Edgar Filing: PAA NATURAL GAS STORAGE LP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

¨	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		27-1679071
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

333 Clay Street, Suite 1500, Houston, Texas		77002
(Address of principal executive offices)		(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. x Yes ¨ 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). x Yes ¨ 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). ¨ Yes x No

As of May 2, 2012, 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:
Condensed Consolidated Balance Sheets: March 31, 2012 and December 31, 2011		3
Condensed Consolidated Statements of Operations: For the three months ended March 31, 2012 and 2011		4
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March, 31 2012 and 2011		5
Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income/(Loss): For the three months ended March 31, 2012		5
Consolidated Statements of Cash Flows: For the three months ended March 31, 2012 and 2011		6
Condensed Consolidated Statement of Changes in Partners’ Capital: For the three months ended March 31, 2012		7
Notes to the Condensed Consolidated Financial Statements:		8
1. Organization and Basis of Presentation		8
2. Recent Accounting Pronouncements		8
3. Accounts Receivable		9
4. Acquisition		9
5. Inventory and Base Gas		10
6. Goodwill		11
7. Debt		11
8. Net Income per Limited Partner Unit		12
9. Partners’ Capital and Distributions		14
10. Equity Compensation Plans		14
11. Derivatives and Risk Management Activities		16
12. Commitments and Contingencies		20
13. Operating Segments		21
14. Related Party Transactions		22
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		23
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		33
Item 4. CONTROLS AND PROCEDURES		33

PART II. OTHER INFORMATION		34
Item 1. LEGAL PROCEEDINGS		34
Item 1A. RISK FACTORS		34
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		34
Item 3. DEFAULTS UPON SENIOR SECURITIES		34
Item 4. MINE SAFETY DISCLOSURES		34
Item 5. OTHER INFORMATION		34
Item 6. EXHIBITS		34
SIGNATURES		35

PART I. FINANCIAL INFORMATION

Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PAA Natural Gas Storage, L.P. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except units)


	March 31, 2012			December 31, 2011
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	519		$	496
Accounts receivable		18,153			33,600
Natural gas inventory		32,812			50,942
Other current assets		10,196			8,917

Total current assets		61,680			93,955

Property and equipment
Property and equipment		1,322,555			1,311,553
Less: Accumulated depreciation, depletion and amortization		(35,478	)		(31,140	)

Property and equipment, net		1,287,077			1,280,413

Other assets
Base gas		48,672			48,432
Goodwill		325,470			325,470
Intangibles and other assets, net		95,602			101,729

Total other assets, net		469,744			475,631

Total assets	$	1,818,501		$	1,849,999

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	29,918		$	40,884
Short-term debt		37,367			67,992
Accrued taxes		1,779			1,296

Total current liabilities		69,064			110,172
Long-term liabilities
Note payable to PAA		200,000			200,000
Long-term debt under credit agreements		279,033			253,508
Other long-term liabilities		3,698			693

Total long-term liabilities		482,731			454,201

Total liabilities		551,795			564,373
Commitments and contingencies (Note 12)
Partners’ capital
Common unitholders (59,193,825 units issued and outstanding at March 31, 2012)		1,029,291			1,037,161
Subordinated unitholders (25,434,351 units issued and outstanding at March 31, 2012)		228,690			230,359
General partner		28,463			28,156
Accumulated other comprehensive income/(loss)		(19,738	)		(10,050	)

Total partners’ capital		1,266,706			1,285,626

Total liabilities and partners’ capital	$	1,818,501		$	1,849,999

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

(in thousands, except per unit data)


	Three Months Ended March 31, 2012			Three Months Ended March 31, 2011
	(unaudited)
Revenues:
Firm storage services	$	33,807		$	29,124
Hub services		3,136			2,401
Natural gas sales		70,620			18,096
Other		1,159			799

Total revenues		108,722			50,420

Costs and expenses:
Storage related costs		6,691			6,902
Natural gas sales costs		67,164			17,599
Other operating costs		3,047			3,087
General and administrative expenses		5,047			9,184
Depreciation, depletion and amortization		9,076			6,469

Total costs and expenses		91,025			43,241

Operating income		17,697			7,179
Other income/(expense)
Interest expense, net of capitalized interest		(1,668	)		(834	)
Other income/(expense), net		(11	)		—

Net income	$	16,018		$	6,345

Calculation of Limited Partner Interest in Net Income:
Net income	$	16,018		$	6,345
Less: General partner interest in net income		538			208

Limited partner interest in net income	$	15,480		$	6,137

Net income per limited partner unit
Common and Series A subordinated units⁽¹⁾(Basic)	$	0.22		$	0.10
Common and Series A subordinated units⁽¹⁾(Diluted)	$	0.22		$	0.10

Weighted average limited partner units outstanding
Common and Series A subordinated units ⁽¹⁾(Basic)		71,128			59,466
Common and Series A subordinated units ⁽¹⁾(Diluted)		71,238			59,480

(1) Excludes Series B subordinated units. See Note 8, “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 Statements of Comprehensive Income

(in thousands)


	Three Months Ended March 31,
	2012			2011
	(unaudited)
Net income	$	16,018		$	6,345
Other comprehensive income/(loss)		(9,688	)		1,340

Comprehensive income	$	6,330		$	7,685

PAA Natural Gas Storage, L.P. and Subsidiaries

Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income/(Loss)

(in thousands)


	Total
	(unaudited)
Balance, December 31, 2011	$	(10,050	)

Reclassification adjustments		(15,285	)
Deferred gain/(loss) on cash flow hedges, net		5,597

Total period activity		(9,688	)

Balance, March 31, 2012	$	(19,738	)

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

(in thousands)


	Three Months Ended March 31, 2012			Three Months Ended March 31, 2011
	(unaudited)
Cash flows from operating activities
Net income	$	16,018		$	6,345
Adjustments to reconcile to cash flow from operations
Depreciation, depletion and amortization		9,076			6,469
Equity compensation expense		1,139			1,396
Unrealized (gain)/loss on derivative instruments		14			(39	)
Changes in assets and liabilities, net of acquisitions
Accounts receivable and other assets		7,827			97
Natural gas inventory		14,253			—
Accounts payable and other liabilities		(8,879	)		4,013

Net cash provided by operating activities		39,448			18,281

Cash flows from investing activities
Additions to property and equipment		(12,387	)		(16,453	)
Cash paid in connection with acquisition, net of cash acquired		—			(751,527	)
Decrease/(increase) in restricted cash		—			17,606
Cash received/(paid) related to base gas sales/(purchases), net		4,295			—
Other investing activities		19			—

Net cash used in investing activities		(8,073	)		(750,374	)

Cash flows from financing activities
Borrowings under credit agreements		65,000			41,400
Repayments of borrowings under credit agreements		(70,100	)		(93,800	)
Borrowings from parent		—			200,000
Net proceeds from issuance of common units		—			587,868
Contributions from general partner		—			12,000
Distributions paid to unitholders		(25,428	)		(15,016	)
Distributions paid to general partner		(741	)		(357	)
Distribution equivalent right payments		(83	)		(15	)

Net cash provided by/(used in) financing activities		(31,352	)		732,080

Net increase/(decrease) in cash and cash equivalents		23			(13	)
Cash and cash equivalents, beginning of period		496			346

Cash and cash equivalents, end of period	$	519		$	333

Cash paid for interest, net of amounts capitalized	$	970		$	692

Noncash investing and financing activities
Change in non-cash asset purchases included in accounts payable	$	(166	)	$	2,244

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

(in thousands)


	Partners’ Capital											Accumulated
	Limited Partners											Other
				Subordinated					General			Comprehensive
	Common			Series A			Series B		Partner			Income/(Loss)			Total
	(unaudited)
Balance at December 31, 2011	$	1,037,161		$	128,568		$	101,791	$	28,156		$	(10,050	)	$	1,285,626

Net income		12,883			2,597			—		538			—			16,018
Equity compensation expense		492			—			—		510			—			1,002
Distributions to unitholders and general partner		(21,162	)		(4,266	)		—		(741	)		—			(26,169	)
Distribution equivalent right payments		(83	)		—			—		—			—			(83	)
Net deferred gain/(loss) on cash flow hedges		—			—			—		—			(9,688	)		(9,688	)

Balance at March 31, 2012	$	1,029,291		$	126,899		$	101,791	$	28,463		$	(19,738	)	$	1,266,706

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)

Note 1—Organization and Basis of Presentation

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

We currently own and operate three natural gas storage facilities located in Louisiana, Mississippi and Michigan. Our Pine Prairie and Southern Pines facilities are recently constructed, high-deliverability salt cavern natural gas storage complexes located in Evangeline Parish, Louisiana and Greene County, Mississippi, respectively. Our Bluewater facility is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. As of March 31, 2012, 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 76 billion cubic feet (“Bcf”). During the second half of 2010, we formed PNG Marketing, LLC as a commercial optimization company. PNG Marketing captures short-term market opportunities by utilizing a portion of our storage capacity and engaging in related commercial marketing activities.

As of March 31, 2012, 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 2011 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, 2011 was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. The results of operations for the three months ended March 31, 2012 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.

Property and Equipment

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

Note 2—Recent Accounting Pronouncements

Other than as discussed below and in our 2011 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the three months ended March 31, 2012 that are of significance or potential significance to us.

In September 2011, the FASB issued guidance with the purpose of simplifying 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 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued guidance regarding the presentation of other comprehensive income, which was later amended in December 2011, with the purpose of increasing the prominence of other comprehensive income in financial statements. This guidance, as amended, requires entities to present comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted the guidance, as amended, on January 1, 2012. Since this guidance only impacts the presentation of comprehensive income and does not change the composition or calculation of such financial information, adoption did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued guidance to amend certain fair value measurement and disclosure requirements in an effort to improve consistency with international reporting standards. The amendments generally clarify that the concepts of highest and best use and valuation premise in fair value measurement are relevant only when measuring the fair value of non-financial assets and are not relevant when measuring the fair value of financial assets or of liabilities. In addition, the guidance expanded disclosure requirements associated with (i) unobservable inputs for Level 3 fair value measurements and (ii) items that are not measured at fair value in the financial statements, but for which fair value is required to be disclosed. This guidance became effective prospectively for interim and annual reporting periods beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Other than requiring additional disclosure, which is included in Note 7, our adoption did not have a material impact on our financial position, results of operations or cash flows.

Note 3—Accounts Receivable

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2012 and December 31, 2011, substantially all of our accounts receivable were current and we had no allowance for doubtful accounts.

Our accounts receivable are from a broad mix of customers, including local gas distribution companies, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities.

To mitigate credit risks related to our accounts receivable, we have in place a rigorous credit review process. We closely monitor market conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, parental guarantees or advance cash payments. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables between the two) that cover substantially all of our natural gas purchases and sales transactions and also serve to mitigate credit risk.

Note 4—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 was approximately $765 million (approximately $750 million net of cash and other working capital acquired).

The purchase price allocation was as follows (in millions):


Description	Amount		Average Depreciable Life (in years)
Inventory	$	14		n/a
Property and equipment		340		5—70
Base gas		3		n/a
Other working capital (including approximately $13 million of cash acquired)		15		n/a
Intangible assets		92		2—10
Goodwill		301		n/a

Total	$	765

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 7) and approximately $600 million from the issuance of our common units (see Note 9).

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

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 purchase price that was escrowed at closing. 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. None of these funds were spent during the three months ended March 31, 2012.

Pro Forma Results

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


	Three Months Ended March 31,
	2011
Total revenues	$	54,383
Net income ⁽¹⁾	$	11,549
Limited partner interest in net income	$	11,236
Net income per limited partner unit ⁽²⁾
Basic	$	0.19
Diluted	$	0.19

(1)	Amount for the period excludes approximately $4.0 million of acquisition costs associated with the Southern Pines Acquisition.

(2)	Excludes Series B subordinated units. See Note 8, “Net Income per Limited Partner Unit.”

Note 5—Inventory and Base Gas

Inventory and base gas consisted of the following (natural gas volumes in thousands of Mcf and total value in thousands):


	March 31, 2012						December 31, 2011
			Unit of		Total				Unit of		Total
	Volumes		Measure		Value ⁽¹⁾		Volumes		Measure		Value ⁽¹⁾
Inventory
Natural gas⁽²⁾⁽³⁾		14,453		Mcf	$	32,812		16,170		Mcf	$	50,942

Inventory subtotal						32,812						50,942

Base Gas
Natural gas		14,105		Mcf		48,672		14,105		Mcf		48,432

Base gas subtotal						48,672						48,432

Total					$	81,484					$	99,374

(1)	Total value represents a weighted average associated with various locations; accordingly, these values may not coincide with any published benchmarks for such products.

(2)	Includes fuel inventory held for operational purposes.

(3)

As of March 31, 2012 and December 31, 2011, the carrying value of natural gas inventory reflects lower of cost or market adjustments of approximately $9.9 million and $6.1 million, respectively. Lower of cost or market adjustments are reflected as a component of natural gas sales costs in our accompanying condensed consolidated statement of operations. The impact of such adjustments were substantially offset by the recognition of unrealized gains on derivative instruments (see Note 11) being utilized to hedge the future sales of our natural gas inventory.

Note 6 — Goodwill

The table below reflects our changes in goodwill for the period indicated (in thousands):


	Total
Balance, December 31, 2011	$	325,470
2012 Goodwill Related Activity:
Acquisitions		—
Purchase price accounting adjustments and other		—

Balance, March 31, 2012	$	325,470

Note 7—Debt

Debt consisted of the following (in thousands):


	March 31,		December 31,
	2012		2011
SHORT-TERM DEBT
Senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.4% at both March 31, 2012 and December 31, 2011 ⁽¹⁾⁽²⁾	$	37,367	$	67,992

Total short-term debt		37,367		67,992

LONG-TERM DEBT
Senior unsecured revolving credit facility, bearing a weighted-average interest rate of 2.4% at both March 31, 2012 and December 31, 2011 ⁽¹⁾⁽²⁾		79,033		53,508
GO Zone term loans, bearing a weighted-average interest rate of 1.5% at both March 31, 2012 and December 31, 2011⁽²⁾		200,000		200,000
Promissory note due to PAA bearing interest at 5.25%⁽²⁾		200,000		200,000

Total long-term debt		479,033		453,508

Total debt ^{(1) (2)}	$	516,400	$	521,500

⁽¹⁾

We classify as short-term debt any borrowings under our senior unsecured revolving credit facility that have been designated as working capital borrowings and must be repaid within one year. Such borrowings are primarily related to a portion of our funded hedged natural gas inventory or NYMEX margin requirements. Approximately $0.2 million of interest expense attributable to such borrowings is reflected as a component of natural gas sales costs in the accompanying condensed consolidated statement of operations for the three months ended March 31, 2012.

⁽²⁾

We estimate that the fair value of borrowings outstanding under our credit agreement (including the revolving credit facility and Go Zone term loans) and our note payable to PAA approximate carrying value due to the short maturity of both obligations and the variable interest rate terms set forth under our credit agreement. Our fair value estimate for amounts outstanding under our credit agreement are based upon observable market data and are classified with Level 2 of the fair value hierarchy. With regards to our note payable to PAA, our fair valuation estimation process incorporates our estimated credit spread, an unobservable input. As such, we consider this to be a Level 3 measurement within the fair value hierarchy.

Our revolving credit facility includes the ability to issue letters of credit. As of March 31, 2012, we had $3.0 million of outstanding letters of credit under our revolving credit facility.

As of March 31, 2012, we were in compliance with the covenants required by our credit agreement.

Interest on the PAA Promissory Note is paid semiannually on the last business day of June and December. No interest was paid to PAA during the three months ended March 31, 2012 and 2011, respectively. Accrued interest payable due under the PAA Promissory Note (which is reflected as a component of accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheets) was approximately $2.6 million as of March 31, 2012.

Capitalized interest for the three months ended March 31, 2012, and 2011 was $2.4 million and $2.7 million, respectively.

Note 8—Net Income per Limited Partner Unit

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

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2012 and 2011(amounts in thousands, except per unit data):


	Three Months Ended		Three Months Ended
	March 31, 2012		March 31, 2011
Net income	$	16,018	$	6,345
Less: General partner’s incentive distribution		222		83
Less: General partner’s 2% ownership interest		316		125

Net income available to limited partners	$	15,480	$	6,137

Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income amongst limited partner interests:
Net income allocable to common units	$	12,883	$	4,905
Net income allocable to Series A subordinated units		2,597		1,232
Net income allocable to Series B subordinated units ⁽¹⁾		—		—

Net income available to limited partners	$	15,480	$	6,137

Denominator:
Basic weighted average number of limited partner units outstanding: ^(1)(2)(3)
Common units		59,194		47,532
Series A subordinated units		11,934		11,934
Series B subordinated units		13,500		13,500
Diluted weighted average number of limited partner units outstanding: ^(1)(2)(3)
Common units		59,304		47,546
Series A subordinated units		11,934		11,934
Series B subordinated units		13,500		13,500

Basic and diluted net income per limited partner unit: ^(1)(2)(3)
Common units	$	0.22	$	0.10
Series A subordinated units	$	0.22	$	0.10
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 March 31, 2012 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 March 31, 2012 therefore, there is no dilutive impact of such units in our determination of diluted net income per limited partner unit.

Note 9—Partners’ Capital and Distributions

Modification of Terms of Series B Subordinated Units

In February 2012, we modified the terms of the Partnership’s 13.5 million Series B subordinated units, which modification was approved by PAA, the owner of all of the Series B subordinated units. The Partnership’s Series B subordinated units do not participate in quarterly distributions. Instead, the Series B subordinated units convert into Series A subordinated units or common units in five distinct tranches upon the achievement of defined benchmarks tied to the amount of capacity in service at Pine Prairie and increases in our quarterly distributions. The modification increases the quarterly distribution benchmark for the first three of the five tranches, totaling 7.5 million Series B subordinated units in the aggregate, to an annualized level of $1.71 per unit. Previously, the quarterly distribution levels required to cause conversion for these three tranches were at annualized levels of $1.44, $1.53 and $1.63 per unit. The modification, which was made in recognition of the continued challenging market conditions facing the natural gas storage business, benefits our common unitholders by reducing the number of units on which distributions would otherwise be required to be paid in the case of distributions below the annualized level of $1.71. The following table presents the operational and financial benchmarks, as modified, for conversion of the Series B subordinated units into Series A subordinated units for each tranche (units in millions):


	Series B Subordinated Units to Convert into Series A Subordinated Units		Working Gas Storage Capacity (Bcf)		Annualized Distribution Level
Tranche 1		2.6		29.6	$	1.71
Tranche 2		2.8		35.6	$	1.71
Tranche 3		2.1		41.6	$	1.71
Tranche 4		3.0		48.0	$	1.71
Tranche 5		3.0		48.0	$	1.80

Outstanding Units

From December 31, 2011 through March 31, 2012, there were no changes in our issued and outstanding common, Series A subordinated or Series B subordinated units.

Distributions

The following table details the distributions declared for 2012 quarterly periods or paid during the three months ended March 31, 2012 (in millions, except per unit amounts):


				Series A								Distributions
		Common		Subordinated		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Units		Incentive		2%		Total		partner unit
April 10, 2012	May 15, 2012 ⁽¹⁾	$	21.2	$	4.3	$	0.2	$	0.5	$	26.2	$	0.3575
January 12, 2012	February 14, 2012	$	21.2	$	4.3	$	0.2	$	0.5	$	26.2	$	0.3575

(1)	Payable to unitholders of record on May 4, 2012, for the period January 1, 2012 through March 31, 2012

Equity Offerings

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.

Note 10—Equity Compensation Plans

Long Term Incentive Plan (“LTIP”)

For discussion of our equity compensation awards, see Note 12 to our consolidated financial statements included in Part IV of our 2011 Annual Report on Form 10-K.

In February 2012, the Board of Directors of our general partner approved the modification of certain equity compensation awards previously granted under the 2010 LTIP Plan. As a result of the modification, approximately 232,500 equity-classified phantom unit awards will now vest in the following manner: (i) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in February 2012, will vest upon the date we pay an annualized distribution of at least $1.45, (ii) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in May 2013, will vest upon the date we pay an annualized distribution of at least $1.50 and (iii) the remainder, with distribution equivalent rights also modified to begin payment in May 2014, will vest upon the date we pay an annualized distribution of at least $1.55. Fifty percent of any awards that have not vested as of the November 2016 distribution date will vest at that time and the remainder will expire. Additionally, 232,500 of equity-classified phantom unit awards with vesting terms originally tied to the conversion of our Series A and Series B subordinated units were modified such that all these awards will now fully vest upon conversion of the Series A subordinated units to common units. Distribution equivalent rights were also granted with respect to the these awards beginning February 2012.

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


			Weighted Average
			Grant Date
	Units ⁽¹⁾		Fair Value per Unit
Outstanding, December 31, 2011		499	$	19.53

Granted		120	$	15.05
Vested		—	$	—
Cancelled or forfeited		—	$	—

Outstanding, March 31, 2012 ⁽²⁾		619	$	15.84

(1)	Amounts do not include Class B units of PNGS GP LLC or transaction awards granted by PAA.

(2)	Weighted average grant date fair value per unit for PNG units outstanding at March 31, 2012, reflects the impact of the modification of PNG awards during February 2012, as discussed above.

The table below summarizes the expense recognized and unit or cash settled vestings related to all of our equity compensation plans during the three months ended March 31, 2012 and 2011 (in thousands):


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2012				2011
	Liability Awards		Equity Awards		Liability Awards		Equity Awards
Equity compensation expense⁽¹⁾	$	137	$	1,002	$	126	$	1,270
LTIP cash settled vestings	$	104	$	—	$	—	$	—
LTIP unit settled vestings	$	—	$	—	$	—	$	—
Distribution equivalent right payments	$	6	$	83	$	4	$	15

(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 $0.5 million and $1.1 million of compensation expense associated with these equity-classified awards during the three months ended March 31, 2012 and 2011, respectively.

Note 11—Derivatives 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. We use various derivative instruments to (i) manage our price exposure associated with anticipated purchases or sales of natural gas and (ii) 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 the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows of hedged items.

Commodity Price Risk Hedging

Our core business activities contain certain commodity price-related risks that we manage in various ways, including the use of derivative instruments. The material commodity-related risks inherent in our business activities can be summarized into the following general categories:

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell natural gas and sell crude oil produced at our Bluewater facility. We use various derivatives, including index swaps and basis swaps, to manage the associated risks and to optimize profits. As of March 31, 2012, net derivative positions related to these activities included:

•

A short swap position of approximately 21.9 Bcf through December 2012 related to anticipated sales of natural gas.

•

A short swap position of approximately 16,000 barrels through December 2012, which hedge a portion of our anticipated sales of crude oil produced at our Bluewater facility.

Base Gas Management — Our gas storage facilities require minimum levels of base gas to operate. For our natural gas storage facilities that are under construction, we anticipate purchasing base gas in future periods as construction is completed. We use derivatives to hedge such anticipated purchases of natural gas. As of March 31, 2012, we have a long swap position of approximately 3.5 Bcf through August 2014 related to anticipated base gas purchases.

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

For derivatives that qualify as a cash flow hedge, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions impact earnings. Derivatives that do not qualify or were not designated for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting change in cash flows of the hedged items are recognized in earnings each period.

A summary of the impact of our derivative activities recognized in earnings for the three months ended March 31, 2012 and 2011 is as follows (in thousands):


	Three Months Ended March 31, 2012
Location of gain/(loss)	Derivatives in Hedging Relationships^(1)(2)(4)			Derivatives not Designated as a Hedge⁽³⁾		Total
Commodity Derivatives
Natural gas sales	$	11,592		$	163	$	11,755
Natural gas sales costs		3,877			—		3,877
Other revenues		(261	)		168		(93	)
Interest Rate Derivatives
Interest expense		(104	)		—		(104	)
Total Gain/(Loss) on

Derivatives Recognized in Net Income	$	15,104		$	331	$	15,435


	Three Months Ended March 31, 2011
Location of gain/(loss)	Derivatives in Hedging Relationships^(1)(2)(4)			Derivatives not Designated as a Hedge⁽³⁾		Total
Commodity Derivatives
Natural gas sales	$	846		$	85	$	931
Natural gas sales costs		—			—		—
Other revenues		39			—		39
Interest Rate Derivatives
Interest expense		—			—		—
Total Gain/(Loss) on

Derivatives Recognized in Net Income	$	885		$	85	$	970

(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 include the ineffective portion of our cash flow hedges recognized in earnings.

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

(4)

Amounts include unrealized gains of approximately $3.9 million (reflecting the net change in the lower of cost or market adjustment from December 31, 2011 to March 31, 2012) reclassified from AOCI to earnings for the three months ended March 31, 2012 to offset a lower of cost or market adjustment relating to the carrying value of our inventory.

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of March 31, 2012 (in thousands):


	As of March 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	27,155	Other current assets	$	(14,248	)
	Other long-term liabilities		19	Other long-term liabilities		(2,728	)
Interest rate derivatives				Other current liabilities		(402	)
				Other long-term liabilities		(327	)

Total derivatives designated as hedging instruments		$	27,174		$	(17,705	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	179	Other current assets	$	(5	)

Total derivatives not designated as hedging instruments		$	179		$	(5	)

Total derivatives		$	27,353		$	(17,710	)

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


	As of December 31, 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	$	31,541	Other current assets	$	(16,766	)
	Other long-term assets		3,292	Other long-term assets		(1,896	)
Interest rate derivatives				Other current liabilities		(236	)
				Other long-term liabilities		(212	)

Total derivatives designated as hedging instruments		$	34,833		$	(19,110	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	138	Other current assets	$	(515	)
	Other long-term assets		5

Total derivatives not designated as hedging instruments		$	143		$	(515	)

Total derivatives		$	34,976		$	(19,625	)

Accumulated Other Comprehensive Income

As of March 31, 2012, there was a net loss of $19.7 million deferred in AOCI. 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 base gas purchases or other capital expansion expenditures. 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. Amounts related to other capital expansion activities will be reclassified to future earnings over the estimated useful live of the applicable asset. Deferred losses associated with capital expansion activities of approximately $12.9 million (including $10.5 million associated with base gas purchases) are included in AOCI as of March 31, 2012. Remaining amounts in AOCI as of March 31, 2012 are associated with both open and settled derivative positions. Of the total net loss deferred in AOCI at March 31, 2012, we expect to reclassify a net loss of approximately $6.2 million to earnings in the next twelve months. Amounts deferred are predominately based on market prices at the current period end, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

Amounts recognized in AOCI for derivatives and amounts reclassified to earnings during the three months ended March 31, 2012 and 2011 are as follows (in thousands):


	For the Three Months Ended March 31,
	2012			2011
Commodity derivatives, net ⁽¹⁾	$	5,494		$	2,100
Interest rate derivatives, net ⁽¹⁾		103			—
Reclassification adjustments, net ⁽²⁾		(15,285	)		(760	)

Total	$	(9,688	)	$	1,340

(1)	Amounts reflect net unrealized derivative gains and losses deferred in AOCI for the period. Negative amounts represent a net deferral of losses and positive amounts reflect a net deferral of gains on the applicable activity.

(2)

Reclassification adjustments represent transfers of deferred gains and losses out of AOCI and into earnings for the period. Negative amounts represent the reclassification of previously deferred net gains into earnings and positive amounts represent the reclassification of previously deferred net losses into earnings for the period. Reclassification adjustments may include realization of amounts originally deferred to AOCI in both the current period as well as prior periods.

Our accounting policy is to offset derivative assets and liabilities 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 the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of March 31, 2012, we had a net broker payable of approximately $5.2 million (consisting of initial margin of $5.6 million decreased by $10.8 million of variation margin returned to us). Our interest rate derivatives, which are over-the-counter instruments, do not have margin requirements. At March 31, 2012 and 2011, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.

Recurring Fair Value Measurements

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which affects the placement of assets and liabilities within the fair value hierarchy levels.


	Fair Value as of March 31, 2012										Fair Value as of December 31, 2011
	(in thousands)										(in thousands)
Recurring Fair Value Measures ⁽¹⁾	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Commodity derivatives	$	10,372	$	—		$	—	$	10,372		$	15,799	$	—		$	—	$	15,799
Interest rate derivatives		—		(729	)		—		(729	)		—		(448	)		—		(448	)

Total	$	10,372	$	(729	)	$	—	$	9,643		$	15,799	$	(448	)	$	—	$	15,351

(1)	Derivative assets and (liabilities) are presented above on a net basis but do not include any related cash margin deposits.

The determination of the fair values above includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives and interest-rate derivatives includes adjustments for credit risk. There were no changes to any of our valuation techniques during the period.

Note 12—Commitments and Contingencies

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.

Environmental

We may experience releases of natural gas, brine, crude oil or other contaminants into the environment, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such releases from our assets may substantially affect our business. As of March 31, 2012, we have not identified any such material obligations.

Insurance

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, including the potential loss of significant revenues.

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. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. For example, the market for hurricane-or windstorm-related property damage coverage has remained difficult the last few years. The amount of coverage available has been limited, and costs have increased substantially with the combination of premiums and deductibles.

As a result of these conditions, we did not renew this coverage in 2011 and, instead, self-insure this risk. This decision does not affect our third-party liability insurance, which still covers hurricane-related liability claims and which we have renewed at our historic levels. In addition, although we believe that we have established adequate reserves to the extent 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 conditions, results of operations or cash flows.

Property Tax Matter

In December 2011, we received a property tax bill from Evangeline Parish for approximately $1.4 million related to property that we believe is tax-exempt under the applicable lease agreement. To properly preserve our rights to dispute this billing, as required under applicable Louisiana state law, we have paid this billing, which relates to the 2011 tax year, under protest and have filed suit against Evangeline Parish seeking recovery of the amounts paid and declaratory relief that will insure our lease agreement is honored in the future. The approximately $1.4 million paid under protest is reflected as a component of other current assets on our accompanying condensed consolidated balance sheet as of March 31, 2012. We have not recognized any property tax expense related to this matter as this billing relates to property which is exempt from taxes in accordance with the terms of the lease agreement.

Note 13—Operating Segments

We manage our operations through three operating segments, Bluewater, Pine Prairie and Southern Pines. 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 to 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 March 31,
	2012		2011
Revenues	$	108,722	$	50,420

Adjusted EBITDA	$	27,815	$	19,500

Maintenance capital	$	182	$	106

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


	Three Months Ended March 31,
	2012			2011
Adjusted EBITDA	$	27,815		$	19,500
Selected items impacting Adjusted EBITDA:
Equity compensation expense		(1,039	)		(1,396	)
Mark-to-market of open derivative positions		(14	)		39
Acquisition-related expenses		—			(3,995	)
Insurance deductible related to property damage		—			(500	)
Depreciation, depletion and amortization		(9,076	)		(6,469	)
Interest expense, net of capitalized interest		(1,668	)		(834	)

Net Income	$	16,018		$	6,345

Note 14—Related Party Transactions

In addition to transactions between PNG and PAA discussed in Notes 4, 7, 9, 10 and 12, additional activities between PNG and PAA are discussed below.

Total costs reimbursed by us to PAA for the three months ended March 31, 2012 and 2011, were $4.7 million and $3.7 million, respectively. Of these amounts approximately $0.9 million and $0.9 million, during the three month periods ended March 31, 2012 and 2011, respectively, were allocated personnel costs for shared services and the remainder consisted of direct costs that PAA paid on our behalf along with our allocation of insurance premiums for participation in PAA’s insurance program.

As of March 31, 2012 and December 31, 2011, PNG had amounts due to PAA of approximately $2.9 million and $0.6 million, respectively, included in accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheet. Such amounts include accrued interest due under the PAA Promissory Note (see Note 7).

As of March 31, 2012 and December 31, 2011, PNG’s obligation for unvested equity-based compensation awards for which we are required to reimburse PAA upon vesting and settlement was approximately $1.4 million and $1.2 million, respectively. Approximately $0.7 million and $0.7 million of such amounts were reflected in accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets as of March 31, 2012 and December 31, 2011, respectively, with the remaining balances included as a component of other long-term liabilities at each respective date.

As of March 31, 2012, 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 March 31, 2012 under such guarantees and no payments were made to PAA under such guarantees during the three months ended March 31, 2012. 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 months ended March 31, 2012, we incurred approximately $13,000 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

During the three months ended March 31, 2012, we recognized approximately $0.4 million of access fee revenues under our Natural Gas Services Agreement with Plains Gas Solutions, LLC.

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.

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 2011 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.

Overview of Operating Results, Capital Spending and Significant Activities

Adjusted EBITDA for the three months ended March 31, 2012 was approximately $27.8 million, a 43% increase over Adjusted EBITDA of approximately $19.5 million for the three months ended March 31, 2011. This increase was primarily the result of the completion of the Southern Pines Acquisition on February 9, 2011 incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf during 2011 and results of PNG Marketing, LLC (our commercial optimization company). See “— Results of Operations” for further discussion and analysis of our operating results. Expansion capital expenditures for the three months ended March 31, 2012 were approximately $12.3 million.

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 March 31,						Favorable/(Unfavorable) Variance ⁽¹⁾
	2012			2011			$			%
Revenues
Firm storage services	$	33,807		$	29,124		$	4,683			16	%
Hub services and merchant storage ⁽²⁾		73,756			20,497			53,259			260	%
Other		1,159			799			360			45	%

Total revenues		108,722			50,420			58,302			116	%
Storage related costs - Hub services and merchant storage ⁽³⁾		(70,079	)		(19,402	)		(50,677	)		(261	)%
Storage related costs - Firm storage services ⁽⁴⁾		(3,776	)		(5,099	)		1,323			26	%
Other operating costs		(3,047	)		(3,087	)		40			1	%
General and administrative expenses		(5,047	)		(9,184	)		4,137			45	%
Other income/(expense), net		(11	)		—
Acquisition-related expenses		—			3,995
Insurance deductible related to property damage		—			500
Equity compensation expense		1,039			1,396
Mark-to-market of open derivative positions		14			(39	)

Adjusted EBITDA	$	27,815		$	19,500		$	8,315			43	%

Reconciliation to net income
Adjusted EBITDA	$	27,815		$	19,500		$	8,315			43	%
Depreciation, depletion and amortization		(9,076	)		(6,469	)		(2,607	)		(40	)%
Interest expense, net of capitalized interest		(1,668	)		(834	)		(834	)		(100	)%
Equity compensation expense		(1,039	)		(1,396	)
Acquisition-related expenses		—			(3,995	)
Mark-to-market of open derivative positions		(14	)		39
Insurance deductible related to property damage		—			(500	)

Net income	$	16,018		$	6,345		$	9,673			152	%

Operating Data:
Net revenue margin⁽⁵⁾⁽⁶⁾	$	34,881		$	25,880		$	9,001			35	%
Other operating expenses / G&A / Other		(7,066	)		(6,380	)		(686	)		(11	)%

Adjusted EBITDA	$	27,815		$	19,500		$	8,315			43	%

Average working storage capacity (Bcf)		76			59			17			28	%

Monthly Operating Metrics ($/Mcf):
Net revenue margin ⁽⁵⁾⁽⁶⁾	$	0.15		$	0.15		$	—			—
Operating expenses / G&A / Other		(0.03	)		(0.04	)		0.01			25	%

Adjusted EBITDA	$	0.12		$	0.11		$	0.01			9	%

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

(2)	Includes revenues associated with sales of natural gas through commercial marketing activities.

(3)	Includes costs associated with natural gas sold through commercial marketing activities and storage related costs (including fuel expense) attributable to hub services and merchant storage revenues.

(4)	Includes storage related costs (including fuel expense) attributable to firm storage services revenues.

(5)	Net revenue margin equals total revenues minus storage related costs.

(6)	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 March 31,
	2012			2011
Adjusted EBITDA reconciliation
Net income	$	16,018		$	6,345
Interest expense, net of amounts capitalized		1,668			834
Depreciation, depletion and amortization		9,076			6,469
Selected items impacting Adjusted EBITDA
Equity compensation expense		1,039			1,396
Acquisition-related expenses		—			3,995
Mark-to-market of open derivative positions		14			(39	)
Insurance deductible related to property damage		—			500

Adjusted EBITDA	$	27,815		$	19,500

Distributable cash flow reconciliation
Net income	$	16,018		$	6,345
Depreciation, depletion and amortization		9,076			6,469
Acquisition-related expenses		—			3,995
Maintenance capital expenditures		(182	)		(106	)
Other non cash items:
Equity compensation expense, net of cash payments		947			1,377
Mark-to-market of open derivative positions		14			(39	)

Distributable cash flow	$	25,873		$	18,041

Three Months Ended March 31, 2012 as Compared to the Three Months Ended March 31, 2011

Revenues, Volumes and Related Costs. As noted in the table above, our total revenue and related costs increased during the three months ended March 31, 2012 (the “2012 period”) when compared to the three months ended March 31, 2011 (the “2011 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) and incremental revenues attributable to the expansion of our working gas capacity at the Pine Prairie facility by approximately 8 Bcf during 2011. These and other significant variances related to these periods are discussed in more detail below:

•

Firm storage services — Firm storage services revenues increased in the 2012 period as compared to the 2011 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. These increases were partially offset by decreased storage rates on contracts executed to replace expiring contracts on existing capacity and lower fuel in kind revenues, both of which resulted from the deterioration of the natural gas market (including lower natural gas prices) thoughout 2011 and into 2012.

•

Hub services and merchant storage — Hub services and merchant storage revenues (which include revenues from sales of natural gas by our commercial optimization company) increased in the 2012 period as compared to the 2011 period. The primary reason for the increase in 2012 as compared to 2011 is due to an increase in volumes of natural gas sold by our commercial optimization company.

•

Other — Other revenues increased in the 2012 compared to the 2011 period primarily due to approximately $0.4 million of access fee revenues generated under our natural gas services agreement with Plains Gas Solutions, LLC.

•

Storage related costs- Hub services and merchant storage — Hub services and merchant storage related costs (which includes costs associated with natural gas sold by our commercial optimization company) increased in the 2012 period as compared to the 2011 period. The primary reason for the increase in 2012 as compared to 2011 is due to the increase in volumes of natural gas sold by our commercial optimization company.

•

Storage related costs — Firm storage services — Firm storage services related costs decreased in the 2012 period as compared to the 2011 period. The decrease in 2012 as compared to 2011 is primarily due to lower fuel costs, resulting from a decline in natural gas prices, and a reduction in storage capacity leased from third parties.

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

•

Other operating costs — Other operating costs did not change significantly in the 2012 period when compared to the 2011 period. Increases in operating expenses during the 2012 period associated with the previously mentioned Southern Pines Acquisition and Pine Prairie expansion were approximately offset by $0.5 million of expense recognized during the 2011 period for the property insurance deductible related to the January 2011 operational incident and fire at our Bluewater facility.

•

General and administrative expenses — General and administrative expenses decreased in the 2012 period as compared to the 2011 period. The 2011 period includes approximately $4.0 million of acquisition-related costs associated with the Southern Pines Acquisition. Additionally, we recognized approximately $0.5 million and $1.1 million of equity compensation expense associated with awards granted by PAA during the 2012 and 2011 periods, respectively. Although we will not bear the economic burden of these awards, we benefit from the services underlying these awards.

•

Depreciation, depletion and amortization — Depreciation, depletion and amortization expense increased in the 2012 period as compared to the 2011 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 and $2.3 million during the 2012 and 2011 periods, respectively.

•

Interest expense, net of capitalized interest — Interest expense, net of capitalized interest, increased in the 2012 period when compared to the 2011 period. Interest expense, on a gross basis, increased to approximately $4.1 million in the 2012 period as compared to approximately $3.5 million in the 2011 period. Interest expense, on a gross basis, increased due to higher average debt balances outstanding in the 2012 period as compared to the 2011 period and was partially offset by a decrease in average interest rates in the 2012 period as compared to the 2011 period. Capitalized interest was approximately $2.4 million and $2.7 million in the 2012 and 2011 periods, respectively.

Outlook

In the first quarter of 2012, overall market conditions for both hub services and firm storage services were slightly better than the conditions experienced during 2011, but still reflected seasonal spreads (October-January) and volatility levels that were low relative to historical trends. During the first quarter of 2012, seasonal spreads for 2012-2013, which are a proxy for the current fundamental value of storage, ranged from $0.52 to $0.77, which was slightly improved relative to the range for spreads during the first quarter of 2011 ($0.43 to $0.63), but at the low end of the range during most of the past decade ($0.37-$4.75). However, the slight improvement in 2012-2013 seasonal spreads during the first quarter of 2012 has not translated into an improvement in seasonal spreads for later years (i.e., beyond 2013). Seasonal spreads for 2013-2014 and 2014-2015, which influence the rates at which we will be able to contract firm storage capacity in future years, have ranged from $0.36 to $0.48. Volatility levels, which impact the value we are able to realize on a short-term basis from our hub service and merchant storage activities, have also increased somewhat during the first part of 2012, but remain low relative to levels experienced during the 2005-2010 time period. Driven largely by the robust supply levels for natural gas, both in terms of natural gas storage inventory levels and the production from shale resources, recent increases in volatility levels have been relatively short in duration. In general, our outlook for the balance of 2012 presumes that these fundamental trends will continue, with relatively low seasonal spreads and reduced volatility levels from a historical perspective.

We believe our asset base, contract profile, financial position, low risk profile, and economically attractive expansion projects will enable us to maintain our cash flows for the next several years in the current conditions. Also, we are reasonably well positioned

to develop low cost organic expansions and to acquire other assets if favorable market conditions exist. However, if gas storage market conditions decline further, 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 adverse overall market conditions. In addition, we can provide no assurances that our organic growth and acquisition 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, natural gas purchases 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 short-term and 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 agreement, and/or proceeds from the issuance of additional equity or debt securities.

During 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”). Although the Dodd-Frank Act includes provisions regarding the use of financial instruments, and the scope and applicability of these provisions as implemented may continue to develop, our current assessment is that the direct effects of the Dodd-Frank Act on PNG will be limited to additional documentation and record-keeping requirements. We cannot, however, predict the effect the Dodd-Frank Act may have on the futures and capital markets, which may affect the depth and quality of our counterparties and lenders and, as a result, our liquidity and access to capital.

Credit Agreement

In August 2011, we entered into a $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. 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.

Our credit agreement contains covenants and events of default. 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 March 31, 2012, borrowings of approximately $316.4 million were outstanding under our credit agreement, which includes approximately $116.4 million under the revolving credit facility. Additionally, we had approximately $3.0 million of outstanding letters of credit under our revolving credit facility. As of March 31, 2012, we were in compliance with the covenants, including the financial ratios, contained in our credit agreement. Based on the most restrictive covenant, at March 31, 2012 our incremental borrowing ability under our credit agreement was limited to approximately $131 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.

PAA Financial Support

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. As of March 31, 2012, 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 March 31, 2012 under such guarantees and no payments were made to PAA under such guarantees during the three months ended March 31, 2012.

Sources of Liquidity

Our current sources of liquidity include:

•

cash generated from operations;

•

borrowings under our credit agreement;

•

issuances of additional partnership units; and

•

debt offerings.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, and quarterly cash distributions to unitholders.

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 have not issued any securities under the Traditional Shelf.

To maintain our targeted credit profile, we generally intend to fund approximately 60% of the capital required for future expansion projects with equity and cash flow in excess of distributions.

For a discussion of the impact that the price of natural gas might have on our operations and liquidity and capital resources, see Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

Working Capital

Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven primarily by changes in accounts receivable and accounts payable, natural gas inventory balances and short-term debt. These changes are primarily affected by factors such as credit extended to, and the timing of collections from, our customers and our level of spending for maintenance and expansion activity. As of March 31, 2012 we had a working capital deficit of approximately $7.4 million.

Historical Cash Flow Information

The following table presents a summary of our cash flows for the three months ended March 31, 2012 and 2011 (in thousands):


	Three Months Ended March 31,
	2012			2011
Net cash provided by (used in):
Operating activities	$	39,448		$	18,281
Investing activities		(8,073	)		(750,374	)
Financing activities		(31,352	)		732,080

Net increase/(decrease) in cash	$	23		$	(13	)

Adjusted EBITDA	$	27,815		$	19,500

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. Cash provided by operating activities is significantly impacted in periods where we are increasing or decreasing the amount of inventory in storage. In the month that we pay for stored natural gas, we borrow under our credit facility to pay for the natural gas, which negatively impacts our operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored natural gas. During 2012 our cash generated from our recurring operations increased over 2011and was positively impacted by a reduction in inventory balances.

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

Financing Activities. Our financing activities primarily consist of (i) the payment of distributions to our unitholders and general partner, (ii) funding of capital expansion efforts (including organic growth projects and acquisitions) and (iii) borrowings and repayments under our credit agreement associated with inventory purchases and sales in conjunction with our merchant storage activities. The 2011 period includes borrowings and equity issuances associated with the funding of the Southern Pines Acquisition.

Capital Expenditures and Distributions to our Unitholders and General Partner

In addition to operating activities discussed above, we also use cash for our acquisition activities, purchases of natural gas inventory, 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.

Capital Expenditures. We currently forecast capital expansion expenditures for 2012 of approximately $55 million to $60 million (including capitalized interest), primarily related to the ongoing expansion of our Pine Prairie and Southern Pines facilities and the related base gas required to operate the facilities. We expect to fund our capital expenditures with cash generated from operations and borrowings under our credit agreement. Additionally, we are forecasting approximately $0.6 million of maintenance capital expenditures in 2012, of which approximately $0.2 million was incurred through March 31, 2012.

Distributions to Unitholders and General Partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On May 15, 2012, we will pay a quarterly distribution of $0.3575 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 12 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. Additionally, we purchase natural gas from third parties for both commercial and operational purposes. We establish a margin on gas purchased for commercial purposes by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. The table below includes purchase obligations related to these activities. We do not expect to use a significant amount of internal capital on a long-term basis to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy.


	Total		2012		2013		2014		2015		2016		Thereafter
Long-term debt, interest and fees ⁽¹⁾		522.6		12.0		15.9		206.7		5.5		282.5		—
Short-term borrowings		37.4		37.4		—		—		—		—		—
Storage / transportation agreements and lease		26.5		13.1		6.7		4.5		2.0		—		0.2
Purchase obligations ⁽²⁾		24.7		9.2		1.9		1.9		1.9		1.9		7.9
Other long-term liabilities		3.0		0.7		1.0		0.7		0.4		0.1		0.1

Subtotal		614.2		72.4		25.5		213.8		9.8		284.5		8.2
Natural gas purchases ⁽³⁾		68.3		68.3		—		—		—		—		—

Total		682.5		140.7		25.5		213.8		9.8		284.5		8.2

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

(2)	Primarily includes amounts related to utility contracts and capital expansion activities.

(3)

Amounts are based on estimated volumes and market prices based on committed obligations as of March 31, 2012. 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 and Parental Guarantees. Our $450 million senior unsecured credit agreement provides us with the ability to issue letters of credit. In connection with our use of certain leased storage and transportation assets and the purchase of natural gas by our commercial optimization company, we have periodically provided certain suppliers and counterparties with irrevocable standby letters of credit to secure our obligations for such purchases. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our consolidated balance sheet in the month the services are provided or when we take delivery of the natural gas purchased. In certain instances, parental guarantees have been provided by PAA in lieu of letters of credit. As of March 31, 2011, we had approximately $3 million of outstanding letters of credit under our credit agreement. Additionally, approximately $31 million of parental guarantees issued by PAA on behalf of PNG Marketing were outstanding as of March 31, 2011.

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

See Note 2 to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates

For discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2011 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. The most important of these factors include, but are not limited to:

•

a continuation of 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 revenues from hub services and merchant storage transactions involving uncontracted or unutilized capacity at our facilities;

•

the effects of competition;

•

the impact of operational, geologic 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, cavern temperature variances, salt creep and subsurface conditions or events;

•

risks related to the ownership, 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;

•

operational, 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;

•

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;

•

our ability to obtain and/or maintain all permits, approvals and authorizations that are necessary to conduct our business and execute our capital projects;

•

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;

•

the operations or financial performance of assets or businesses that we acquire;

•

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

•

increased costs or unavailability of insurance; and

•

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

•

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

Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2011 Annual Report on Form 10-K. 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 2011 Annual Report on Form 10-K. There have been no material changes to that information other than as discussed below. Also, see Note 11 to the condensed consolidated financial statements for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

The fair value of our outstanding natural gas derivatives as of March 31, 2012 was a net asset of approximately $10.4 million. A 10% increase in natural gas prices would result in a net asset of approximately $4.6 million. A 10% decrease in natural gas prices would result in a net asset of approximately $16.2 million.

Interest Rate Risk

The fair value of our outstanding interest rate swap agreements as of March 31, 2012 was a net liability of approximately $0.7 million. A 10% increase in interest rates would result in a net liability of approximately $0.6 million. A 10% decrease in interest rates would result in a net liability of approximately $0.8 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 information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (“the Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) 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 12 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 2011 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. Mine Safety Disclosures

None.

Item 5. Other Information

None.

Item 6. Exhibits

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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: May 8, 2012	By:	/s/ GREG L. ARMSTRONG
		Name:	Greg L. Armstrong
		Title:	Chairman and Chief Executive Officer
			(Principal Executive Officer)

Date: May 8, 2012	By:	/s/ DEAN LIOLLIO
		Name:	Dean Liollio
		Title:	President

Date: May 8, 2012	By:	/s/ AL SWANSON
		Name:	Al Swanson
		Title:	Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

EXHIBIT INDEX


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	–	Amendment No. 1 dated February 2, 2012 to Second Amended and Restated Agreement of Limited Partnership of PAA Natural Gas Storage, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 8, 2012).

3.4	–	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).

3.5	–	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).

10.1†	–	Form of Phantom Unit Grant Letter (Category 1) (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K for the year ended December 31, 2011).

10.2†	–	Form of Phantom Unit Grant Letter (Category 2) (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K for the year ended December 31, 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.INS*	–	XBRL Instance Document

101.SCH*	–	XBRL Taxonomy Extension Schema Document

101.CAL*	–	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	–	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	–	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	–	XBRL Taxonomy Extension Presentation Linkbase Document

†	Management compensatory plan or arrangement.

*	Filed herewith.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company