UNITED STATES SECURITIES AND EXCHANGE
COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of
The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported)—August 4, 2010

PAA Natural Gas Storage, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE (State or other jurisdiction of incorporation)		1-34722 (Commission File Number)		27-1679071 (IRS Employer Identification No.)

333 Clay Street, Suite 1500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

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

(Former name or former address, if changed since last report.)

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 9.01.		Financial Statements and Exhibits

          (d) Exhibit 99.1 — Press Release dated August 4, 2010.

Item 2.02		and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure

     PAA Natural Gas Storage, L.P. (the “Partnership”) today issued a press release reporting its second quarter 2010 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01, we are providing detailed guidance for financial performance for the third and fourth quarters of calendar 2010 and for the full year 2010. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under this Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Third- and Fourth-Quarter 2010 Guidance; Full Year 2010 Guidance

     Adjusted EBITDA (as defined below in Note 1 to the “Operating and Financial Guidance” table) is a financial measure used by our chief operating decision maker to evaluate our segment performance. In Note 10 below, we reconcile Adjusted EBITDA to net income for the 2010 guidance periods presented. We encourage you to visit our website at www.pnglp.com (in particular the section entitled “Non-GAAP Reconciliation”), which presents a historical reconciliation of Adjusted EBITDA and certain commonly used non-GAAP financial measures. We present Adjusted EBITDA because it is a measure used by management to evaluate segment performance and because we believe it provides additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We believe that Adjusted EBITDA is used to assess our operating performance compared to other publically traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical costs basis. In addition, we have highlighted the impact of our selected items impacting comparability, including expenses associated with equity compensation plans, and gains and losses from derivative activities on EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

     We based our guidance for the three-month period ending September 30, 2010 and the three-month and twelve-month periods ending December 31, 2010 on assumptions and estimates that we believe are reasonable given our assessment of historical trends (modified for changes in market conditions), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from a variety of factors we believe to be relevant, including new expansion projects, changes in our portfolio of storage and services contracts, the seasonal nature of our business, and other market and competitive factors influencing the demand for storage services. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so we can provide no assurance that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of August 3, 2010. We undertake no obligation to publicly update or revise any forward-looking statements.

PAA Natural Gas Storage, L.P.
Operating and Financial Guidance
(in millions, except per unit data)

			Actual				Guidance
			6 Months				3 Months Ending								3 Months Ending								12 Months Ending
			Ended				September 30, 2010								December 31, 2010								December 31, 2010
			06/30/10				Low				High				Low				High				Low				High
	Firm storage services		$	42.3			$	24.1			$	24.3			$	24.3			$	24.5			$	90.7			$	91.1
	Hub services			2.9				0.8				1.6				0.7				1.5				4.4				6.0
	Other			1.2				0.3				0.5				0.9				1.1				2.4				2.8
	Total revenues			46.4				25.2				26.4				25.9				27.1				97.5				99.9
	Storage related costs			(11.5	)			(4.4	)			(4.2	)			(5.9	)			(5.7	)			(21.8	)			(21.4	)
	Other operating costs (except those shown below)			(3.4	)			(2.3	)			(2.1	)			(2.2	)			(2.0	)			(7.9	)			(7.5	)
	Fuel expense			(1.1	)			(1.4	)			(1.2	)			(0.7	)			(0.5	)			(3.2	)			(2.8	)
	General and administrative expenses			(7.7	)			(3.6	)			(3.4	)			(3.8	)			(3.6	)			(15.1	)			(14.7	)
	Depreciation, depletion and amortization			(6.5	)			(3.6	)			(3.6	)			(3.6	)			(3.6	)			(13.7	)			(13.7	)
	Total costs and expenses			(30.2	)			(15.3	)			(14.5	)			(16.2	)			(15.4	)			(61.7	)			(60.1	)
	Operating income			16.2				9.9				11.9				9.7				11.7				35.8				39.8
	Interest expense, net of capitalized interest			(5.8	)			(0.9	)			(0.8	)			(0.9	)			(0.8	)			(7.6	)			(7.4	)
	Net income		$	10.4			$	9.0			$	11.1			$	8.8			$	10.9			$	28.2			$	32.4
	Net income available to limited partners		$	4.8	*		$	8.8			$	10.9			$	8.6			$	10.7			$	22.2	*		$	26.4	*
	Net Income Per Limited Partner Unit (basic and diluted) (1)
	Weighted Average Units Outstanding			45.5				45.5				45.5				45.5				45.5				45.5				45.5
	Net income Per Limited Partner Unit		$	0.11	*		$	0.19			$	0.24			$	0.19			$	0.24			$	0.49	*		$	0.58	*
	EBITDA		$	22.7			$	13.5			$	15.5			$	13.3			$	15.3			$	49.5			$	53.5
	Selected Items Impacting Comparability
	Equity compensation charge		$	(0.8	)		$	(0.3	)		$	(0.3	)		$	(0.2	)		$	(0.2	)		$	(1.3	)		$	(1.3	)
	Mark-to-market of open derivative positions			0.4				—				—				—				—				0.4				0.4
			$	(0.4	)		$	(0.3	)		$	(0.3	)		$	(0.2	)		$	(0.2	)		$	(0.9	)		$	(0.9	)
	Excluding Selected Items Impacting Comparability
	Adjusted EBITDA		$	23.1			$	13.8			$	15.8			$	13.5			$	15.5			$	50.4			$	54.4
	Adjusted Net Income		$	10.8			$	9.3			$	11.4			$	9.0			$	11.1			$	29.1			$	33.3
	Adjusted Basic Net Income per Limited Partner Unit (1)		$	0.12	*		$	0.20			$	0.25			$	0.19			$	0.24			$	0.51	*		$	0.60	*

Notes and Significant Assumptions:

1.

Definitions.

EBITDA		Earnings before interest, taxes and depreciation, depletion and amortization.
Adjusted EBITDA		EBITDA excluding selected items impacting comparability.
Bcf		Billion cubic feet
Mcf		Thousand cubic feet
LTIP		Long-Term Incentive Plan
PAA		Plains All American Pipeline, L.P. (NYSE: PAA), the owner of our general partner, as well as a majority of our limited partner interests.
General partner (GP)		As the context requires, “general partner” or “GP” refers to any or all of (i) PNGS GP LLC, the owner of our 2% general partner interest and incentive distribution rights and (ii) PAA, the sole member of PNGS GP LLC.

2.

Business Overview. Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. We provide natural gas storage services to a broad mix of customers, including local gas distribution companies (LDCs), electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. Our storage rates are regulated under Federal Energy Regulatory Commission, or FERC, rate-making policies, which currently permit our facilities to charge market-based rates for our services. We currently own and operate two natural gas storage facilities located in Louisiana and Michigan that have an aggregate working gas storage capacity of 50 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. From time to time, we also lease storage capacity and pipeline transportation capacity from third parties in order to increase our operational flexibility and enhance the services we offer our customers. On a system-wide basis, natural gas is typically injected into storage between April and October when producer’s wellhead production and natural gas imports exceed end-user demand and typically withdrawn during the winter months of November through March to supplement producer’s wellhead production and natural gas imports, which in the aggregate are typically not sufficient to meet end-user demand. Acquisitions are expected to constitute an important element of our growth strategy; however, the accompanying detailed financial guidance does not include any forecasts for acquisitions that may be committed to after the date hereof.

We generate revenue almost exclusively from fee-based gas storage services to our customers, which include both “firm storage services” and “hub services.” We also generate a relatively small portion of our revenues from other sources as described below in “other revenues.”

	•		Firm Storage Services. Firm storage services include (i) storage services pursuant to which customers receive the assured or “firm” right to store gas in our facilities over a multi-year period and (ii) seasonal “park and loan” services pursuant to which customers receive the “firm” right to store gas in (park), or borrow gas from (loan), our facilities on a seasonal basis. Under our firm storage contracts, our customers are obligated to pay us fixed monthly capacity reservation fees, which are owed to us regardless of the actual storage capacity utilized. Firm storage services also include cycling fees based on the volume of natural gas nominated for injection and/or withdrawal as well as a small portion of natural gas nominated for injection that we retain as compensation for our fuel use (see “fuel expense” below). For the three-month period ending September 30, 2010 and the three-month period ending December 31, 2010, approximately 97% of our projected owned storage capacity is subject to existing multi-year contracts for firm storage services. Our revenue guidance for firm storage services is based primarily on the service fees provided for under such existing contracts, the service fees provided for under any existing seasonal park and loan contracts, and our estimate of revenues to be generated for un-contracted storage capacity under new contracts for firm storage services, if any. Additional components of our firm storage services revenue, such as cycling fees and fuel compensation, are dependent on the injection and withdrawal actions of our individual customers, both from a timing and volume perspective. Timing differences between forecasted activity and actual activity may result in a shifting of revenues between individual quarterly periods within a given storage season. Throughput differences may result in our ultimate realization of revenues being different from our forecasted amounts. A meaningful portion of revenues associated with fuel collections are offset by fuel related expenses (see discussion of “Fuel expense”).
	•		Hub Services. We also generate revenue from the provision of “hub services” at our facilities. Our capacity to provide hub services is primarily dependent on our outstanding obligations to customers under firm storage services contracts. As a result, increases in our firm storage services obligations may result in certain limitations in our ability to provide hub services and vice versa. Hub services include (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from our facilities. A

			portion of revenues related to these activities may include fuel collections which are offset by fuel related expenses (see discussion of “Fuel expense” below). Such activities are generally short-term in nature and the timing is influenced by weather, operating disruptions, foreign import activities and other conditions that result in temporary disruptions in supply and demand. Additionally, our wheeling and balancing activities are also influenced by certain market conditions such as location price differentials and other competing sources of transportation capacity. Accordingly, providing guidance on the overall amount and timing of revenue from these activities is less precise than those associated with firm storage services and thus we have provided for a wider range of potential performance on a relative basis during any given guidance period. Our overall revenue guidance for hub services is based on assumptions and estimates for an annual period that we believe are reasonable given our assessment of historical trends (modified for changes in market conditions) and other reasonably available information. Our revenue guidance for hub services for the third quarter of 2010 and three-month and twelve-month periods ending December 31, 2010 are based on an allocation of the full year guidance for 2010 and will vary throughout the projection period as actual information is obtained. As a result, absent new information, over-performance or underperformance in any given period may not increase or decrease the overall guidance for the full year of 2010, but may instead impact the allocation of such annual estimate among remaining projection periods.
	•		Other Revenues. We also generate revenues through the sale of crude oil and liquids produced in conjunction with the operation of our Bluewater facility, net of royalties and taxes. Due to injection and withdrawal cycles and related reservoir pressure considerations, we anticipate crude oil and liquids production will occur disproportionately in the first quarter of each year, a lesser amount in the second quarter and the balance over the third and fourth quarters of each year. Revenues from sales of crude oil and liquids are also impacted by changes in market prices. Our revenue guidance for these activities reflects our estimates of likely production based on these historical production patterns and our estimate of a net realizable price at the time of delivery. Our accompanying detailed guidance for financial performance for the third quarter of calendar 2010 and the three-month and twelve-month periods ending December 31, 2010 does not include forecasts with respect to potential gains or losses on derivative financial instruments as we do not believe that there is an accurate way to forecast such activity. Additionally, we periodically sell any fuel-in-kind volumes in excess of actual volumes needed as fuel to operate facilities and reflect any gain or loss on such sales.

		Effective June 1, 2010, we established a dedicated commercial optimization group to allow us to capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing opportunities. The positive benefits of this group are not expected to have a meaningful impact on our results until 2011 and, accordingly, our accompanying detailed guidance for financial performance for the third quarter of calendar 2010 and for the three-month and twelve-month periods ending December 31, 2010 incorporates the incremental overhead costs associated with these activities, but does not reflect any material incremental revenues that may be generated during the start-up period of our commercial optimization group.
		The following table summarizes our Adjusted EBITDA guidance for the forecasted periods, average owned working natural gas storage capacities and operating metrics.

		Actual(1)				2010 Guidance(1)(2)
		6 Months				3 Months				3 Months				12 Months
		Ended				Ending				Ending				Ending
		June 30,				Sep. 30,				Dec. 31,				Dec. 31,
Total revenues		$	46.0			$	25.8			$	26.5			$	98.3
Storage related costs			(11.5	)			(4.3	)			(5.8	)			(21.6	)
Net Revenue Margin			34.5				21.5				20.7				76.7
Operating costs / G&A / Other			(11.4	)			(6.7	)			(6.2	)			(24.3	)
Adjusted EBITDA		$	23.1			$	14.8			$	14.5			$	52.4
Average Working Storage Capacity (Bcf)(3)
Pine Prairie			19				24				24				22
Bluewater			26				26				26				26
			45				50				50				48
Average Monthly Operating Metrics ($/Mcf)
Net Revenue Margin		$	0.13			$	0.14			$	0.14			$	0.13
Operating costs / G&A / Other			(0.04	)			(0.04	)			(0.04	)			(0.04	)
Adjusted EBITDA		$	0.09			$	0.10			$	0.10			$	0.09

Net Revenue Margin is total revenues less storage related costs. Storage related costs consist of fees incurred to lease third-party storage and pipeline capacity and transaction costs associated with managing injection and deliverability capacity at our facilities. Costs associated with our leased pipeline capacity are subject to variation as the terms of these agreements typically contain certain fees which fluctuate based on actual volumes shipped in addition to monthly reservation fees. Our revenues generated through the use of leased assets, which are typically limited to a margin, are not significant to our results of operations when compared to activities generated from the assets which we own. Additionally, we enter into loans of our base gas to provide us greater flexibility in providing firm storage services and hub services. Costs incurred to enter into seasonal loan agreements are reflected as a component of storage related costs in our detailed guidance. Storage related costs are subject to fluctuation based on both the amount and timing of loan agreements we enter into and certain timing differences may occur between the recognition of costs associated with these loans and the corresponding firm storage services or hub services revenues generated from the operational flexibility provided by these loans.

Our primary expense components related to gas storage services comprise “fuel expense,” “operating costs” and “general and administrative expense.”

	•		Fuel expense. Natural gas is the primary fuel for our compressors, which are used to inject natural gas into our storage facilities and to boost the pressures for certain pipeline deliveries or transfers. Fuel-related expense may fluctuate materially from period to period due to variations in both the volume and value of natural gas consumed in our operations, with volumes being driven primarily by the volumes of natural gas injected into or wheeled through our facilities. During an annual cycle, we generally collect sufficient quantities of fuel from our customers through our cycling collections and hub services activities to offset the amount of fuel we consume (see revenue descriptions above), therefore our fuel expense is principally offset by fuel related revenue over an annual basis. However, the fuel consumed and collected may not be equivalent on a quarterly basis. Fuel expense is also impacted by our ability to maximize the efficiency of our operation of our facilities. We measure our fuel consumption using meters located at our central facilities. We charge fuel expense for the estimated volume consumed based on the weighted average price of fuel collected. Actual fuel revenue generated and consumed will vary with customer activity and may be influenced by weather and other factors.
	•		Operating Costs. Excluding fuel-related expenses, our operating costs typically do not materially vary based on the amount of natural gas we store. The timing of certain expenditures during a year generally fluctuates with customers’ demands, which change depending on market conditions and whether we are in the injection or withdrawal season for natural gas. Fluctuations in operating costs may occur due to the timing of planned maintenance activities as well as fluctuations in the level of project development and acquisition activity during a given period of time. Regulatory compliance can also impact our maintenance programs and affect the timing and amount of our expenditures.

•

General and Administrative Expense. Our guidance for the third quarter of calendar 2010 and for the three-month and twelve-month periods ending December 31, 2010 reflects an increase in our general and administrative expenses as a result of additional personnel and related costs associated with us becoming a publicly traded limited partnership and an increased level of acquisition evaluation activity. Such amounts also reflect the incremental cost associated with the establishment of our commercial optimization group. For guidance purposes, we anticipate we will routinely incur annual third party acquisition expenses. In accordance with Section 805 of the FASB’s Accounting Standards Codification, effective in 2009, we are required to expense costs related to acquisition evaluations as incurred, regardless of the success of such acquisition efforts. Accordingly, from time to time we may incur general and administrative expenses related to our acquisition efforts in excess of such guidance amounts. To the extent considered meaningful, such excess amounts will be classified as a selected item impacting comparability and thus excluded from Adjusted EBITDA, as such costs do not impact the operations of our existing assets and may benefit future periods. Our guidance for the remainder of 2010 includes approximately $250,000 of incremental acquisition related expenses.

3.

Depreciation, Depletion and Amortization. We forecast depreciation, depletion and amortization based on our existing depreciable assets, unamortized deferred debt costs, forecasted capital expenditures and projected in-service dates.

4.

Capital Expenditures. Excluding any potential acquisitions which we may commit to after the date hereof, we forecast capital expenditures during calendar 2010 to be approximately $95 million for expansion projects with an additional $0.6 million for maintenance capital projects as follows:

		Calendar 2010
		(in millions)
Expansion Capital
• Pine Prairie		$	92.5
• Bluewater			2.5
			95.0
Maintenance Capital			0.6
Total Projected Capital Expenditures (excluding acquisitions)		$	95.6

			During the first six months of 2010, we spent approximately $53.8 million and $0.2 million, respectively, for expansion and maintenance projects,
	5.		Capital Structure. This guidance is based on our capital structure as of June 30, 2010.
	6.		Interest Expense, net. Debt balances are projected based on estimated (i) operating cash flows, (ii) capital expenditures for maintenance / expansion projects and base gas purchases, (iii) working capital sources and uses and (iv) estimated distribution payments. Interest rate assumptions for variable rate debt are based on the current forward LIBOR curve. Included in interest expense are commitment fees and other financing costs. Interest expense is net of amounts capitalized for major expansion capital projects.
	7.		Net Income per Limited Partner Unit. We are required to prepare our earnings per unit computations in accordance with requirements contained in generally accepted accounting principles specific to master limited partnerships. As a result of our initial public offering, our outstanding limited partner interests as of June 30, 2010 consist of approximately 31.6 million common units, approximately 13.9 million Series A subordinated units and approximately 11.5 million Series B subordinated units. In addition to our outstanding 2.0% general partner interest and all of our incentive distribution rights, PAA owns approximately 18.1 million of our outstanding common units and all of our outstanding Series A and Series B subordinated units. Basic net income per limited partner unit is calculated by dividing net income allocated to each class of limited partner interest by the basic weighted average units outstanding for such limited partner interest during the period. The Series B subordinated units are not entitled to cash distributions unless and until they convert to Series A subordinated units or common units, which conversion is contingent on our meeting both certain distribution levels and certain in-service operational tests at our Pine Prairie facility. As a result, the Series B subordinated units are not included in the calculation of basic or diluted net income per unit in the following table.

		Actual				Guidance (in millions, except per unit data)
		6 Months				3 Months Ending								3 Months Ending								12 Months Ending
		Ended				September 30, 2010								December 31, 2010								December 31, 2010
		6/30/2010				Low				High				Low				High				Low				High
Numerator for basic and diluted earnings per limited partner unit:
Net Income		$	10.4			$	9.0			$	11.1			$	8.8			$	10.9			$	28.2			$	32.4
Less: Income earned prior to closing of IPO(1)			(5.5	)			—				—				—				—				(5.5	)			(5.5	)
Less: General partners incentive distribution paid (2)			—				—				—				—				—				—				—
Less: General partner 2% ownership			(0.1	)			(0.2	)			(0.2	)			(0.2	)			(0.2	)			(0.5	)			(0.5	)
Net income available to limited partners		$	4.8			$	8.8			$	10.9			$	8.6			$	10.7			$	22.2			$	26.4
Denominator
Weighted average number of units outstanding (basic and diluted)			45.5				45.5				45.5				45.5				45.5				45.5				45.5
Net income per limited partner unit (basic and diluted)		$	0.11			$	0.19			$	0.24			$	0.19			$	0.24			$	0.49			$	0.58

8.		Equity Compensation Plans. The majority of our outstanding equity compensation awards contain vesting criteria that are based either on (i) the later to occur of a specified date, or the date upon which a specified PNG distribution level is attained, or (ii) the conversion of our Series A and Series B subordinated units. For the majority of our outstanding equity compensation awards as of June 30, 2010, estimated vesting dates range from August 2011 to May 2015 and annualized PNG distribution levels range from $1.55 to $1.90. The majority of these awards are classified as equity awards for accounting purposes and thus the compensation expense recognized over the service period is based on the fair value of the awards on the grant date and is generally not subject to re-measurement prior to vesting. Upon vesting, our equity classified awards will result in the issuance of PNG common units.
		In addition to the awards described above, certain PNG officers have outstanding awards that were granted out of PAA’s equity compensation plans prior to our IPO. These awards contain performance conditions based on the attainment of specified annualized PAA distribution levels or the attainment of specified PNG EBITDA levels and are classified as liability awards. Upon vesting, these awards will result in a cash payment or the issuance of PAA common units. The impact of these awards on our guidance is immaterial.
		We have determined that an annualized distribution of $1.45 and the conversion of our Series A subordinated units and the conversion of the first tranche of the Series B subordinated units is probable of occurring and accordingly, for awards that vest upon annualized distribution levels of $1.45 or less, our guidance includes compensation expense accruals over the service period of the respective awards. The actual amount of equity compensation expense for any given period can vary as a result of future changes to our probability assessments relative to the performance conditions required for vesting and as a result of changes to our outstanding awards, such as granting additional awards or forfeitures.
9.		Reconciliation of Net Income to Adjusted EBTIDA. The following table reconciles net income to Adjusted EBTIDA for the three-month guidance range ending September 30, 2010 and three-month and twelve-month guidance ranges ending December 31, 2010.

		Guidance
		3 Months Ending								3 Months Ending								12 Months Ending
		September 30, 2010								December 31, 2010								December 31, 2010
		Low				High				Low				High				Low				High
Reconciliation to Adjusted EBITDA
Net Income		$	9.0			$	11.1			$	8.8			$	10.9			$	28.2			$	32.4
Interest expense, net of amounts capitalized			0.9				0.8				0.9				0.8				7.6				7.4
Depreciation, depletion and amortization			3.6				3.6				3.6				3.6				13.7				13.7
Selected Items Impacting Comparability
Equity Compensation Charge			0.3				0.3				0.2				0.2				1.3				1.3
Mark-to-market of open derivative positions			—				—				—				—				(0.4	)			(0.4	)
Adjusted EBTIDA		$	13.8			$	15.8			$	13.5			$	15.5			$	50.4			$	54.4

Forward-Looking Statements and Associated Risks

     All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives of our management 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 are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

	•		the impact of operational and commercial factors that could result in an inability on our part to satisfy our contractual commitments and obligations, including the impact of equipment performance, cavern operating pressures, and cavern temperature variances;
	•		risks related to the development and operation of natural gas storage facilities;
	•		failure to implement or execute planned internal growth projects on a timely basis and within targeted cost projections;
	•		interruptions in service and fluctuations in tariffs or volumes on third-party pipelines;
	•		general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns;
	•		the successful integration and future performance of acquired assets or businesses;
	•		our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;
	•		the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations;
	•		significantly reduced volatility in natural gas markets for an extended period of time;
	•		factors affecting demand for natural gas and natural gas storage services and the rates we are able to charge for such services;
	•		our ability to maintain or replace expiring storage contracts at attractive rates and on other favorable terms;
	•		the effects of competition;
	•		shortages or cost increases of power supplies, materials or labor;
	•		weather interference with business operations or project construction;
	•		our ability to receive open credit from our suppliers and trade counterparties;
	•		continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;
	•		the effectiveness of our risk management activities;
	•		the availability of, and our ability to consummate, acquisition or combination opportunities;
	•		environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
	•		increased costs or unavailability of insurance;
	•		fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plan;
	•		future developments and circumstances at the time distributions are declared; and
	•		other factors and uncertainties inherent in the development and operation of natural gas storage facilities.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

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 hereunto duly authorized.