UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-34722

PAA Natural Gas Storage, L.P.

(Exact name of registrant as specified in its charter)

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

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

     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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):

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

     As of November 2, 2011, there were 59,193,825 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: September 30, 2011 and December 31, 2010			3
Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2011 and 2010			4
Condensed Consolidated Statement of Changes in Partners’ Capital: For the nine months ended September 30, 2011			5
Condensed Consolidated Statements of Cash Flows: For the nine months ended September 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			10
5. Debt			14
6. Commitments and Contingencies			15
7. Partners’ Capital and Distributions			16
8. Comprehensive Income			16
9. Net Income per Limited Partner Unit			16
10. Equity Compensation Plans			18
11. Related Party Transactions			19
12. Reporting Segment			20
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			23
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			35
Item 4. CONTROLS AND PROCEDURES			35
PART II. OTHER INFORMATION			37
Item 1. LEGAL PROCEEDINGS			37
Item 1A. RISK FACTORS			37
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			37
Item 3. DEFAULTS UPON SENIOR SECURITIES			37
Item 4. [REMOVED AND RESERVED]			37
Item 5. OTHER INFORMATION			37
Item 6. EXHIBITS			37
SIGNATURES			39
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)

		September 30,				December 31,
		2011				2010
Assets
Current assets
Cash and cash equivalents		$	342			$	346
Restricted cash			—				20,000
Accounts receivable			15,476				13,986
Natural gas inventory			28,348				57
Other current assets			8,058				1,487
Total current assets			52,224				35,876
Property and equipment
Property and equipment			1,293,153				892,645
Less: Accumulated depreciation, depletion and amortization			(26,799	)			(14,837	)
Property and equipment, net			1,266,354				877,808
Other assets
Base gas			45,712				37,498
Goodwill			325,470				24,966
Intangibles, net			104,288				22,580
Total other assets, net			475,470				85,044
Total assets		$	1,794,048			$	998,728
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities		$	43,929			$	14,006
Short-term debt			18,261				—
Accrued taxes			1,544				1,009
Total current liabilities			63,734				15,015
Long-term liabilities
Note payable to PAA			200,000				—
Long-term debt under credit agreement			234,639				259,900
Other long-term liabilities			1,218				423
Total long-term liabilities			435,857				260,323
Total liabilities			499,591				275,338
Commitments and contingencies (Note 6)
Partners’ capital
Common unitholders (59,193,825 units issued and outstanding at September 30, 2011)			1,040,765				474,489
Subordinated unitholders (25,434,351 units issued and outstanding at September 30, 2011)			230,980				236,853
General partner			27,618				13,637
Accumulated other comprehensive loss			(4,906	)			(1,589	)
Total partners’ capital			1,294,457				723,390
Total liabilities and partners’ capital		$	1,794,048			$	998,728

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

PAA Natural Gas Storage, L.P. and Subsidiaries

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Revenues
Firm storage services		$	35,536			$	23,773			$	100,075			$	66,057
Hub services			1,830				689				6,465				3,625
Natural gas sales			40,718				—				74,787				—
Other			1,250				621				2,791				1,764
Total revenues			79,334				25,083				184,118				71,446
Costs and expenses
Storage related costs			4,770				5,101				14,908				16,624
Natural gas sales costs			40,053				—				72,785				—
Other operating costs (except those shown below)			3,070				1,720				9,072				5,144
Fuel expense			762				611				2,964				1,665
General and administrative expenses			4,368				3,409				18,193				11,163
Depreciation, depletion and amortization			9,193				3,867				24,602				10,323
Total costs and expenses			62,216				14,708				142,524				44,919
Operating income			17,118				10,375				41,594				26,527
Other income/(expense)
Interest expense, net of capitalized interest			(1,666	)			(749	)			(3,945	)			(6,540	)
Other income (expense)			(7	)			(6	)			10				(12	)
Net income		$	15,445			$	9,620			$	37,659			$	19,975
Calculation of Limited Partner Interest in Net Income:
Net income (1)		$	15,445			$	9,620			$	37,659			$	14,547
Less general partner interest in net income			526				192				1,133				291
Limited partner interest in net income		$	14,919			$	9,428			$	36,526			$	14,256
Net income per limited partner unit
Common and Series A subordinated units (2) (Basic)		$	0.21			$	0.21			$	0.54			$	0.32
Common and Series A subordinated units (2)(Diluted)		$	0.21			$	0.21			$	0.54			$	0.32
Limited partner units outstanding
Common and Series A subordinated units (2) (Basic)			71,125				44,520				67,279				44,902
Common and Series A subordinated units (2)(Diluted)			71,136				44,525				67,294				44,907

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

PAA Natural Gas Storage, L.P. and Subsidiaries

		Partners’ Capital																Accumulated
						Limited Partners												Other
						Subordinated								General				Comprehensive
		Common				Series A				Series B				Partner				Gain/(Loss)				Total
Balance at December 31, 2010		$	474,489			$	135,062			$	101,791			$	13,637			$	(1,589	)		$	723,390
Net income			30,047				6,479				—				1,133				—				37,659
Issuance of common units, net of offering and other costs			587,347				—				—				12,000				—				599,347
Equity compensation expense			664				—				—				2,369				—				3,033
Distributions to unitholders and general partner			(51,735	)			(12,352	)			—				(1,525	)			—				(65,612	)
Distribution equivalent right payments			(47	)			—				—				—				—				(47	)
Contribution from general partner			—				—				—				4				—				4
Net deferred loss on cash flow hedges			—				—				—				—				(3,317	)			(3,317	)
Balance at September 30, 2011		$	1,040,765			$	129,189			$	101,791			$	27,618			$	(4,906	)		$	1,294,457

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

PAA Natural Gas Storage, L.P. and Subsidiaries

		Nine Months Ended
		September 30
		2011				2010
Cash flows from operating activities
Net income		$	37,659			$	19,975
Adjustments to reconcile to cash flow from operations
Depreciation, depletion and amortization			24,602				10,323
Equity compensation expense			3,360				1,514
Non-cash interest expense on borrowings from parent, net			—				5,081
Unrealized gain on derivative instruments			(235	)			(370	)
Changes in assets and liabilities, net of acquisitions
Accounts receivable and other assets			(17,679	)			(5,882	)
Accounts payable and accrued liabilities			15,320				1,585
Net cash provided by operating activities			63,027				32,226
Cash flows from investing activities
Additions to property and equipment			(57,662	)			(58,550	)
Cash paid in connection with acquisition, net of cash acquired			(744,209	)			—
Decrease in restricted cash			20,000				—
Cash paid for base gas			(5,292	)			(9,488	)
Other investing activities			—				80
Net cash used in investing activities			(787,163	)			(67,958	)
Cash flows from financing activities
Borrowings under credit agreements			437,800				256,900
Repayments of borrowings under credit agreements			(444,800	)			(35,400	)
Borrowings from parent			200,000				24,000
Repayment of borrowings from parent			—				(468,363	)
Net proceeds from issuance of common units			587,347				268,161
Costs incurred in connection with financing arrangements			(2,561	)			(2,433	)
Contributions from general partner			12,004				1
Distributions paid to unitholders			(64,086	)			(9,623	)
Distributions paid to general partner			(1,525	)			(196	)
Distribution equivalent right payments			(47	)			(10	)
Net cash provided by financing activities			724,132				33,037
Net increase (decrease) in cash and cash equivalents			(4	)			(2,695	)
Cash and cash equivalents
Beginning of period			346				3,124
End of period		$	342			$	429
Cash paid for interest, net of amounts capitalized		$	2,902			$	1,448
Non-cash items
Change in non-cash asset purchases included in accounts payable		$	1,811			$	(6,855	)
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 September 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 September 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 nine months ended September 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 of gas acquired and sold 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 is valued at the lower of cost or market, with cost determined using an average cost method within specified inventory pools. As of September 30, 2011, PNG owned approximately 7.3 Bcf of natural gas inventory with a carrying value of approximately $28.3 million. Our natural gas inventory balance at September 30, 2011 reflects a lower of cost or market adjustment of approximately $2.6 million. The recognition of this adjustment, a component of natural gas sales costs in our accompanying condensed consolidated statement of operations, was offset by the recognition of approximately $2.6 million of unrealized gains on derivative instruments (see Note 4) being utilized to hedge the future sales of our natural gas inventory.

Property and Equipment

     During the nine months ended September 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 nine months ended September 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 September 2011, the FASB issued guidance to simplify the goodwill impairment test by permitting entities to perform a qualitative assessment to determine whether further impairment testing is necessary. If qualitative factors indicate that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, an entity need not perform the two-step goodwill impairment test. This guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on our financial position, results of operations or cash flows.

     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.

     Also in connection with the Southern Pines Acquisition, the Partnership became the owner, with the ability to remarket in the future, and ultimate obligor 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 Bonds”). These were originally issued to fund the expansion of the Southern Pines facility. We remarketed the GO Bonds in August 2011 (see Note 5).

     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 nine months ended September 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 September 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 $12.6 million for the three months ended September 30, 2011 and approximately $30.8 million for the period from February 9, 2011 (date of acquisition) through September 30, 2011 are included in our condensed consolidated statements of operations for the three and nine months ended September 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 nine months ended September 30, 2011 and 2010, assuming the Southern Pines Acquisition had occurred on January 1, 2010, are presented below (in thousands, except per unit amounts):

		Nine Months Ended September 30,
		2011				2010
Total revenues		$	188,081			$	98,581
Net income(1)		$	42,963			$	27,635
Limited partner interest in net income(2)		$	41,723			$	22,623
Net income per limited partner unit(3)
Basic		$	0.59			$	0.31
Diluted		$	0.59			$	0.31

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 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 September 30, 2011, we have a long swap position of approximately 2.0 Bcf through April 2013 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 September 30, 2011, we have a short swap position of approximately 14.3 Bcf through December 2011 related to anticipated sales of natural gas, and an approximate 5.9 Bcf long swap position through December 2011 related to anticipated purchases of natural gas.

Interest Rate Risk Hedging

     We use interest rate derivatives to hedge the underlying benchmark interest rate associated with borrowings outstanding under our debt facilities. During June 2011 and August 2011, we entered into three interest rate swaps to fix the interest rate on a portion of our outstanding debt. The swaps have an aggregate notional amount of $100 million with an average fixed rate of 0.95%. Two of these swaps terminate in June 2014 and the remaining swap terminates in August 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 in AOCI and reclassed to 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.

     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 commodity derivatives, which are all exchange-traded or exchange-cleared, 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 September 30, 2011, we had a net broker receivable of approximately $6.1 million (consisting of initial margin of $4.4 million increased by $1.7 million of variation margin posted by us). Our interest rate derivatives, which are over-the-counter instruments, do not have margin requirements. At September 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.

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

		Three Months Ended September 30, 2011
		Derivatives in Hedging				Derivatives not
Location of Gain/(Loss)		Relationships(1)(2)(4)				Designated as a Hedge(3)				Total
Commodity Derivatives
Natural Gas Sales		$	60			$	(50	)		$	10
Natural Gas Sales Costs			2,615				—				2,615
Other Revenues			211				(11	)			200
Interest Rate Derivatives
Interest Expense			(147	)			—				(147	)
Total Gain/(Loss) on Derivatives Recognized in Net Income		$	2,739			$	(61	)		$	2,678

		Nine Months Ended September 30, 2011
		Derivatives in Hedging				Derivatives not
Location of Gain/(Loss)		Relationships(1)(2)(4)				Designated as a Hedge(3)				Total
Commodity Derivatives
Natural Gas Sales		$	1,713			$	45			$	1,758
Natural Gas Sales Costs			2,615				—				2,615
Other Revenues			243				61				304
Interest Rate Derivatives
Interest Expense			(175	)			—				(175	)
Total Gain/(Loss) on Derivatives Recognized in Net Income		$	4,396			$	106			$	4,502

     During the three and nine months ended September 30, 2010, our earnings were not impacted from derivative activities in cash flow hedging relationships.

     We recognized realized losses of approximately $0.8 million, of which approximately $0.4 million was incurred during the nine months ended September 30, 2010, 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 September 30, 2011 (in thousands):

		As of September 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				$	7,496			Other current assets				$	(8,215	)
										Other long-term liabilities					(515	)
Interest Rate Derivatives										Other current liabilities					(342	)
										Other long-term liabilities					(361	)
Total Derivatives designated as hedging instruments						$	7,496							$	(9,433	)

		As of September 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				$	285			Other current assets				$	(669	)
Total Derivatives designated as hedging instruments						$	285							$	(669	)
Total Derivatives						$	7,781							$	(10,102	)

     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

Balance Sheet

Location

Fair Value

Location

Fair Value

Derivatives designated as hedging instruments:

Commodity Derivatives

Other current assets

$

43

Other current assets

$

(4

)

Accumulated Other Comprehensive Income

     During the nine months ended September 30, 2011, we recognized a net loss in AOCI of $3.3 million. The $3.3 million net deferred loss consisted of net deferred gains of $1.1 million for the period offset by net reclassification adjustments of $4.4 million. Reclassification adjustments reflect amounts reclassified to earnings from AOCI to coincide with the earnings impact of the respective hedged transactions. Reclassification adjustments which reduce AOCI result in an offsetting increase to current period earnings and those which increase AOCI result in an offsetting decrease to current period earnings. The net reclassification adjustment of $4.4 million for the nine month period ended September 30, 2011, which reduced AOCI and increased current period earnings, includes a deferred gain of approximately $2.6 million which offsets a lower of cost or market adjustment related to the carrying value of our natural gas inventory.

     Amounts deferred in AOCI include amounts associated with settled derivatives 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. Deferred losses of $2.4 million associated with base gas hedges are included in AOCI as of September 30, 2011. Remaining amounts in AOCI as of September 30, 2011 associated with both open and settled derivative positions. Of the total deferred loss in AOCI of $4.9 million as of September 30, 2011, approximately $2.3 million is expected to be reclassed to earnings during the next twelve months. Amounts deferred are based on market prices as of September 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 nine months ended September 30, 2011, we reclassified a gain of $0.7 million from AOCI to natural gas sales when it was deemed probable that the anticipated hedged transactions would not occur.

Fair Value Measurements

     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 September 30, 2011 and December 31, 2010 and during the three and nine months ended September 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 September 30, 2011 and December 31, 2010 and during the three and nine month periods ended September 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

     In August 2011, we entered into a new $450 million five-year senior unsecured credit agreement, which provides for (i) $250 million under a revolving credit facility, which may be increased at our option to $450 million (subject to receipt of additional or increased lender commitments) and (ii) two $100 million term loan facilities (the “GO Zone Term Loans”) pursuant to the purchase, at par, of the GO Bonds we acquired in conjunction with the Southern Pines Acquisition (see Note 3). The revolving credit facility expires in August 2016. The purchasers of the two GO Zone Term Loans have the right to put, at par, to PNG the GO Zone Term Loans in August 2016. The GO Bonds mature by their terms in May 2032 and August 2035, respectively. Borrowings under the revolving credit facility accrue interest, at our election, on either the Eurodollar Rate or the Base Rate, in each case, plus an applicable margin. The GO Zone Term Loans accrue interest in accordance with the interest payable on the related GO Bonds purchased with respect thereto as provided in such GO Bonds and the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed, which generally provides that interest on the outstanding principal amount of (i) the GO Bonds 2009 shall accrue at a rate per annum equal to 75% of the sum of (a) the one-month Eurodollar Rate, plus (b) an applicable margin and (ii) the GO Bonds 2010 shall accrue at a rate per annum equal to 67% of the sum of (a) the one-month Eurodollar Rate plus (b) an applicable margin. Fees on issued letters of credit accrue at the applicable margin for Eurodollar Rate Loans, and a commitment fee accrues at an applicable margin. The applicable margin used in connection with interest rates and fees is based on our consolidated leverage ratio (as defined in the agreement) at the applicable time. This new credit agreement replaced our $400 million, three year senior unsecured revolving credit facility that was scheduled to mature in May 2013.

     Our new credit agreement contains covenants and events of default which are substantially consistent with those contained in our previous credit facility. Our new credit agreement restricts, among other things, our ability to make distributions of available cash to unitholders if any default or event of default, as defined in the credit agreement, exists or would result therefrom. In addition, the credit agreement contains restrictive covenants, including those that restrict our ability to grant liens, incur additional indebtedness, engage in certain transactions with affiliates, engage in substantially unrelated businesses, sell substantially all of our assets or enter into a merger or consolidation, and enter into certain burdensome agreements. In addition, the credit agreement contains certain financial covenants which, among other things, require us to maintain a debt-to-EBITDA coverage ratio that will not be greater than 5.00 to 1.00 on outstanding debt (5.50 to 1.00 during an acquisition period) and also require that we maintain an EBITDA-to-interest coverage ratio that will not be less than 3.00 to 1.00, as such terms are defined in the credit agreement.

     At September 30, 2011, borrowings of approximately $252.9 million were outstanding under our new credit agreement, which includes approximately $52.9 million under the revolving credit facility. The weighted average interest rate on all borrowings outstanding under our new credit agreement as of September 30, 2011 was approximately 1.8%. We classify as short-term debt any borrowings under our revolving credit facility which have been designated as working capital borrowings and must be repaid within one year. Such borrowings are primarily related to a portion of our hedged natural gas inventory. At December 31, 2010, borrowings of approximately $260 million were outstanding under PNG’s previous revolving credit facility.

     Our revolving credit facility includes the ability to issue letters of credit. As of September 30, 2011, we had $3.0 million of outstanding letters of credit under our revolving credit facility.

     As of September 30, 2011, we were in compliance with the covenants required by our new credit agreement.

     In conjunction with the modification of our credit agreements, we incurred approximately $2.4 million of debt issuance costs, which together with the remaining unamortized debt issuance costs on our previous revolving credit facility, will be amortized over the term of our new credit agreement. Additionally, we accelerated the recognition of approximately $0.1 million of debt issuance costs related to our previous credit facility attributable to certain lenders that did not participate in our new credit agreement.

     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 nine months ended September 30, 2011 was approximately $4.1 million.

     Capitalized interest for the three and nine months ended September 30, 2011 was $2.7 million and $8.4 million, respectively, and $1.0 million and $6.5 million for the three and nine months ended September 30, 2010, respectively.

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 September 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.

     During the three months ended September 30, 2011, we received $3.0 million of property insurance proceeds related to the January 2011 operational incident and fire at our Bluewater facility.

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 September 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 issued in private placements			27,598,045				—				—				27,598,045
Vesting of LTIP awards			9,375												9,375
Balance, September 30, 2011			59,193,825				11,934,351				13,500,000				84,628,176

Distributions

     The following table details the distributions declared for 2011 quarterly periods or paid during the nine months ended September 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
October 11, 2011		November 14, 2011(1)		$21.2		$4.3		$0.2		$0.5		$26.2		$0.3575
July 11, 2011		August 12, 2011		$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

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								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Net income		$	15,445			$	9,620			$	37,659			$	19,975
Net loss on cash flow hedges			(3,573	)			(44	)			(3,317	)			(403	)
Total comprehensive income		$	11,872			$	9,576			$	34,342			$	19,572

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 nine months ended September 30, 2011 (amounts in thousands, except per unit data):

		Three Months Ended				Nine Months Ended
		September 30, 2011				September 30, 2011
Net income		$	15,445			$	37,659
Less: Incentive distributions due to general partner			222				388
Less: General partner’s 2% ownership interest			304				745
Net income available to limited partners		$	14,919			$	36,526
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income amongst limited partner interests:
Net income allocable to common units		$	12,416			$	30,047
Net income allocable to Series A subordinated units			2,503				6,479
Net income allocable to Series B subordinated units (1)			—				—
Net income available to limited partners		$	14,919			$	36,526
Denominator:
Basic weighted average number of limited partner units outstanding:(1)(2)(3)
Common units			59,191				55,345
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			59,202				55,360
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		$	0.21			$	0.54
Series A subordinated units		$	0.21			$	0.54
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 September 30, 2010 (amounts in thousands, except per unit data):

		Three Months Ended				May 5, 2010 Through
		September 30, 2010				September 30, 2010
Net income		$	9,620			$	14,547
Less: Incentive distributions due to general partner			—				—
Less: General partner’s 2% ownership interest			192				291
Net income available to limited partners		$	9,428			$	14,256
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income amongst limited partner interests:
Net income allocable to common units		$	6,686			$	10,024
Net income allocable to Series A subordinated units			2,742				4,232
Net income allocable to Series B subordinated units (1)			—				—
Net income available to limited partners		$	9,428			$	14,256
Denominator:
Basic weighted average number of limited partner units outstanding: (1)(2)(3)
Common units			31,586				31,585
Series A subordinated units			12,934				13,317
Series B subordinated units			—				—
Diluted weighted average number of limited partner units outstanding: (1)(2)(3)
Common units			31,591				31,590
Series A subordinated units			12,934				13,317
Series B subordinated units			—				—
Basic and diluted net income per limited partner unit: (1)(2)(3)
Common units		$	0.21			$	0.32
Series A subordinated units		$	0.21			$	0.32
Series B subordinated units		$	—			$	—

10. Equity Compensation Plans

Long Term Incentive Plan (“LTIP”)

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

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

						Weighted Average
						Grant Date
		Units				Fair Value per Unit
Outstanding, December 31, 2010			623			$	19.42
Granted			24			$	22.06
Vested			(9	)		$	23.31
Cancelled or forfeited			(30	)		$	19.14
Outstanding, September 30, 2011			608			$	19.48

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 nine months ended September 30, 2011 and 2010 (in thousands):

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Equity compensation expense (1)(2)(3)		$	702			$	671			$	3,360			$	1,514
LTIP cash settled vestings		$	—			$	317			$	580			$	471
DER cash payments		$	19			$	10			$	57			$	10

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 accompanying condensed consolidated statements of operations 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 nine months ended September 30, 2011, were $5.7 million and $14.7 million, respectively; and $4.6 million and $16.0 million for the three and nine months ended September 30, 2010, respectively. Of these amounts approximately $0.9 million and $2.7 million and $0.8 million and $2.6 million, during the three and nine month periods ended September 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 September 30, 2011 and December 31, 2010, PNG had amounts due to PAA of approximately $0.2 million and $0.6 million, respectively, included in accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheet.

     As of September 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 $0.9 million and $1.0 million, respectively. Approximately $0.5 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 September 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 September 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 September 30, 2011 under such guarantees and no payments were made to PAA under such guarantees during the three and nine months ended September 30, 2011. We 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. During the three and nine months ended September 30, 2011, we incurred approximately $16,000 and $20,000 of expense under our obligation to reimburse PAA for administrative costs incurred in conjunction with providing parental guarantees on our behalf.

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 capital costs associated with construction of 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. The Natural Gas Services Agreement has an initial term of ten years and is subject to annual renewals thereafter.

Natural Gas Sales

     During the three and nine months ended September 30, 2011, we recognized approximately $0.8 million of revenues from sales of natural gas to CDM Max.

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, unrealized 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								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Revenues (1)		$	79,334			$	25,083			$	184,118			$	71,446
Adjusted EBITDA		$	26,858			$	14,907			$	73,865			$	37,982
Maintenance capital		$	51			$	75			$	266			$	292
Long-lived assets (1)(2)		$	1,741,824			$	946,734			$	1,741,824			$	946,734
Total assets (2)		$	1,794,048			$	962,078			$	1,794,048			$	962,078

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Adjusted EBITDA		$	26,858			$	14,907			$	73,865			$	37,982
Selected items impacting Adjusted EBITDA:
Equity compensation expense			(681	)			(671	)			(3,339	)			(1,514	)
Mark-to-market of open derivative positions			132				—				235				370
Acquisition-related expenses			(5	)			—				(4,055	)			—
Insurance deductible related to property damage incident			—				—				(500	)			—
Depreciation, depletion and amortization			(9,193	)			(3,867	)			(24,602	)			(10,323	)
Interest expense, net of capitalized interest			(1,666	)			(749	)			(3,945	)			(6,540	)
Net Income		$	15,445			$	9,620			$	37,659			$	19,975

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 nine months ended September 30, 2011 was approximately $73.9 million, a 94% increase over Adjusted EBITDA of approximately $38.0 million for nine months ended September 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. Excluding acquisitions, expansion capital expenditures for the nine months ended September 30, 2011 were approximately $66.3 million. Additionally, in August 2011, we entered into a new $450 million five-year senior unsecured credit agreement, which replaced our $400 million, three year senior unsecured revolving credit facility that was scheduled to mature in May 2013. See “— Liquidity and Capital Resources — Overview” for further discussion.

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)
		September 30,								Variance(1)
		2011				2010				$				%
Revenues
Firm Storage Services
Reservation fees		$	33,862			$	22,487			$	11,375				51	%
Cycling fees and fuel-in-kind			1,674				1,286				388				30	%
Hub Services			1,830				689				1,141				166	%
Natural Gas Sales			40,718				—				40,718
Other			1,250				621				629				101	%
Total revenue		$	79,334			$	25,083			$	54,251				216	%
Storage related costs		$	(4,770	)		$	(5,101	)		$	331				6	%
Natural gas sales costs			(40,053	)			—				(40,053	)
Operating costs (except those shown below)			(3,070	)			(1,720	)			(1,350	)			(78	)%
Fuel expense			(762	)			(611	)			(151	)			(25	)%
General and administrative expenses			(4,368	)			(3,409	)			(959	)			(28	)%
Interest income and other income (expense), net			(7	)			(6	)			(1	)
Acquisition-related expenses			5				—
Insurance deductible related to property damage incident			—				—
Equity compensation expense			681				671
Mark-to-market of open derivative positions			(132	)			—
Adjusted EBITDA		$	26,858			$	14,907			$	11,951				80	%
Reconciliation to net income
Adjusted EBITDA		$	26,858			$	14,907			$	11,951				80	%
Depreciation, depletion and amortization			(9,193	)			(3,867	)			(5,326	)			(138	)%
Interest expense, net of capitalized interest			(1,666	)			(749	)			(917	)			(122	)%
Equity compensation expense			(681	)			(671	)
Acquisition-related expenses			(5	)			—
Mark-to-market of open derivative positions			132				—
Insurance deductible related to property damage incident			—				—
Net income		$	15,445			$	9,620			$	5,825				61	%
Operating Data:
Net revenue margin(2)(3)		$	34,379			$	19,982			$	14,397				72	%
Other operating expenses / G&A / Other			(7,521	)			(5,075	)			(2,446	)			(48	)%
Adjusted EBITDA		$	26,858			$	14,907			$	11,951				80	%
Average working capacity (Bcf)			74.6				50.0				24.6				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	)			(0.03	)
Adjusted EBITDA		$	0.12			$	0.10			$	0.02				20	%

		Nine Months Ended								Favorable/(Unfavorable)
		September 30,								Variance(1)
		2011				2010				$				%
Revenues
Firm Storage Services
Reservation fees		$	94,147			$	62,172			$	31,975				51	%
Cycling fees and fuel-in-kind			5,928				3,885				2,043				53	%
Hub Services			6,465				3,625				2,840				78	%
Natural Gas Sales			74,787				—				74,787
Other			2,791				1,764				1,027				58	%
Total revenue		$	184,118			$	71,446			$	112,672				158	%
Storage related costs		$	(14,908	)		$	(16,624	)		$	1,716				10	%
Natural gas sales costs			(72,785	)			—				(72,785	)
Operating costs (except those shown below)			(9,072	)			(5,144	)			(3,928	)			(76	)%
Fuel expense			(2,964	)			(1,665	)			(1,299	)			(78	)%
General and administrative expenses			(18,193	)			(11,163	)			(7,030	)			(63	)%
Interest income and other income (expense), net			10				(12	)
Acquisition-related expenses			4,055				—
Insurance deductible related to property damage incident			500				—
Equity compensation expense			3,339				1,514
Mark-to-market of open derivative positions			(235	)			(370	)
Adjusted EBITDA		$	73,865			$	37,982			$	35,883				94	%
Reconciliation to net income
Adjusted EBITDA		$	73,865			$	37,982			$	35,883				94	%
Depreciation, depletion and amortization			(24,602	)			(10,323	)			(14,279	)			(138	)%
Interest expense, net of capitalized interest			(3,945	)			(6,540	)			2,595				40	%
Equity compensation expense			(3,339	)			(1,514	)
Acquisition-related expenses			(4,055	)			—
Mark-to-market of open derivative positions			235				370
Insurance deductible related to property damage incident			(500	)			—
Net income		$	37,659			$	19,975			$	17,684				89	%
Operating Data:
Net revenue margin(2)(3)		$	96,190			$	54,452			$	41,738				77	%
Other operating expenses / G&A / Other			(22,325	)			(16,470	)			(5,855	)			(36	)%
Adjusted EBITDA		$	73,865			$	37,982			$	35,883				94	%
Average working capacity (Bcf)			69.4				46.0				23.4				51	%
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	%