Edgar Filing: PAA NATURAL GAS STORAGE LP

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e10vq

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

For the quarterly period ended June 30, 2011


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

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). þ 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):

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

PAA NATURAL GAS STORAGE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:		3
Condensed Consolidated Balance Sheets: June 30, 2011 and December 31, 2010		3
Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 2011 and 2010		4
Condensed Consolidated Statement of Changes in Partners’ Capital: For the six months ended June 30, 2011		5
Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 2011 and 2010		6
Notes to the Condensed Consolidated Financial Statements:		7
1. Organization, Nature of Operations and Basis of Presentation		7
2. Recent Accounting Pronouncements		8
3. Acquisition		9
4. Derivative Instruments and Risk Management Activities		11
5. Debt		14
6. Commitments and Contingencies		14
7. Partners’ Capital and Distributions		15
8. Comprehensive Income		16
9. Net Income per Limited Partner Unit		16
10. Equity Compensation Plans		19
11. Related Party Transactions		20
12. Reporting Segment		20
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		22
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		33
Item 4. CONTROLS AND PROCEDURES		33
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS		35
Item 1A. RISK FACTORS		35
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		35
Item 3. DEFAULTS UPON SENIOR SECURITIES		35
Item 4. [REMOVED AND RESERVED]		35
Item 5. OTHER INFORMATION		35
Item 6. EXHIBITS		35
SIGNATURES		37
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PAA Natural Gas Storage, L.P. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except units)


	June 30,			December 31,
	2011			2010
Assets
Current assets
Cash and cash equivalents	$	376		$	346
Restricted cash		—			20,000
Accounts receivable		19,135			12,786
Natural gas imbalances receivable		1,500			1,200
Natural gas inventory		12,779			57
Other current assets		6,314			1,487

Total current assets		40,104			35,876

Property and equipment
Property and equipment		1,277,940			892,645
Less: Accumulated depreciation, depletion and amortization		(22,506	)		(14,837	)

Property and equipment, net		1,255,434			877,808

Other assets
Base gas		42,694			37,498
Goodwill		325,470			24,966
Intangibles, net		106,781			22,580
Other long term assets		157			—

Total other assets, net		475,102			85,044

Total assets	$	1,770,640		$	998,728


Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	34,024		$	12,806
Natural gas imbalances payable		1,500			1,200
Accrued taxes		1,723			1,009

Total current liabilities		37,247			15,015

Long-term liabilities
Note payable to PAA		200,000			—
Long-term debt under credit facility		226,100			259,900
Other long-term liabilities		178			423

Total long-term liabilities		426,278			260,323

Total liabilities		463,525			275,338
Commitments and contingencies (Note 6)
Partners’ capital
Common unitholders (59,184,450 units issued and outstanding at June 30, 2011)		1,048,679			474,489
Subordinated unitholders (25,434,351 units issued and outstanding at June 30, 2011)		232,566			236,853
General partner		27,203			13,637
Accumulated other comprehensive loss		(1,333	)		(1,589	)

Total partners’ capital		1,307,115			723,390

Total liabilities and partners’ capital	$	1,770,640		$	998,728

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

PAA Natural Gas Storage, L.P. and Subsidiaries

Condensed Consolidated Statements of Operations
(unaudited)

(in thousands, except per unit data)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2011			2010			2011			2010
Revenues
Firm storage services	$	35,415		$	23,611		$	64,539		$	42,284
Hub services		2,234			1,280			4,635			2,936
Natural gas sales		15,973			—			34,069			—
Other		742			(733	)		1,541			1,143

Total revenues		54,364			24,158			104,784			46,363

Costs and expenses
Storage related costs		4,331			4,963			10,138			11,523
Natural gas sales costs		15,133			—			32,732			—
Other operating costs (except those shown below)		2,915			1,420			6,002			3,424
Fuel expense		1,107			533			2,202			1,054
General and administrative expenses		4,641			3,740			13,825			7,754
Depreciation, depletion and amortization		8,940			3,515			15,409			6,456

Total costs and expenses		37,067			14,171			80,308			30,211

Operating income		17,297			9,987			24,476			16,152
Other income/(expense)
Interest expense, net of capitalized interest		(1,445	)		(2,754	)		(2,279	)		(5,791	)
Other income (expense)		17			(1	)		17			(6	)

Net income	$	15,869		$	7,232		$	22,214		$	10,355


Calculation of Limited Partner Interest in Net Income:
Net income ⁽¹⁾	$	15,869		$	4,927		$	22,214		$	4,927
Less general partner interest in net income		399			99			607			99

Limited partner interest in net income	$	15,470		$	4,828		$	21,607		$	4,828


Net income per limited partner unit
Common and Series A subordinated units ⁽²⁾ (Basic)	$	0.22		$	0.11		$	0.33		$	0.11
Common and Series A subordinated units ⁽²⁾ (Diluted)	$	0.22		$	0.11		$	0.33		$	0.11

Limited partner units outstanding
Common and Series A subordinated units ⁽²⁾(Basic)		71,119			45,519			65,325			45,519
Common and Series A subordinated units ⁽²⁾ (Diluted)		71,137			45,525			65,344			45,525


(1)		Amounts attributable to 2010 periods are reflective of general and limited partner interests in net income subsequent to closing of the Partnership’s initial public offering on May 5, 2010.

(2)		Excludes Series B subordinated units. See Note 9, “Net Income per Limited Partner Unit.”

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

PAA Natural Gas Storage, L.P. and Subsidiaries

Condensed Consolidated Statement of Changes in Partners’ Capital

(unaudited)

(in thousands)


	Partners’ Capital											Accumulated
	Limited Partners											Other
				Subordinated					General			Comprehensive
	Common			Series A			Series B		Partner			Gain/(Loss)			Total

Balance at December 31, 2010	$	474,489		$	135,062		$	101,791	$	13,637		$	(1,589	)	$	723,390
Net income		17,660			3,947			—		607			—			22,214
Issuance of common units, net of offering and other costs		587,407			—			—		12,000			—			599,407
Equity compensation expense		471			—			—		1,900			—			2,371
Distributions to unitholders and general partner		(31,317	)		(8,234	)		—		(941	)		—			(40,492	)
Distribution equivalent right payments		(31	)		—			—		—			—			(31	)
Net deferred gain on cash flow hedges		—			—			—		—			256			256

Balance at June 30, 2011	$	1,048,679		$	130,775		$	101,791	$	27,203		$	(1,333	)	$	1,307,115

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

PAA Natural Gas Storage, L.P. and Subsidiaries

Condensed Consolidated Statements of Cash Flows
(unaudited)

(in thousands)


	Six Months Ended
	June 30
	2011			2010
Cash flows from operating activities
Net income	$	22,214		$	10,355
Adjustments to reconcile to cash flow from operations
Depreciation, depletion and amortization		15,409			6,456
Equity compensation expense		2,658			843
Non-cash interest expense on borrowings from parent, net		—			5,081
Non-cash change in fair value of derivative instruments		(103	)		435
Changes in assets and liabilities, net of acquisitions
Accounts receivable and other assets		(5,397	)		(1,978	)
Accounts payable and accrued liabilities		5,997			3,371

Net cash provided by operating activities		40,778			24,563

Cash flows from investing activities
Additions to property and equipment		(41,610	)		(43,447	)
Cash paid in connection with acquisition, net of cash acquired		(744,069	)		—
Decrease in restricted cash		20,000			—
Cash paid for base gas		—			(8,578	)
Other investing activities		—			4

Net cash (used in) investing activities		(765,679	)		(52,021	)

Cash flows from financing activities
Borrowings on revolving credit facility		98,500			204,500
Repayments of borrowings on revolving credit facility		(132,300	)		—
Borrowings under note from PAA		200,000			24,000
Repayment of borrowings from parent		—			(468,363	)
Net proceeds from issuance of common units		587,407			268,161
Costs incurred in connection with financing arrangements		(153	)		(2,432	)
Contribution from general partner		12,000			—
Distributions paid to unitholders		(39,551	)		—
Distributions paid to general partner		(941	)		—
Distribution equivalent right payments		(31	)		—

Net cash provided by financing activities		724,931			25,866

Net increase (decrease) in cash and cash equivalents		30			(1,592	)
Cash and cash equivalents
Beginning of period		346			3,124

End of period	$	376		$	1,532


Cash paid for interest, net of amounts capitalized	$	2,303		$	711

Non-cash items
Change in non-cash asset purchases included in accounts payable	$	2,569		$	(3,590	)

Non-cash interest capitalized on borrowings from parent	$	—		$	5,130

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

PAA Natural Gas Storage, L.P. and Subsidiaries

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 three natural gas storage facilities located in Louisiana, Mississippi and Michigan. Our Pine Prairie and Southern Pines facilities are recently constructed, high-deliverability salt cavern natural gas storage complexes located in Evangeline Parish, Louisiana and Greene County, Mississippi, respectively. Our Bluewater facility is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. As of June 30, 2011, through these facilities, PNG had a total of seven operational salt storage caverns and two depleted reservoirs used for natural gas storage, with an aggregate owned working gas storage capacity of approximately 75 billion cubic feet (“Bcf”). During the second half of 2010, we formed PNG Marketing, LLC as a commercial optimization company. PNG Marketing engages in the purchase and sale of natural gas as well as leasing capacity and related services from third party and affiliated providers and engaging in related commercial natural gas marketing activities.

On May 5, 2010, the Partnership completed its initial public offering (“IPO”) pursuant to which PAA sold an approximate 23.0% limited partner interest in the Partnership to the public. Immediately prior to the closing of the IPO, PAA and certain of its consolidated subsidiaries contributed 100.0% of the equity interests in PAA Natural Gas Storage, LLC (“PNGS”), the predecessor of the Partnership, and its subsidiaries to the Partnership. As of June 30, 2011, PAA owned approximately 64.1% of the equity interests in the Partnership, including our 2.0% general partner interest and limited partner interests consisting of 28,214,198 common units, 11,934,351 Series A subordinated units and 13,500,000 Series B subordinated units.

The accompanying condensed consolidated interim financial statements include the accounts of PNG and its subsidiaries, all of which are wholly owned, and should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2010 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to the Partnership. The condensed balance sheet data as of December 31, 2010 was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. The results of operations for the three and six months ended June 30, 2011 should not be taken as indicative of the results to be expected for the full year.

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

Natural Gas Sales

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

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

Natural Gas Sales Costs

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

Inventory

Natural gas inventory owned by PNG Marketing is valued at the lower of cost or market, with cost determined using an average cost method within specified inventory pools. As of June 30, 2011, PNG owned approximately 3.0 Bcf of natural gas inventory with a carrying value of approximately $12.8 million.

Property and Equipment

During the six months ended June 30, 2011, we received cash of approximately $7.2 million under a state incentive program for jobs creation. This incentive payment, which was determined based on applicable capital expenditures, was accounted for as a refund of sales tax previously paid and reduced the carrying value of our applicable property and equipment.

2. Recent Accounting Pronouncements

Other than as discussed below and in our 2010 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the six months ended June 30, 2011 that are of significance or potential significance to us.

In December 2010, the FASB issued updated accounting guidance related to the calculation of the carrying amount of a reporting unit when performing the first step of a goodwill impairment test. More specifically, this update will require an entity to use an equity premise when performing the first step of a goodwill impairment test, and if a reporting unit has a zero or negative carrying amount, the entity must assess and consider qualitative factors to determine whether it is more likely than not that a goodwill impairment exists. The new accounting guidance is effective for public entities, for impairment tests performed during entities’ fiscal years (and interim periods within those years) that begin after December 15, 2010. Early application is not permitted. We adopted this guidance on January 1, 2011; however, as we currently do not have any reporting units with a zero or negative carrying amount, our adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In December 2010, the FASB issued updated accounting guidance to clarify that pro forma disclosures should be presented as if a business combination that is determined to be material on an individual or aggregate basis occurred at the beginning of the prior annual period for purposes of preparing both the current reporting period and the prior reporting period pro forma financial information. These disclosures should be accompanied by a narrative description about the nature and amount of material, nonrecurring pro forma adjustments. The new accounting guidance is effective for business combinations consummated in periods beginning after December 15, 2010 and should be applied prospectively as of the date of adoption. Early adoption is permitted. We adopted this guidance on January 1, 2011. Our adoption did not have a 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 a gross presentation of activities within the level 3 rollforward. This guidance was effective for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted this guidance on January 1, 2011. See Note 4 for additional disclosure. Our adoption did not have any material impact on our financial position, results of operations, or cash flows.

Accounting Pronouncements Not Yet Effective

In June 2011, the FASB issued new guidance regarding the presentation of comprehensive income. This guidance requires entities to present reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement in which the components of net income and components of other comprehensive income are presented. It also eliminates the current option under U.S. GAAP to present components of other comprehensive income within the statement of changes in

stockholders’ equity. The components of comprehensive income will be required to be presented within either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance is effective for interim and annual periods beginning after December 15, 2011, with earlier adoption permitted. Since this issuance only impacts the presentation of such financial information, adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued guidance to amend certain measurement and disclosure requirements related to fair value in an effort to improve consistency with international reporting standards. This guidance is effective prospectively for interim and annual reporting periods beginning after December 15, 2011, with earlier adoption prohibited. The adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows.

3. Acquisition

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

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

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


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

Total	$	752

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

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

During the six months ended June 30, 2011, we incurred approximately $4.1 million of acquisition-related costs associated with the Southern Pines Acquisition. Such costs are reflected as a component of general and administrative expenses in our condensed consolidated statement of operations.

Goodwill included in our condensed consolidated balance sheets was approximately $325 million and $25 million as of June 30, 2011 and December 31, 2010, respectively.

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

Pro Forma Results

Total revenues generated by our Southern Pines facility of approximately $12.5 million for the three months ended June 30, 2011 and approximately $18.2 million for the period from February 9, 2011 (date of acquisition) through June 30, 2011 are included in our condensed consolidated statement of operations for the three and six months ended June 30, 2011, respectively. Disclosure of the earnings of our Southern Pines facility since the acquisition date is not practicable as it is not being operated as a standalone subsidiary.

Selected unaudited pro forma results of operations for the six months ended June 30, 2011 and 2010, assuming the Southern Pines Acquisition had occurred on January 1, 2010, are presented below (in thousands, except per share amounts):


	Six Months Ended June 30,
	2011		2010
Total revenues	$	108,747	$	62,342
Net income⁽¹⁾	$	27,518	$	12,331
Limited partner interest in net income⁽²⁾	$	26,805	$	7,304
Net income per limited partner unit⁽³⁾
Basic	$	0.38	$	0.10
Diluted	$	0.38	$	0.10


(1)		Amount for the 2010 period includes approximately $4.1 million of acquisition costs associated with the Southern Pines Acquisition.

(2)		Amount for the 2010 period represents portion of net income attributable to limited partner interests for the period subsequent to the closing of our initial public offering on May 5, 2010.

(3)		Excludes Series B subordinated units. See Note 9, “Net Income per Limited Partner Unit.”

4. Derivative Instruments and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on commodity price changes. We use various derivative instruments to (i) manage our price exposure associated with anticipated purchases or sales of natural gas, (ii) economically hedge the value of our natural gas storage facilities and (iii) manage our exposure to interest rate risk. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking hedges. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of a hedge and on an ongoing basis, we assess whether the derivatives used in such hedging transactions are highly effective in offsetting changes in cash flows of hedged items. FASB guidance requires us to recognize changes in the fair value of derivative instruments currently in earnings unless the derivatives meet specific cash flow hedge accounting requirements, in which case the effective portion of changes in the fair value of cash flow hedges are deferred in accumulated other comprehensive income (“AOCI”) and reclassified into earnings when the underlying hedged transaction affects earnings.

Commodity Price Risk Hedging

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, 2011, we have a long futures position of approximately 0.7 Bcf, 3.0 Bcf of long swaps, and a long call option position of approximately 0.7 Bcf related to anticipated base gas purchases. Additionally, our dedicated commercial optimization company captures short-term market opportunities by leasing a portion of our owned or leased storage capacity and engaging in related commercial optimization activities. We use various derivatives, including index and basis swaps, to hedge anticipated purchases and sales of natural gas by our commercial optimization company. As of June 30, 2011, we have a short swap position of approximately 6.6 Bcf related to anticipated sales of natural gas, and an approximate 6.3 Bcf long swap position related to anticipated purchases of natural gas. Additionally, we have a net short calendar spread call option position of approximately 3.0 Bcf related to anticipated sales of natural gas. These calls are time spreads between two different months and other than for changes in the spreads, do not result in exposure to outright price movements.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge the underlying benchmark interest rate associated with debt outstanding under our credit facility. During June 2011, we entered into two interest rate swaps in order to fix the interest rate on a portion of our outstanding debt under our revolving credit facility. The swaps have an aggregate notional amount of $50 million with an average fixed rate of 1.06% and terminate in June 2014. These swaps are designated as cash flow hedges.

Summary of Financial Statement Impact

Derivatives that qualify for hedge accounting are generally designated as cash flow hedges. Changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in earnings in the periods during which the underlying hedged transaction impacts earnings. Derivatives that do not qualify or were not designated 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.

A summary of the impact of our derivative activities recognized in earnings for the three and six months ended June 30, 2011 is as follows (in thousands):


	Three Months Ended June 30, 2011
	Derivatives in Hedging			Derivatives not
Location of Gain/(Loss)	Relationships⁽¹⁾⁽²⁾			Designated as a Hedge⁽³⁾		Total
Commodity Derivatives
Natural Gas Sales	$	807		$	10	$	817
Other Revenues		(8	)		72		64

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	799		$	82	$	881


	Six Months Ended June 30, 2011
	Derivatives in Hedging		Derivatives not
Location of Gain/(Loss)	Relationships⁽¹⁾⁽²⁾		Designated as a Hedge⁽³⁾		Total
Commodity Derivatives
Natural Gas Sales	$	1,653	$	95	$	1,748
Other Revenues		31		72		103

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	1,684	$	167	$	1,851


(1)		Amounts reported as a component of Natural Gas Sales represent derivative gains and losses that were reclassified from AOCI to earnings during the period to coincide with the earnings impact of the respective hedged transaction.

(2)		Amounts reported as a component of Other Revenues represent the ineffective portion of our cash flow hedges recognized in earnings.

(3)		Includes realized and unrealized gains or losses for derivatives that did not qualify or were not designated for hedge accounting during the period.

During the three and six months ended June 30, 2010, our earnings were not impacted from derivatives activities in cash flow hedging relationships.

We recognized unrealized losses of approximately $1 million and $0.4 million during three and six months ended June 30, 2010, respectively, associated with a 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.

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of June 30, 2011 (in thousands):


	As of June 30, 2011
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity Derivatives	Other current assets	$	1,779	Other current assets	$	(4,800	)
	Other long-term assets		105			—
Interest Rate Derivatives	Other current assets		9			—
	Other long-term assets		22			—

Total Derivatives designated as hedging instruments		$	1,915		$	(4,800	)


	As of June 30, 2011
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity Derivatives	Other current assets	$	716	Other current assets	$	(753	)
	Other long-term assets		29			—

Total Derivatives designated as hedging instruments		$	745		$	(753	)



Total Derivatives		$	2,660		$	(5,553	)

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

As of December 31, 2010

Asset Derivatives

Liability Derivatives

Balance Sheet

Location

Fair Value

Location

Fair Value

Derivatives designated as hedging instruments:

Commodity Derivatives

Other current assets

)

As of June 30, 2011, there was a net loss of approximately $1.3 million deferred in AOCI. During the six months ended June 30, 2011, we recognized a $0.3 million net deferred gain in AOCI which included approximately $2.0 million of unrealized derivative gains offset by approximately $1.7 million of amounts reclassified to current period earnings to coincide with the earnings impact of the respective hedged transaction. Amounts deferred in AOCI include amounts associated with terminated hedging instruments for which the underlying anticipated hedge transactions are still probable of occurring. The deferred loss in AOCI is expected to be reclassified to future earnings contemporaneously with the earnings recognition of the underlying hedged transactions. Certain underlying hedged transactions are for anticipated base gas purchases. As we account for base gas as a long-term asset, which is not subject to depreciation, amounts related to base gas will not be reclassified to future earnings until such gas is sold or in the event an impairment charge is recognized in the future. Approximately $1.3 million of deferred loss as of June 30, 2011 is associated with base gas purchases. Remaining amounts in AOCI as of June 30, 2011 associated with both open and settled derivative positions are not expected to result in a material amount reclassified into earnings on a net basis during the next twelve months. Amounts deferred are based on market prices as of June 30, 2011, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. Additionally, during the three and six months ended June 30, 2011, we reclassified a gain of $0.7 million from AOCI to natural gas sales as a result of anticipated hedged transactions that are no longer considered to be probable of occurring.

Our accounting policy is to offset fair value amounts associated with derivatives executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through a brokerage account and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of June 30, 2011, we had a net broker receivable of approximately $7.4 million (consisting of initial margin of $4.7 million increased by $2.7 million of variation margin posted by us). At June 30, 2011, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact upon a change in our credit standing.

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, 2011 and December 31, 2010 and during the three and six months ended June 30, 2011 and 2010, all of our commodity

derivatives utilized consisted of exchange-traded or exchange-cleared instruments within active markets. We therefore consider all of our commodity derivatives as of June 30, 2011 and December 31, 2010 and during the three and six months periods ended June 30, 2011 and 2010 to be Level 1 fair value measurements.

We consider our interest rate derivatives to be within Level 2 of the fair value hierarchy. The fair value of these instruments is based on broker or dealer price quotations which are corroborated with market observable inputs including forward interest rates obtained from pricing services.

5. Debt

Our three-year, $400 million senior unsecured credit facility, as amended, bears interest based on LIBOR plus an applicable margin and commitment fees (approximately 3.4% in the aggregate as of June 30, 2011) determined based on funded debt-to-EBITDA levels (as defined in the credit agreement). As of June 30, 2011, we were in compliance with the covenants required by our credit facility.

On February 9, 2011, in connection with the Southern Pines Acquisition (see Note 3), the Partnership borrowed $200 million from PAA pursuant to a three-year promissory note bearing interest at an annual rate of 5.25% (the “PAA Promissory Note”). Interest on the PAA Promissory Note is paid semiannually on the last business day of June and December. Interest paid to PAA during the six months ended June 30, 2011 was approximately $4.1 million.

Our credit facility includes the ability to issue letters of credit. As of June 30, 2011, we had approximately $2 million of outstanding letters of credit under our credit facility.

Capitalized interest for the three and six months ended June 30, 2011 was $3.1 million and $5.7 million, respectively, and $1.2 million and $5.5 million for the three and six months ended June 30, 2010, respectively.

Also in connection with the Southern Pines Acquisition, the Partnership became the holder of the $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2009 and the $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2010 (collectively, the “GO Zone Bonds”), which mature in 2032 and 2035, respectively. The GO Zone Bonds were originally issued to fund the expansion of the Southern Pines facility. The Partnership has the ability to remarket the GO Zone Bonds in the future. As we are currently both the owner of and the ultimate obligor under the GO Zone Bonds, we have presented our investment in and obligation under the GO Zone Bonds on a net basis in our condensed consolidated balance sheet as of June 30, 2011.

6. Commitments and Contingencies

Environmental

We may experience releases of natural gas, brine, crude oil or other contaminants into the environment, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such releases from our assets may substantially affect our business. As of June 30, 2011, we have not identified any such material obligations.

A natural gas storage facility, associated pipeline header system and gas handling and compression facilities may suffer damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to or destruction of property, base gas, or equipment, pollution or environmental damage, or suspension of operations. We maintain insurance under PAA’s insurance program, of various types that we consider adequate to cover our operations and properties. Such insurance covers our assets in amounts management considers reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating natural gas storage facilities, associated pipeline header systems, and gas handling and compression facilities. The overall trend in the insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, we expect this trend to continue as we continue to grow and expand. Accordingly, we may elect to self-insure more of our activities or incorporate higher retention in our insurance arrangements.

The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are

adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, although we believe that we have established adequate reserves to the extent that such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial condition, results of operations or cash flows.

Insurance

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

Litigation

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

7. Partners’ Capital and Distributions

Equity Issuances

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

Outstanding Units

From December 31, 2010 through June 30, 2011, changes in our issued and outstanding common, Series A subordinated and Series B subordinated units were as follows:


			Subordinated
	Common		Series A		Series B		Total
Balance, December 31, 2010		31,586,405		11,934,351		13,500,000		57,020,756
Units Issed in Private Placements		27,598,045		—		—		27,598,045

Balance, June 30, 2011		59,184,450		11,934,351		13,500,000		84,618,801

Distributions

The following table details the distributions declared for 2011 quarterly periods or paid during the six months ended June 30, 2011 (in millions, except per unit amounts):


				Distributions Paid
				Series A								Distributions
		Common		Subordinated		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Units		Incentive		2%		Total		partner unit
July 11, 2011	August 12, 2011 ⁽¹⁾	$	20.4	$	4.1	$	0.1	$	0.5	$	25.1	$	0.3450
April 11, 2011	May 13, 2011	$	20.4	$	4.1	$	0.1	$	0.5	$	25.1	$	0.3450
January 12, 2011	February 14, 2011	$	10.9	$	4.1	$	0.1	$	0.3	$	15.4	$	0.3450

(1) Payable to unitholders of record on August 2, 2011, for the period April 1, 2011 through June 30, 2011

8. Comprehensive Income

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2011			2010		2011		2010
Net income	$	15,869		$	7,232	$	22,214	$	10,355
Net unrealized gain/(loss) on cash flow hedges		(1,084	)		30		256		(359	)

Total comprehensive income	$	14,785		$	7,262	$	22,470	$	9,996

9. Net Income per Limited Partner Unit

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

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2011 (amounts in thousands, except per unit data):


	Three Months Ended,		Six Months Ended
	June 30, 2011		June 30, 2011
Net income	$	15,869	$	22,214
Less: Incentive distributions due to general partner		83		166
Less: General partner’s 2% ownership interest		316		441

Net income available to limited partners	$	15,470	$	21,607


Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income amongst limited partner interests:
Net income allocable to common units	$	12,874	$	17,660
Net income allocable to Series A subordinated units		2,596		3,947
Net income allocable to Series B subordinated units ⁽¹⁾		—		—

Net income available to limited partners	$	15,470	$	21,607


Denominator:
Basic weighted average number of limited partner units outstanding: ^(1)(2)(3)
Common units		59,185		53,391
Series A subordinated units		11,934		11,934
Series B subordinated units		—		—
Diluted weighted average number of limited partner units outstanding: ^(1)(2)(3)
Common units		59,203		53,410
Series A subordinated units		11,934		11,934
Series B subordinated units		—		—

Basic and diluted net income per limited partner unit: ^(1)(2)(3)
Common units	$	0.22	$	0.33
Series A subordinated units	$	0.22	$	0.33
Series B subordinated 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 Through
	June 30, 2010
Net income	$	4,927
Less: Incentive distributions due to general partner		—
Less: General partner’s 2% ownership interest		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 ⁽¹⁾		—

Net income available to limited partners	$	4,828


Denominator:
Basic weighted average number of limited partner units outstanding: ^(1)(2)(3)
Common units		31,585
Series A subordinated units		13,934
Series B subordinated units		—
Diluted weighted average number of limited partner units outstanding: ^(1)(2)(3)
Common units		31,591
Series A subordinated units		13,934
Series B subordinated units		—

Basic and diluted net income per limited partner unit: ^(1)(2)(3)
Common units	$	0.11
Series A subordinated units	$	0.11
Series B subordinated units	$	—


(1)		For each of the periods presented, our Series B subordinated units were not entitled to participate in our earnings, losses or distributions in accordance with the terms of our partnership agreement as necessary performance conditions have not been satisfied. As a result, no earnings were allocated to the Series B subordinated units in our determination of basic and diluted net income per limited partner unit.

(2)		Substantially all of our LTIP awards (described in Note 10), which are classified as equity awards, contain provisions whereby vesting occurs only upon the satisfaction of a performance condition. None of the performance conditions on such awards had been satisfied during any of the periods presented. As such, our outstanding LTIP awards as of June 30, 2011 did not have a material impact in our determination of diluted net income per limited partner unit.

(3)		The conversion of (i) our Series A subordinated units to common units and (ii) our Series B subordinated units to Series A subordinated units or common units is subject to certain performance conditions. None of these performance conditions had been satisfied as of June 30, 2011 therefore, there is no dilutive impact of such units in our determination of diluted net income per limited partner unit.

10. Equity Compensation Plans

Long Term Incentive Plan (“LTIP”)

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

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


				Weighted Average
				Grant Date
	Units			Fair Value per Unit
Outstanding, December 31, 2010		623		$	19.42

Granted		15		$	24.22
Vested		—			—
Cancelled or forfeited		(5	)	$	18.76

Outstanding, June 30, 2011		633		$	19.54

The table below summarizes the expense recognized and unit or cash settled vestings related to all of our equity compensation plans during the three and six months ended June 30, 2011 and 2010 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Equity compensation expense ^{(1) (2) (3)}	$	1,262	$	428	$	2,658	$	843
LTIP cash settled vestings	$	580	$	154	$	580	$	154
DER cash payments	$	19	$	—	$	38	$	—


(1)		Includes expense associated with transaction awards granted by PAA and denominated in PNG units owned by PAA. These awards, which were granted in September 2010, are not included in units outstanding above. The entire economic burden of these agreements will be borne solely by PAA and will not impact our cash or units outstanding. Since these individuals also serve as officers of PNG and PNG benefits as a result of the services they provide, we recognize the grant date fair value of these awards as compensation expense over the service period, with such expense recognized as a capital contribution. We recognized approximately $0.8 million and $1.9 million of compensation expense associated with these awards during the three and six months ended June 30, 2011.

(2)		Equity compensation expense for the six months ended June 30, 2010 relates to awards that were denominated in PAA units and were treated as liability-classified awards. Subsequent to our initial public offering, substantially all of the then outstanding PAA unit denominated awards were converted to equity-classified awards.

(3)		Equity compensation expense for the six months ended June 30, 2011 includes approximately $2.4 million of expense, including approximately $1.9 million associated with the transaction awards, associated with equity-classified awards.

11. Related Party Transactions

We do not directly employ any personnel to manage or operate our business. These functions are provided by employees of Plains All American GP LLC (“GP LLC”), the general partner of Plains AAP, L.P. which is the sole member of PAA GP LLC, PAA’s general partner. References to PAA, unless the context otherwise requires, include GP LLC. We reimburse PAA for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by PAA in connection with the operation of our business. These expenses are recorded in general and administrative expenses and other operating costs on our income statement and include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf. We record these costs on the accrual basis in the period in which PAA’s general partner incurs them. We reimburse PAA for costs related to equity-based compensation awards upon vesting of the awards. Our agreement with PAA provides that PAA will determine the expenses allocable to us in any reasonable manner determined by PAA in its sole discretion. Total costs reimbursed by us to PAA for the three and six months ended June 30, 2011, were $4.4 million and $8.1 million, respectively; and $5.9 million and $11.4 million for the three and six months ended June 30, 2010, respectively. Of these amounts approximately $0.9 million and $1.8 million and $1.0 million and $1.8 million, during the three and six month periods ended June 30, 2011 and 2010, 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, 2011 and December 31, 2010, PNG had amounts due to PAA of approximately $1.7 million and $0.6 million, respectively, included in accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheet.

As of June 30, 2011 and December 31, 2010, PNG’s obligation for unvested equity-based compensation awards for which we are required to reimburse PAA upon vesting and settlement was approximately $0.8 million and $1.0 million, respectively. Approximately $0.6 million and $0.6 million of such amounts were reflected in accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets as of June 30, 2011 and December 31, 2010, respectively, with the remaining balances included as a component of other long-term liabilities at each respective date.

As of June 30, 2011, outstanding parental guarantees issued by PAA to third parties on behalf of PNG Marketing were approximately $31 million. No amounts were due to PAA as of June 30, 2011 under such guarantees and no payments were made to PAA under such guarantees during the three and six months ended June 30, 2011. Effective July 1, 2011, we reached an agreement whereby we will pay PAA a quarterly fee in exchange for providing such parental guarantees. The quarterly fee, which is based on actual usage, is subject to a quarterly minimum of $12,500 regardless of utilization to cover PAA’s administrative costs.

Natural Gas Services Agreement and Related Transactions

In January and July of 2011, we sold a total of approximately 45 acres of land located in Acadia Parish, Louisiana to CDM Max, a subsidiary of PAA, to be used for the development of a natural gas processing plant. The aggregate sales price of approximately $109,000 was based on a third party appraisal and the sale was made on an “as is, where is” basis without any representations or warranties by us. Effective July 1, 2011, we also entered into a Facilities Interconnect Agreement, Natural Gas Services Agreement, and Assignment and Bill of Sale with CDM Max. Pursuant to these agreements, (i) our Pine Prairie subsidiary and CDM Max agreed upon the terms pursuant to which CDM Max would be allowed to connect its natural gas processing facility to Pine Prairie’s header system, including the agreement by Pine Prairie to reimburse CDM Max for approximately $1.5 million of costs associated with certain of such interconnect facilities, (ii) CDM Max agreed to provide certain gas handling services to our Pine Prairie facility and pay a fixed $125,000 per month access fee in exchange for the right to process any volumes delivered to its facility by Pine Prairie and retain for its own account any liquefiable hydrocarbons extracted therefrom, and (iii) we sold two inactive and unused pipeline segments located near CDM Max’s facility to CDM Max in exchange for nominal consideration and without warranties of any kind.

Relationship with our general partner

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

12. Reporting Segment

We manage our operations through three operating segments, Bluewater, Southern Pines and Pine Prairie. We have aggregated these operating segments into one reporting segment, Gas Storage. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including adjusted EBITDA, volumes, adjusted EBITDA per thousand cubic feet (“mcf”) and maintenance capital expenditures. We have aggregated our three operating segments into one reportable segment based on the similarity of their economic and other characteristics, including the nature of services provided, methods of execution and delivery of services, types of customers served and regulatory requirements. We define adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and other adjustments for the impact of unique and infrequent items, items outside of management’s control and/or items that are not indicative of our core operating results and business outlook, which we refer as “selected items impacting comparability” or “selected items.” The measure above excludes depreciation, depletion and amortization as we believe that

depreciation, depletion and amortization are largely offset by repair and maintenance capital investments. Maintenance capital consists of expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating capability, service capability, and/or functionality of our existing assets.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Revenues ⁽¹⁾	$	54,364	$	24,158	$	104,784	$	46,363

Adjusted EBITDA	$	27,507	$	14,159	$	47,007	$	23,075

Maintenance capital	$	109	$	18	$	215	$	217

Long-lived assets ^{(1) (2)}	$	1,730,536	$	938,259	$	1,730,536	$	938,259

Total assets ⁽²⁾	$	1,770,640	$	955,859	$	1,770,640	$	955,859


(1)		We only have operations in the United States, thus no geographic data disclosure is necessary for revenues or long-lived assets.

(2)		Amounts are as of June 30.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Adjusted EBITDA	$	27,507		$	14,159		$	47,007		$	23,075
Selected items impacting Adjusted EBITDA:
Equity compensation expense		(1,262	)		(428	)		(2,658	)		(843	)
Mark-to-market of open derivative positions		64			(230	)		103			370
Acquisition-related expenses		(55	)		—			(4,050	)		—
Insurance deductible related to property damage incident		—			—			(500	)		—
Depreciation, depletion and amortization		(8,940	)		(3,515	)		(15,409	)		(6,456	)
Interest expense, net of capitalized interest		(1,445	)		(2,754	)		(2,279	)		(5,791	)

Net Income	$	15,869		$	7,232		$	22,214		$	10,355

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

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

For ease of reference, we refer to the historical financial results of PAA Natural Gas Storage, LLC (“PNGS”) prior to our initial public offering as being “our” historical financial results. Unless the context otherwise requires, references to “we,” “us,” “our,” and “the Partnership” are intended to mean the business and operations of PAA Natural Gas Storage, L.P. (the “Partnership” or “PNG”) and its consolidated subsidiaries since May 5, 2010. When used in the historical context (i.e. prior to May 5, 2010), these terms are intended to mean the business and operations of PNGS. Unless the context indicates otherwise, for purposes of the following discussion “PAA” refers to Plains All American Pipeline, L.P. (the owner of our general partner) (NYSE: PAA) and its consolidated subsidiaries and affiliates other than the Partnership and its general partner and their respective subsidiaries. For further discussion regarding the Partnership’s initial public offering, please see the consolidated financial statements included in the Partnership’s 2010 Annual Report on Form 10-K.

Overview of Operating Results, Capital Spending and Significant Activities

Adjusted EBITDA for the six months ended June 30, 2011 was approximately $47.0 million, a 104% increase over Adjusted EBITDA of approximately $23.1 million for six months ended June 30, 2010. This increase was primarily the result of the completion of the Southern Pines Acquisition on February 9, 2011 and incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf and 10 Bcf during 2011 and 2010, respectively. See “— Results of Operations” for further discussion and analysis of our operating results. Expansion capital expenditures for the six months ended June 30, 2011 were approximately $789 million including the acquisition of our Southern Pines facility and the ongoing development of our Pine Prairie facility.

Results of Operations

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


	Three Months Ended						Favorable/(Unfavorable)
	June 30,						Variance⁽¹⁾
	2011			2010			$			%
Revenues
Firm Storage Services
Reservation fees	$	32,903		$	22,192		$	10,711			48	%
Cycling fees and fuel-in-kind		2,512			1,419			1,093			77	%
Hub Services		2,234			1,280			954			75	%
Natural Gas Sales		15,973			—			15,973
Other		742			(733	)		1,475			201	%

Total revenues	$	54,364		$	24,158		$	30,206			125	%

Storage related costs	$	(4,331	)	$	(4,963	)	$	632			13	%
Natural gas sales costs		(15,133	)		—			(15,133	)
Operating costs (except those shown below)		(2,915	)		(1,420	)		(1,495	)		(105	)%
Fuel expense		(1,107	)		(533	)		(574	)		(108	)%
General and administrative expenses		(4,641	)		(3,740	)		(901	)		(24	)%
Interest income and other income (expense), net		17			(1	)		18
Acquisition-related expenses		55			—
Insurance deductible related to property damage incident		—			—
Equity compensation expense		1,262			428
Mark-to-market of open derivative positions		(64	)		230

Adjusted EBITDA	$	27,507		$	14,159		$	13,348			94	%


Reconciliation to net income
Adjusted EBITDA	$	27,507		$	14,159		$	13,348			94	%
Depreciation, depletion and amortization		(8,940	)		(3,515	)		(5,425	)		(154	)%
Interest expense, net of capitalized interest		(1,445	)		(2,754	)		1,309			48	%
Equity compensation expense		(1,262	)		(428	)
Acquisition-related expenses		(55	)		—
Mark-to-market of open derivative positions		64			(230	)
Insurance deductible related to property damage incident		—			—

Net income	$	15,869		$	7,232		$	8,637			119	%


Operating Data:
Net revenue margin^{(2) (3)}	$	34,836		$	19,425		$	15,411			79	%
Other operating expenses / G&A / Other		(7,329	)		(5,266	)		(2,063	)		(39	)%

Adjusted EBITDA	$	27,507		$	14,159		$	13,348			94	%


Average working capacity (Bcf)		75			50			25			50	%

Average Monthly Operating Metrics ($/Mcf):
Net revenue margin ^(2) (3)	$	0.15		$	0.13		$	0.02			15	%
Operating expenses / G&A / Other		(0.03	)		(0.04	)		0.01			25	%

Adjusted EBITDA	$	0.12		$	0.09		$	0.03			33	%


	Six Months Ended						Favorable/(Unfavorable)
	June 30,						Variance⁽¹⁾
	2011			2010			$			%
Revenues
Firm Storage Services
Reservation fees	$	60,285		$	39,685		$	20,600			52	%
Cycling fees and fuel-in-kind		4,254			2,599			1,655			64	%
Hub Services		4,635			2,936			1,699			58	%
Natural Gas Sales		34,069			—			34,069
Other		1,541			1,143			398			35	%

Total revenues	$	104,784		$	46,363		$	58,421			126	%

Storage related costs	$	(10,138	)	$	(11,523	)	$	1,385			12	%
Natural gas sales costs		(32,732	)		—			(32,732	)
Operating costs (except those shown below)		(6,002	)		(3,424	)		(2,578	)		(75	)%
Fuel expense		(2,202	)		(1,054	)		(1,148	)		(109	)%
General and administrative expenses		(13,825	)		(7,754	)		(6,071	)		(78	)%
Interest income and other income (expense), net		17			(6	)		23
Acquisition-related expenses		4,050			—
Insurance deductible related to property damage incident		500			—
Equity compensation expense		2,658			843
Mark-to-market of open derivative positions		(103	)		(370	)

Adjusted EBITDA	$	47,007		$	23,075		$	23,932			104	%


Reconciliation to net income
Adjusted EBITDA	$	47,007		$	23,075		$	23,932			104	%
Depreciation, depletion and amortization		(15,409	)		(6,456	)		(8,953	)		(139	)%
Interest expense, net of capitalized interest		(2,279	)		(5,791	)		3,512			61	%
Equity compensation expense		(2,658	)		(843	)
Acquisition-related expenses		(4,050	)		—
Mark-to-market of open derivative positions		103			370
Insurance deductible related to property damage incident		(500	)		—

Net income	$	22,214		$	10,355		$	11,859			115	%


Operating Data:
Net revenue margin^{(2) (3)}	$	61,811		$	34,470		$	27,341			79	%
Other operating expenses / G&A / Other		(14,804	)		(11,395	)		(3,409	)		(30	)%

Adjusted EBITDA	$	47,007		$	23,075		$	23,932			104	%


Average working capacity (Bcf)		67			45			22			49	%

Average Monthly Operating Metrics ($/Mcf):
Net revenue margin ^(2) (3)	$	0.15		$	0.13		$	0.02			15	%
Operating expenses / G&A / Other		(0.03	)		(0.04	)		0.01			25	%

Adjusted EBITDA	$	0.12		$	0.09		$	0.03			33	%


(1)		Certain variance amounts and/or percentages were intentionally omitted.

(2)		Net revenue margin equals total revenues minus storage related and natural gas sales costs.

(3)		Net revenue margin excludes the impact of mark-to-market of open derivative positions.

Non-GAAP and Segment Financial Measures

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

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

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Adjusted EBITDA reconciliation
Net income	$	15,869		$	7,232		$	22,214		$	10,355
Interest expense, net of amounts capitalized		1,445			2,754			2,279			5,791
Depreciation, depletion and amortization		8,940			3,515			15,409			6,456
Selected items impacting Adjusted EBITDA
Equity compensation expense		1,262			428			2,658			843
Significant acquisition-related expenses		55			—			4,050			—
Mark-to-market of open derivative positions		(64	)		230			(103	)		(370	)
Insurance deductible related to property damage incident		—			—			500			—

Adjusted EBITDA	$	27,507		$	14,159		$	47,007		$	23,075


Distributable cash flow reconciliation
Net income	$	15,869		$	7,232		$	22,214		$	10,355
Depreciation, depletion and amortization		8,940			3,515			15,409			6,456
Acquisition-related expenses		55			—			4,050			—
Maintenance capital expenditures		(109	)		(18	)		(215	)		(217	)
Other non cash items:
Equity compensation expense, net of cash payments		662			275			2,039			689
Mark-to-market of open derivative positions		(64	)		230			(103	)		(370	)

Distributable cash flow	$	25,353		$	11,234		$	43,394		$	16,913

Three Months Ended June 30, 2011 as Compared to the Three Months Ended June 30, 2010

Revenues, Volumes and Related Costs. As noted in the table above, our total revenue and related costs increased during the three months ended June 30, 2011 (the “2011 period”) when compared to the three months ended June 30, 2010 (the “2010 period”). The primary reasons for such increase are the completion of the Southern Pines Acquisition on February 9, 2011, results of PNG Marketing, LLC, (our commercial optimization company), incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf during 2011, and additional leasing of third party transportation assets impacting the 2011 period relative to the 2010 period. These and other significant variances related to these periods are discussed in more detail below:

	•		*Firm storage reservation fees* — Firm storage reservation fee revenues increased in the 2011 period as compared to the 2010 period, primarily due to the completion of the Southern Pines Acquisition and incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf during 2011.

	•		*Firm storage cycling fees and fuel-in-kind* — Firm storage cycling fees and fuel-in-kind revenues increased in the 2011 period as compared to the 2010 period primarily due to the increase in working gas capacity in-service from 2010 to 2011 as a result of the completion of the Southern Pines Acquisition. An increase in period-over-period average natural gas prices also contributed to the increased revenues in the 2011 period as compared to the 2010 period.

	•		*Hub services* — Hub services increased in the 2011 period as compared to the 2010 period. Our hub services activities are generally short-term in nature and their timing is influenced by weather, operating disruptions, import activities and other conditions that result in temporary disruptions in supply and demand. The increase in hub services revenues in the 2011 period as compared to the 2010 period is primarily due to usage of leased transportation assets.

	•		*Natural gas sales* — Natural gas sales of approximately $16.0 million during the 2011 period relate to revenues from sales of natural gas by PNG Marketing.

	•		*Other —* Other revenue for each of the periods consists primarily of crude oil sales and activities associated with natural gas storage-related futures derivative positions. Crude oil sales increased in the 2011 period as compared to the 2010 period by

			approximately $0.4 million. The increase was due to both increased volumes sold as a result of our liquids removal efforts at our Bluewater facility and higher average realized prices in the 2011 period as compared to the 2010 period. The 2010 period 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. 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 decreased in the 2011 period as compared to the 2010 period. The decrease was primarily the result of a decrease in the amount of leased storage and a reduction in costs incurred to manage our storage capacity. This decrease was partially offset by an increase in leased transportation assets in the 2011 period as compared to the 2010 period.

	•		*Natural gas sales costs* — Natural gas sales costs of approximately $15.1 million during the 2011 period reflect the cost of natural gas sold by PNG Marketing.

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

	•		*Operating costs* — Field operating costs increased in the 2011 period as compared to the 2010 period. The increase is primarily related to the increase in working gas capacity in-service from 2010 to 2011 as a result of our expansion efforts at our Pine Prairie facility and the completion of the Southern Pines Acquisition.

	•		*Fuel expense* — Fuel expense increased in the 2011 period as compared to 2010 due to increases in both the volume of fuel consumed and the market price of fuel.

	•		*General and administrative expenses* — General and administrative expenses increased in the 2011 period as compared to the 2010 period. The increase primarily resulted from the continued expansion of our business and growth in personnel costs, including equity compensation expense and the establishment of our commercial optimization group, along with additional administrative costs associated with being a public company. Additionally, during the 2011 period we recognized approximately $0.8 million of equity compensation expense associated with awards granted by PAA. Although we will not bear the economic burden of these awards, we benefit from the services underlying these awards. The 2010 period includes 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.

	•		*Depreciation, depletion and amortization* — Depreciation, depletion and amortization expense increased in the 2011 period as compared to the 2010 period. The increase resulted primarily from an increased amount of depreciable assets resulting from the Southern Pines acquisition and our internal growth projects, including the additional 8 Bcf of storage capacity placed into service at our Pine Prairie facility in April 2011. Additionally, amortization of intangible assets acquired in conjunction with the Southern Pines Acquisition was approximately $4.1 million during the 2011 period.

	•		*Interest expense, net of capitalized interest* — Interest expense, net of capitalized interest, decreased in the 2011 period when compared to the 2010 period. Interest expense, on a gross basis, increased to approximately $4.5 million in the 2011 period as compared to approximately $3.9 million in the 2010 period. Interest expense, on a gross basis, increased due to higher average debt balances outstanding in the 2011 period as compared to the 2010 period, partially offset by a lower average interest rate in the 2011 period as compared to the 2010 period. Capitalized interest was approximately $3.1 million and $1.2 million in the 2011 and 2010 periods, respectively. Capitalized interest was impacted from the increase in average debt balance outstanding and the decrease in average interest rate in the 2011 period as compared to the 2010 period, along with an increase in assets not yet in-service as a result of the Southern Pines Acquisition. The increased capitalized interest is partially offset by increased interest as a result of increased average debt balances outstanding.

Six Months Ended June 30, 2011 as Compared to the Six Months Ended June 30, 2010

Revenues, Volumes and Related Costs. As noted in the table above, our total revenue and related costs increased during the six months ended June 30, 2011 (the “2011 period”) when compared to the six months ended June 30, 2010 (the “2010 period”). The primary reasons for such increase are the completion of the Southern Pines Acquisition on February 9, 2011, results of PNG Marketing, LLC (our commercial optimization company), incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf and 10 Bcf during 2011 and 2010, respectively, and additional leasing of

third party transportation assets impacting the 2011 period relative to the 2010 period. These and other significant variances related to these periods are discussed in more detail below:

	•		*Firm storage reservation fees* — Firm storage reservation fee revenues increased in the 2011 period as compared to the 2010 period, primarily due to the completion of the Southern Pines Acquisition and incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf and 10 Bcf during 2011 and 2010, respectively.

	•		*Firm storage cycling fees and fuel-in-kind* — Firm storage cycling fees and fuel-in-kind revenues increased in the 2011 period as compared to the 2010 period primarily due to the increase in working gas capacity in-service from 2010 to 2011 as a result of the completion of the Southern Pines Acquisition. Period over period natural gas prices were relatively consistent in the 2011 period as compared to the 2010 period.

	•		*Hub services* — Hub services increased in the 2011 period as compared to the 2010 period. Our hub services activities are generally short-term in nature and their timing is influenced by weather, operating disruptions, import activities and other conditions that result in temporary disruptions in supply and demand. The increase in hub services revenues in the 2011 period as compared to the 2010 period is primarily due to usage of leased transportation assets.

	•		*Natural gas sales* — Natural gas sales of approximately $34.1 million during the 2011 period relate to revenues from sales of natural gas by PNG Marketing.

	•		*Other —* Other revenue for each of the periods consists primarily of crude oil sales and activities associated with natural gas storage-related futures derivative positions. Crude oil sales decreased in the 2011 period as compared to the 2010 period by approximately $0.2 million. The decrease in crude oil sales in the 2011 period as compared to the 2010 period is primarily attributable to a temporary stoppage in liquids removal efforts at our Bluewater facility as a result of the operational incident and related fire that occurred in January 2011. The decrease in volumes sold during 2011 as compared to 2010 was partially offset by higher average realized prices. The 2010 period includes losses of approximately $0.4 million associated with changes in the fair market value of a natural gas storage related futures derivative position. 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 decreased in the 2011 period as compared to the 2010 period. The decrease was primarily the result of a decrease in the amount of leased storage and a reduction in costs incurred to manage our storage capacity. This decrease was partially offset by an increased in leased transportation assets in the 2011 period as compared to the 2010 period.

	•		*Natural gas sales costs* — Natural gas sales costs of approximately $32.7 million during the 2011 period reflect the cost of natural gas sold by PNG Marketing.

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

	•		*Operating costs* — Field operating costs increased in the 2011 period as compared to the 2010 period. The increase is primarily related to the increase in working gas capacity in-service from 2010 to 2011 as a result of our expansion efforts at our Pine Prairie facility and the completion of the Southern Pines Acquisition. The 2011 period includes approximately $0.5 million of expense for the property insurance deductible related to the January 2011 operational incident and fire at our Bluewater facility.

	•		*Fuel expense* — Fuel expense increased in the 2011 period as compared to 2010 due to increases in both the volume of fuel consumed and the market price of fuel.

	•		*General and administrative expenses* — General and administrative expenses increased in the 2011 period as compared to the 2010 period. The increase primarily resulted from the continued expansion of our business and growth in personnel costs, including equity compensation expense and the establishment of our commercial optimization group, along with additional administrative costs associated with being a public company. Additionally, during the 2011 period we recognized approximately $1.9 million of equity compensation expense associated with awards granted by PAA. Although we will not bear the economic burden of these awards, we benefit from the services underlying these awards. The 2011 period also includes approximately $4.1 million of acquisition and integration costs incurred in conjunction with the Southern Pines Acquisition. The 2010 period includes non-recurring costs of 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.

	•		*Depreciation, depletion and amortization* — Depreciation, depletion and amortization expense increased in the 2011 period as compared to the 2010 period. The increase resulted primarily from an increased amount of depreciable assets resulting from the Southern Pines acquisition and our internal growth projects, including the additional 8 Bcf of storage capacity placed into service at our Pine Prairie facility in April 2011. Additionally, amortization of intangible assets acquired in conjunction with the Southern Pines Acquisition was approximately $6.5 million during the 2011 period.

	•		*Interest expense, net of capitalized interest* — Interest expense, net of capitalized interest, decreased in the 2011 period when compared to the 2010 period. Interest expense, on a gross basis, decreased to approximately $8.0 million in the 2011 period as compared to approximately $11.3 million in the 2010 period. The decrease principally resulted from a decrease in average interest rates in the 2011 period as compared to 2010 period and was partially offset by an increase in capitalized interest. Capitalized interest was approximately $5.7 million and $5.5 million in the 2011 and 2010 periods, respectively. Capitalized interest was impacted from an increase in assets not yet in service as a result of the Southern Pines Acquisition, which was partially offset by the decrease in average interest rates.

Outlook

Following a multi-year period of favorable market conditions for natural gas storage providers, overall market conditions for both hub services and firm storage services softened throughout 2010 continuing into 2011. Factors we believe contributed to this deterioration include reduced spread and basis differentials and associated volatility, which we believe were impacted by a combination of factors, including (i) a relatively balanced supply/demand situation with increased shale gas production being offset by incremental consumption associated with historically abnormal weather patterns, (ii) the perception of lower gas supply risk due to a higher percentage of overall supply coming from domestic shale gas production, (iii) pipeline infrastructure additions and (iv) on a regional basis, increased storage on storage competition from capacity additions and re-contracting activities. Market conditions weakened progressively in the second half of 2010 continuing into 2011 with seasonal spreads, as reflected by the October 2011 to January 2012 NYMEX spread, decreasing to a five-year low of $0.371 per dekatherm during June 2011.

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

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

Liquidity and Capital Resources

Overview

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

In conjunction with the closing of our initial public offering on May 5, 2010, the Partnership entered into a three-year, $400 million senior unsecured revolving credit facility, which may be expanded to $600 million with approval of the administrative agent. At June 30, 2011, we had $228.1 million outstanding under this facility, including $2.0 million of outstanding letters of credit. The extent to which we can borrow against the remaining $171.9 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 EBITDA-to-interest 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, 2011, 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, 2011 our total available debt would be limited to approximately $171.9 million of the $400 million. Notably, the restriction on debt incurrence does not limit our ability to incur hedged inventory debt. Also, the formula for determining EBITDA in the context of the financial ratios allows for inclusion of pro forma EBITDA arising from certain capital investments, including for acquisitions and certain capital expenditures related to our Pine Prairie and Southern Pines expansions. We believe our credit facility and available debt capacity is adequate to fund our current capital program.

We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $1.0 billion of debt or equity securities (“Traditional Shelf”). We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. Since the filing of these registration statements with the SEC, we have not issued any securities under the Traditional Shelf or the WKSI Shelf.

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

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

Historical Cash Flow

As of June 30, 2011, we had a working capital surplus of approximately $2.8 million.

The following table presents a summary of our cash flows for the six months ended June 30, 2011 and 2010 (in thousands):


	Six Months Ended June 30,
	2011			2010
Net cash provided by (used in):
Operating activities	$	40,778		$	24,563
Investing activities		(765,679	)		(52,021	)
Financing activities		724,931			25,866

Net increase/(decrease) in cash	$	30		$	(1,592	)


Adjusted EBITDA	$	47,007		$	23,075

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

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

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

Capital Requirements

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

Estimated Capital Expenditures. Excluding acquisitions, we estimate we will spend approximately $100 million in expansion capital, including capitalized interest, during 2011, of which approximately $45 million was incurred through June 30, 2011. Maintenance capital expenditures for 2011 are estimated to be approximately $0.8 million, of which approximately $0.2 million was incurred through June 30, 2011.

Distributions to Unitholders and General Partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On August 12, 2011, we will pay a quarterly distribution of $0.3450 per unit on our common units and Series A subordinated units.

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

Contingencies

See Note 6 to the condensed consolidated financial statements.

Commitments

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

The following table includes our best estimate of the amount and timing of the payments due under our contractual obligations as of June 30, 2011 (in millions):


	Total		2011		2012		2013		2014		2015		Thereafter
Long-term debt, interest and fees⁽¹⁾	$	467	$	9	$	18	$	239	$	201	$	—	$	—
Leases — storage, transportation, other		36		8		13		7		5		2		1
Capital commitments		31		15		2		1		2		2		9
Other long-term liabilities		2		—		1		1		—		—		—

Subtotal		536		32		34		248		208		4		10
Natural gas purchases ⁽²⁾		58		58		—		—		—		—		—

Total	$	594	$	90	$	34	$	248	$	208	$	4	$	10


(1)		Includes interest payments and commitment fees on our senior unsecured revolving credit facility and note payable to PAA.

(2)		Amounts are based on estimated volumes and market prices based on average activity during June 2011. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include weather conditions, changes in market prices and other conditions beyond our control.

Letters of Credit. In connection with our use of certain leased storage and transportation assets, we have periodically provided certain suppliers with irrevocable standby letters of credit to secure our obligations for the purchase of these services. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the services are provided. Our $400.0 million senior unsecured revolving credit facility provides us with the ability to issue letters of credit. As of June 30,

2011, we had approximately $2 million of outstanding letters of credit under our credit facility and approximately $31 million of outstanding parental guarantees issued by PAA to third parties on behalf of PNG Marketing.

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

See Note 2 to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates

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

Forward-Looking Statements

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

•

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

•

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

•

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

•

factors affecting our ability to realize short term optimization revenues from transactions involving uncontracted or unutilized capacity at our facilities;

•

the effects of competition;

•

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

•

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

•

the impact of operational and commercial factors that could result in an inability on our part to satisfy our contractual commitments and obligations, including the impact of equipment performance, cavern operating pressures, and cavern temperature variances;

•

risks related to the development and operation of natural gas storage facilities;

•

failure to implement or execute planned internal growth projects on a timely basis and within targeted cost projections;

•

the effectiveness of our risk management activities;

•

interruptions in service and fluctuations in tariffs or volumes on third-party pipelines;

•

general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns;

•

the successful integration and future performance of acquired assets or businesses;

•

our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

•

the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations;

•

shortages or cost increases of supplies, materials or labor;

•

weather interference with business operations or project construction;

•

our ability to receive open credit from our suppliers and trade counterparties;

•

continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;

•

the availability of, and our ability to consummate, acquisition or combination opportunities;

•

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

•

increased costs or unavailability of insurance;

•

fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plan;

•

future developments and circumstances at the time distributions are declared; and

•

other factors and uncertainties inherent in the development and operation of natural gas storage facilities.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The fair value of our outstanding natural gas derivatives as of June 30, 2011 was a net liability of approximately $2.9 million. A 10% increase in natural gas prices would result in a net liability of approximately $1.7 million. A 10% decrease in natural gas prices would result in a net liability of approximately $4.1 million.

Interest Rate Price Risk

The fair value of our outstanding interest rate swap agreements as of June 30, 2011 was a net asset of approximately $31,000. A 10% increase in interest rates would result in a net asset of approximately $0.2 million. A 10% decrease in interest rates would result in a net liability of approximately $0.1 million.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

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

Changes in Internal Control over Financial Reporting

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

Certifications

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

PART II.
OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. [Removed and Reserved]

Item 5. Other Information

None.

Item 6. Exhibits


2.1	—	Purchase and Sale Agreement dated December 28, 2010 by and among SGR Holdings, L.L.C., Southern Pines Energy Investment Co., LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 30, 2010).

2.2	—	Amendment dated May 2, 2011 to Purchase and Sale Agreement dated December 28, 2010 (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).

3.1	—	Certificate of Limited Partnership of PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).

3.2	—	Second Amended and Restated Agreement of Limited Partnership of PAA Natural Gas Storage, L.P. dated August 16, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on August 20, 2010).

3.3	—	Certificate of Formation of PNGS GP LLC (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).

3.4	—	Amended and Restated Limited Liability Company Agreement of PNGS GP LLC dated May 5, 2010 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q filed on August 6, 2010).

4.1	—	Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 30, 2010).

4.2	—	Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 20, 2011).

10.1	—	Common Unit Purchase Agreement dated December 23, 2010 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 30, 2010).


10.2	—	Common Unit Purchase Agreement dated January 19, 2011 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 20, 2011).

10.3	—	Note Payable to PAA dated February 9, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 14, 2011).

10.4	—	First Amendment to Credit Agreement dated as of March 10, 2011, by and among PAA Natural Gas Storage, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by referenced to Exhibit 10.1 to the Current Report on Form 8-K filed on March 15, 2011).

31.1*	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2*	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1*	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.

32.2*	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

101*	—	The following information from the quarterly report on Form 10-Q of PAA Natural Gas Storage, L.P. for the three months ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations; (ii) Condensed Consolidated Balance Sheets; (iii) Condensed Consolidated Statements of Cash Flows; (iv) Condensed Consolidated Statement of Changes in Partners’ Capital; and (v) Notes to the Condensed Consolidated Financial Statements.


†		Management compensatory plan or arrangement.

*		Filed herewith.

SIGNATURES

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


	PAA NATURAL GAS STORAGE, L.P. By: PNGS GP LLC, its general partner
Date: August 5, 2011	By:	/s/ Greg L. Armstrong
		Name:	Greg L. Armstrong
		Title:	Chairman and Chief Executive Officer (Principal Executive Officer)

Date: August 5, 2011	By:	/s/ Dean Liollio
		Name:	Dean Liollio
		Title:	President

Date: August 5, 2011	By:	/s/ Al Swanson
		Name:	Al Swanson
		Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

EXHIBIT INDEX


2.1	—	Purchase and Sale Agreement dated December 28, 2010 by and among SGR Holdings, L.L.C., Southern Pines Energy Investment Co., LLC and PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on December 30, 2010).

2.2	—	Amendment dated May 2, 2011 to Purchase and Sale Agreement dated December 28, 2010 (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).

3.1	—	Certificate of Limited Partnership of PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).

3.2	—	Second Amended and Restated Agreement of Limited Partnership of PAA Natural Gas Storage, L.P. dated August 16, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on August 20, 2010).

3.3	—	Certificate of Formation of PNGS GP LLC (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (333-164492) filed on January 25, 2010).

3.4	—	Amended and Restated Limited Liability Company Agreement of PNGS GP LLC dated May 5, 2010 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q filed on August 6, 2010).

4.1	—	Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 30, 2010).

4.2	—	Form of Registration Rights Agreement by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 20, 2011).

10.1	—	Common Unit Purchase Agreement dated December 23, 2010 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 30, 2010).

10.2	—	Common Unit Purchase Agreement dated January 19, 2011 by and among PAA Natural Gas Storage, L.P. and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 20, 2011).

10.3	—	Note Payable to PAA dated February 9, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 14, 2011).

10.4	—	First Amendment to Credit Agreement dated as of March 10, 2011, by and among PAA Natural Gas Storage, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by referenced to Exhibit 10.1 to the Current Report on Form 8-K filed on March 15, 2011).

31.1*	—	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

31.2*	—	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a).

32.1*	—	Certification of Principal Executive Officer pursuant to 18 U.S.C. 1350.

32.2*	—	Certification of Principal Financial Officer pursuant to 18 U.S.C. 1350.

101*	—	The following information from the quarterly report on Form 10-Q of PAA Natural Gas Storage, L.P. for the three months ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations; (ii) Condensed Consolidated Balance Sheets; (iii) Condensed Consolidated Statements of Cash Flows; (iv) Condensed Consolidated Statement of Changes in Partners’ Capital; and (v) Notes to the Condensed Consolidated Financial Statements.


†		Management compensatory plan or arrangement.

*		Filed herewith.

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