(unaudited)					(unaudited)
Net cash provided by (used in):
Operating activities		$	24,563				$	14,236
Investing activities			(52,021	)				(36,528	)
Financing activities			25,866					27,636
Net increase/(decrease) in cash		$	(1,592	)			$	5,344
Adjusted EBITDA		$	23,075				$	20,426

     Operating Activities. Net cash provided by operating activities increased from approximately $14.2 million in the 2009 period to approximately $24.6 million. Approximately $5.1 million is due to interest expense on our intercompany note with PAA during the 2010 period that was payable in kind, whereas interest expense on debt outstanding during the 2009 period was paid in cash. Additionally, approximately $3.8 million of the change was due to changes in working capital items period over period.

     Investing Activities. Net cash used in investing activities consisted primarily of expansion capital expenditures associated with the expansion of our Pine Prairie facility during the 2010 and 2009 periods. Cash paid for expansion capital expenditures increased from approximately $36.5 million in the 2009 period to approximately $43.2 million in the 2010 period. Additionally, the 2010 period includes approximately $8.6 million cash paid for base gas purchases related to the 10.0 Bcf of working gas capacity placed into service at our Pine Prairie facility during the second quarter of 2010. No base gas purchases occurred during the 2009 period.

     Financing Activities. Net cash provided by financing consisted primarily of borrowings under debt facilities outstanding during each applicable period. During the 2009 period, net borrowings under our Predecessor’s credit facilities, which were terminated in conjunction with the PAA Ownership Transaction, were approximately $32.3 million. Additionally, approximately $4.6 million of financing costs were paid during this period. During the 2010 period, intercompany borrowings from PAA were approximately $24.0 million. Net proceeds of $268.2 million from the IPO, along with borrowings of $200.0 million under the new credit facility, were used to repay intercompany borrowings of approximately $468.4 million to PAA. Interest expense on our intercompany borrowings from PAA for the 2010 period was approximately $5.1 million, which is net of approximately $5.1 million of capitalized interest.

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. We estimate we will spend approximately $95 million in expansion capital, including capitalized interest, during 2010, of which approximately $53.8 million was incurred through June 30, 2010. Maintenance capital expenditures for 2010 are estimated to be approximately $0.6 million, of which approximately $0.2 million was incurred through June 30, 2010.

     Distributions to Unitholders and General Partner. We intend to distribute 100.0% 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 at the discretion of our general partner for future requirements. We expect to pay a minimum quarterly distribution of $0.3375 per common unit and Series A subordinated unit for each complete calendar quarter, which equates to

approximately $15.7 million per full quarter or approximately $62.7 million per full year, based on the number of common units, Series A subordinated units and general partner interest outstanding immediately after the closing of our initial public offering on May 5, 2010. Our Series B subordinated units will not be entitled to receive distributions until they convert to Series A subordinated units or common units, as applicable. Such conversion is subject to the achievement of (i) certain operational targets at our Pine Prairie facility and (ii) certain distribution requirements in the future. Our minimum quarterly distribution for the quarter ending June 30, 2010 will be pro-rated for the period from May 5, 2010 to June 30, 2010 (See Note 12). For further information regarding distributions, please read “Our cash distribution policy and restrictions on distributions” in the Final Prospectus.

     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.

     See Note 5 to the condensed consolidated financial statements.

     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 June 30, 2010 (in millions):

		Total				2010				2011				2012				2013				2014				Thereafter
Long-term debt(1)		$	223.2			$	3.3			$	6.6			$	6.6			$	206.7			$	—			$	—
Leases — storage, transportation, other			45.9				9.6				13.1				10.5				6.2				4.5				2.0
Purchase obligations			33.7				16.5				1.6				1.9				1.9				1.9				9.9
Other long-term liabilities			1.2				0.8				0.3				0.1				—				—				—
Total		$	304.0			$	30.2			$	21.6			$	19.1			$	214.8			$	6.4			$	11.9