Williams Partners 10-Q 2013 Q1 Quarterly report

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, 2013

¨ Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                    to                    

Commission File No. 1-34831

Access Midstream Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	80-0534394
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
525 Central Park Drive
Oklahoma City, Oklahoma	73105
(Address of principal executive offices)	(Zip Code)

(405) 935-7800

(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.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    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.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

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

As of April 26, 2013, the registrant had 107,724,374 common units outstanding.

ACCESS MIDSTREAM PARTNERS, L.P.

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2013

	PART I.
Financial Information
			Page
Item 1.	Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012			1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012			2
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012			3
	Condensed Consolidated Statement of Changes in Partners’ Capital for the Three Months Ended March 31, 2013			4
	Notes to Condensed Consolidated Financial Statements			5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			39
Item 4.	Controls and Procedures			40
	PART II.
Other Information
Item 1.	Legal Proceedings			41
Item 1A.	Risk Factors	��		41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			41
Item 3.	Defaults Upon Senior Securities			41
Item 4.	Mine Safety Disclosures			41
Item 5.	Other Information			41
Item 6.	Exhibits			42

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2013			December 31, 2012
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	312		$	64,994
Accounts receivable		154,545			133,543
Prepaid expenses		16,058			13,978
Other current assets		9,030			7,251
Total current assets		179,945			219,766
Property, plant and equipment:
Gathering systems		5,365,728			5,125,746
Other fixed assets		109,824			96,916
Less: Accumulated depreciation		(650,849	)		(590,614	)
Total property, plant and equipment, net		4,824,703			4,632,048
Investment in unconsolidated affiliates		1,443,033			1,297,811
Intangible customer relationships, net		349,339			355,217
Deferred loan costs, net		54,394			56,258
Total assets	$	6,851,414		$	6,561,100
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	36,245		$	47,987
Accrued liabilities		238,296			211,274
Total current liabilities		274,541			259,261
Long-term liabilities:
Long-term debt		2,777,000			2,500,000
Other liabilities		5,501			5,333
Total long-term liabilities		2,782,501			2,505,333
Commitments and contingencies (Note 7)
Partners’ capital:
Common units (97,374,243 and 97,324,453 issued and outstanding at March 31, 2013 and December 31, 2012, respectively)		2,160,074			2,188,241
Subordinated units (69,076,122 issued and outstanding at March 31, 2013 and December 31, 2012)		822,754			834,001
Class B units (12,020,774 and 11,858,050 issued and outstanding at March 31, 2013 and December 31, 2012)		283,307			273,858
Class C units (11,199,268 issued and outstanding at March 31, 2013 and December 31, 2012)		301,707			295,551
General partner interest		94,002			93,182
Total partners’ capital attributable to Access Midstream Partners, L.P.		3,661,844			3,684,833
Noncontrolling interest		132,528			111,673
Total partners’ capital		3,794,372			3,796,506
Total liabilities and partners’ capital	$	6,851,414		$	6,561,100

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

1

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	($ in thousands, except per unit data)
Revenues	$	236,959		$	154,674
Operating expenses:
Operating expenses		82,763			48,682
Depreciation and amortization expense		66,650			38,438
General and administrative expense		23,734			11,478
Other operating expense (income)		91			(45	)
Total operating expenses		173,238			98,553
Operating income		63,721			56,121
Other income (expense):
Income from unconsolidated affiliates		25,008			12,987
Interest expense		(27,062	)		(15,958	)
Other income		269			55
Income before income tax expense		61,936			53,205
Income tax expense		1,240			839
Net income		60,696			52,366
Net income attributable to noncontrolling interests		1,158			—
Net income attributable to Access Midstream Partners, L.P.	$	59,538		$	52,366
Limited partner interest in net income
Net income attributable to Access Midstream Partners, L.P.	$	59,538		$	52,366
Less general partner interest in net income		(4,792	)		(1,429	)
Limited partner interest in net income	$	54,746		$	50,937
Net income per common unit – basic and diluted	$	0.14		$	0.34
Net income per subordinated unit – basic and diluted	$	0.29		$	0.34

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

2

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	($ in thousands)
Cash flows from operating activities:
Net income	$	60,696		$	52,366
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		66,650			38,438
Income from unconsolidated affiliates		(25,008	)		(12,987	)
Other non-cash items		4,135			1,932
Changes in assets and liabilities:
Increase in accounts receivable		(29,774	)		(33,058	)
Increase in other assets		(4,054	)		(1,694	)
Decrease in accounts payable		(11,743	)		(7,832	)
Increase in accrued liabilities		19,228			30,050
Net cash provided by operating activities		80,130			67,215
Cash flows from investing activities:
Additions to property, plant and equipment		(270,954	)		(80,593	)
Investments in unconsolidated affiliates		(111,808	)		(45,276	)
Proceeds from sale of assets		26,134			421
Net cash used in investing activities		(356,628	)		(125,448	)
Cash flows from financing activities:
Proceeds from long-term debt borrowings		715,900			245,600
Payments on long-term debt borrowings		(438,900	)		(870,500	)
Proceeds from issuance of senior notes		—			750,000
Distribution to unitholders		(84,073	)		(58,932	)
Capital contribution from noncontrolling interests		18,980			—
Debt issuance costs		—			(13,653	)
Other adjustments		(91	)		5,721
Net cash provided by financing activities		211,816			58,236
Net increase (decrease) in cash and cash equivalents		(64,682	)		3
Cash and cash equivalents, beginning of period		64,994			22
Cash and cash equivalents, end of period	$	312		$	25
Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	1,034		$	(3,565	)
Changes in other liabilities related to asset retirement obligations	$	67		$	—

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

3

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)

	Partners’ Equity
	Limited Partners												General Partner			Non controlling Interest
	Common			Subordinated			Class B			Class C								Total
Balance at December 31, 2012	$	2,188,241		$	834,001		$	273,858		$	295,551		$	93,182		$	111,673	$	3,796,506
Net income		28,264			19,837			3,429			3,216			4,792			1,158		60,696
Distribution to unitholders		(43,818	)		(31,084	)		—			(5,040	)		(4,131	)		—		(84,073	)
Contributions from noncontrolling interest owners		—			—			—			—			—			19,697		19,697
Non-cash equity based compensation		1,387			—			—			—			—			—		1,387
Issuance of general partner interests		—			—			—			—			159			—		159
Beneficial conversion feature of Class B and Class C units		720			—			(720	)		—			—			—		—
Amortization of beneficial conversion feature of Class B and Class C units		(14,720	)		���			6,740			7,980			—			—		—
Balance at March 31, 2013	$	2,160,074		$	822,754		$	283,307		$	301,707		$	94,002		$	132,528	$	3,794,372

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

4

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Description of Business and Basis of Presentation

Organization

Access Midstream Partners, L.P. (the “Partnership”), a Delaware limited partnership formed in January 2010, is principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. The Partnership is the industry’s largest gathering and processing master limited partnership as measured by throughput volume. The Partnership’s assets are located in Arkansas, Kansas, Louisiana, Maryland, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia, West Virginia and Wyoming. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”), Total Gas and Power North America, Inc. (“Total”), Statoil ASA (“Statoil”), Anadarko Petroleum Corporation (“Anadarko”), Mitsui & Co., Ltd. (“Mitsui”) and other producers under long-term, fixed-fee contracts.

For purposes of these financial statements, the “GIP I Entities” refers to, collectively, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P., the “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, and “GIP” refers to the GIP I Entities and their affiliates and the GIP II Entities, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).

Acquisition

On December 20, 2012, the Partnership acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of CMD’s affiliates, 100 percent of the issued and outstanding equity interests in Chesapeake Midstream Operating, L.L.C. (“CMO”) for total consideration of $2.16 billion (the “CMO Acquisition”). As a result of the CMO Acquisition, the Partnership now owns certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended the Partnership’s assets and operations in the Haynesville, Marcellus and Mid-Continent regions. The acquired assets included, in the aggregate, approximately 1,675 miles of pipeline and 4.3 million (gross) dedicated acres as of the date of the acquisition. The Partnership also assumed various gas gathering and processing agreements associated with the assets that have terms ranging from 10 to 20 years and that, in certain cases, include cost of service or fee redetermination mechanisms.

Concurrently with the CMO Acquisition, the GIP I Entities sold to Williams 34,538,061 of the Partnership’s subordinated units and 50% of the outstanding equity interests in Access Midstream Ventures, L.L.C., the sole member of the Partnership’s general partner, for cash consideration of approximately $1.8 billion (the “Williams Acquisition”). The Partnership did not receive any cash proceeds from the Williams Acquisition. As a result of the closing of the Williams Acquisition, the GIP II Entities and Williams together own and control the Partnership’s general partner and the GIP I Entities no longer have any ownership interest in the Partnership or its general partner.

Equity Issuance

On December 18, 2012, the Partnership completed an equity offering of 18.4 million common units, including 2.4 million common units issued pursuant to the exercise of the underwriters’ option to purchase additional common units, at a price of $32.15 per common unit. The Partnership received offering proceeds (net of underwriting discounts, commissions and offering expenses) of approximately $569.3 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units. The Partnership used the net proceeds to pay a portion of the purchase price for the CMO Acquisition.

5

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Subscription Agreement

On December 20, 2012, the Partnership sold 5.9 million Class B units to each of the GIP II Entities and Williams and 5.6 million Class C units to each of the GIP II Entities and Williams, in each case pursuant to the subscription agreement. The Partnership received aggregate proceeds of approximately $712.1 million in exchange for the sale of Class B units and Class C units, inclusive of the capital contribution made by the general partner to maintain its two percent interest in the Partnership following the issuance of common, Class B and Class C units.

Holdings of Partnership Capital

At March 31, 2013, the GIP II Entities held 1,935,413 notional general partner units representing a 1.0 percent general partner interest in the Partnership, 50.0 percent of the Partnership’s incentive distribution rights, 33,704,666 common units, 34,538,061 subordinated units, 6,010,387 Class B units and 5,599,634 Class C units. The GIP II Entities’ ownership represents an aggregate 41.3 percent limited partner interest in the Partnership. Williams held 1,935,413 notional general partner units representing a 1.0 percent general partner interest in the Partnership, 50.0 percent of the Partnership’s incentive distribution rights, 34,538,061 subordinated units, 6,010,387 Class B units and 5,599,634 Class C units. Williams ownership represents an aggregate 23.8 percent limited partner interest in the Partnership. The public held 63,669,577 common units, representing a 32.9 percent limited partner interest in the Partnership.

Basis of Presentation

The accompanying financial statements and related notes present the unaudited condensed consolidated balance sheets of the Partnership as of March 31, 2013 and December 31, 2012. They also include the unaudited condensed consolidated statements of operations for the three-month periods ended March 31, 2013 and 2012, the unaudited condensed consolidated statements of cash flows for the Partnership for the three-month periods ended March 31, 2013 and 2012, and the unaudited changes in partners’ capital of the Partnership for the three-month period ended March 31, 2013.

The accompanying condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary to a fair statement of the results for the interim periods. Certain footnote disclosures normally included in the financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this quarterly report on Form 10-Q (this “Form 10-Q”). Management believes the disclosures made are adequate to make the information presented not misleading. This Form 10-Q should be read together with the Partnership’s annual report on Form 10-K for the year ended December 31, 2012.

The results of operations for the three-month period ended March 31, 2013, are not indicative of results that may be expected for the full fiscal year.

Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation.

2. Partnership Capital and Distributions

The partnership agreement requires that, within 45 days after the end of each quarter, the Partnership distribute its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the three-month period ended March 31, 2013, the Partnership paid cash distributions to its unitholders of approximately $84.1 million, representing a $0.45 per common unit distribution for the quarter ended December 31, 2012. See also Note 10 — Subsequent Events, concerning distributions declared on April 24, 2013, for the three-month period ended March 31, 2013.

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ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

General Partner Interest and Incentive Distribution Rights

The general partner of the Partnership is currently entitled to two percent of all quarterly distributions that the Partnership makes. Upon the issuance of any equity by the Partnership, the general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s initial two percent interest in the Partnership’s distributions may be reduced if the Partnership issues additional limited partner interests in the future (other than the issuance of common units upon conversion of outstanding subordinated, Class B or Class C units or the issuance of common units upon a reset of the incentive distribution rights (“IDRs”)) and its general partner does not contribute a proportionate amount of capital to the Partnership to maintain its two percent general partner interest.

The general partner holds IDRs that entitle it to receive increasing percentages, up to a maximum of 50 percent, of Partnership cash distributions if any of the Partnership’s quarterly distributions exceed a specified threshold. The maximum distribution sharing percentage of 50 percent includes distributions paid to the general partner on its two percent general partner interest and assumes that the general partner maintains its general partner interest at two percent. The maximum distribution of 50 percent does not include any distributions that the general partner may receive on the limited partner units that it may acquire.

Subordinated Units

As of March 31, 2013, all subordinated units are held indirectly by the GIP II Entities and Williams, collectively. These units are considered subordinated because for a period of time (the “Subordination Period”), the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution of $0.3375 per common unit plus any arrearages from prior quarters. Arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the Subordination Period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to or greater than the minimum quarterly distribution.

The Subordination Period will lapse at such time when the Partnership has earned and paid at least the minimum quarterly distribution on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit and the related distribution on the incentive distribution rights in a consecutive four-quarter period, the Subordination Period will terminate.

Class B Units

The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units will receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit will be the quotient of the quarterly distribution paid in respect of a common unit divided by the volume-weighted average price of the common units for the 30-day period prior to the declaration of the quarterly distribution to common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2014, each Class B unit will become convertible at the election of either the holder of such Class B unit or us into a common unit on a one-for-one basis. In the event of our liquidation, the holder of Class B units will be entitled to receive out of our assets available for distribution to the partners the positive balance in each such holder’s capital account in respect of such Class B units, determined after allocating our net income or net loss among the partners. All Class B units are held indirectly by affiliates of the Partnership’s general partner.

Class C Units

The Class C units are entitled to quarterly cash distributions after the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. The Class C units will participate pro

7

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

rata thereafter with all outstanding subordinated units until the subordinated units and Class C units receive the minimum quarterly distribution, after which the Class C units will participate in further cash distributions pro rata with our common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2013, each Class C unit will become convertible into a common unit on a one-for-one basis at the election of either the holder of such Class C unit or us. In the event of our liquidation, the holder of Class C units will be entitled to receive out of our assets available for distribution to the partners the positive balance in each such holder’s capital account in respect of such Class C units, determined after allocating our net income or net loss among the Partners. All Class C units are held indirectly by affiliates of the Partnership’s general partner.

3. Net Income per Limited Partner Unit

The Partnership’s net income attributable to the Partnership’s assets for periods including and subsequent to the Partnership’s acquisitions of such assets is allocated to the general partner and the limited partners, including any subordinated, Class B and Class C unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the IDRs is limited to available cash (as defined by the partnership agreement) for the period. The Partnership’s net income allocable to the limited partners is allocated between the common, subordinated, Class B and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, for any quarterly period, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since August 3, 2010 is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated, Class B and Class C unitholders for such quarterly period.

Basic and diluted net income per limited partner unit are calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding.

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ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):

	Three Months Ended March 31,
	2013			2012
Net income attributable to Access Midstream Partners, L.P.	$	59,538		$	52,366
Less general partner interest in net income		(4,792	)		(1,429	)
Limited partner interest in net income	$	54,746		$	50,937
Net income allocable to common units(1)	$	13,447		$	27,219
Net income allocable to subordinated units		19,837			23,718
Net income allocable to Class B units(1)		10,230			—
Net income allocable to Class C units(1)		11,232			—
Limited partner interest in net income	$	54,746		$	50,937
Net income per limited partner unit – basic and diluted
Common units	$	0.14		$	0.34
Subordinated units	$	0.29			0.34
Weighted average limited partner units outstanding – basic and diluted
Common units		98,421,405			79,276,432
Subordinated units		69,076,122			69,076,122
Total		167,497,527			148,352,554

⁽¹⁾  Adjusted to reflect amortization for the beneficial conversion feature.

4. Long-Term Debt

The following table presents the Partnership’s outstanding debt as of March 31, 2013 and December 31, 2012 (in thousands):

	March 31, 2013		December 31, 2012
Revolving credit facility	$	277,000	$	—
5.875 percent senior notes due April 2021		350,000		350,000
6.125 percent senior notes due July 2022		750,000		750,000
4.875 percent senior notes due May 2023		1,400,000		1,400,000
Total long-term debt	$	2,777,000	$	2,500,000

The following table presents the Partnership’s average interest rate and average debt balance for the three-months ended March 31, 2013:

	Average Interest Rate			Average Balance
				(in thousands)
Revolving credit facility		2.02	%	$	180,977
5.875 percent senior notes due April 2021		5.875			350,000
6.125 percent senior notes due July 2022		6.125			750,000
4.875 percent senior notes due May 2023		4.875			1,400,000

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ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Revolving Credit Facility

On December 12, 2012, the Partnership amended its senior secured revolving credit facility. The amended revolving credit facility matures in June 2016 and provides up to $1 billion of borrowing capacity, including a sub-limit of $50 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the revolving credit facility’s accordion feature allows the Partnership to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the revolving credit facility.

Borrowings under the revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. The revolving credit facility is secured by all of the Partnership’s assets, and loans thereunder (other than swing line loans) bear interest at the Partnership’s option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to the Partnership’s leverage ratio. If the Partnership reaches investment grade status, the Partnership will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.20 percent to 0.35 percent per annum while the Partnership is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.

Additionally, the revolving credit facility contains various covenants and restrictive provisions which limit the Partnership and its subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of the Partnership’s assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If the Partnership fails to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility also has cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit the Partnership’s ability, as well as the ability of certain of its subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require the Partnership to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for the Partnership to maintain the EBITDA to interest expense ratio and allows for the Partnership to release all collateral securing the revolving credit facility if the Partnership reaches investment grade status. The revolving credit facility agreement also requires the Partnership to maintain a consolidated leverage ratio of 5.5 to 1.0 (or 5.0 to 1.0 after we have released all collateral upon achieving investment grade status). The Partnership was in compliance with all covenants under the agreement at March 31, 2013.

Senior Notes

On December 19, 2012, the Partnership and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a public offering of $1.4 billion in aggregate principal amount of 4.875 percent senior notes due 2023 (the “2023 Notes”). The Partnership used a portion of the net proceeds to fund a portion of the purchase price for the CMO Acquisition, and the balance to repay borrowings outstanding under the Partnership’s revolving credit facility. Debt issuance costs of $25.8 million are being amortized over the life of the 2023 Notes.

10

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On January 11, 2012, the Partnership and ACMP Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). The Partnership used a portion of the net proceeds to repay all borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $13.8 million are being amortized over the life of the 2022 Notes.

On April 19, 2011, the Partnership and ACMP Finance Corp. completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 ( the “2021 Notes”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $8.2 million are being amortized over the life of the 2021 Notes.

The 2023 Notes will mature on May 15, 2023, and interest is payable on May 15 and November 15 of each year. The Partnership has the option to redeem all or a portion of the 2023 Notes at any time on or after December 15, 2017, at the redemption price specified in the indenture relating to the 2023 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2023 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to December 15, 2017. In addition, the Partnership may redeem up to 35 percent of the 2023 Notes prior to December 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. The Partnership has the option to redeem all or a portion of the 2022 Notes at any time on or after January 15, 2017, at the redemption price specified in the indenture relating to the 2022 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2022 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to January 15, 2017. In addition, the Partnership may redeem up to 35 percent of the 2022 Notes prior to January 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2021 Notes will mature on April 15, 2021 and interest is payable on the 2021 Notes on April 15 and October 15 of each year, beginning on October 15, 2011. The Partnership has the option to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture, plus accrued and unpaid interest. The Partnership may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, the Partnership may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2023 Notes, 2022 Notes and the 2021 Notes indentures contain covenants that, among other things, limit the Partnership’s ability and the ability of certain of the Partnership’s subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase the Partnership’s units, or redeem or purchase the Partnership’s subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to the Partnership; (7) consolidate, merge or transfer all or substantially all of the Partnership’s or certain of the Partnership’s subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2023 Notes, 2022 Notes or the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the indentures, has occurred or is continuing, many of these covenants will terminate.

The Partnership, as the parent company, has no independent assets or operations. The Partnership’s operations are conducted by its subsidiaries through its primary operating company subsidiaries, Access MLP Operating, L.L.C. and Access Midstream Operating, L.L.C. Each of Access MLP Operating, L.L.C., Access Midstream Operating, L.L.C. and the Partnership’s other subsidiaries is a guarantor, other than ACMP Finance Corp., an indirect 100 percent owned subsidiary of the Partnership whose sole purpose is to

11

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

act as co-issuer of any debt securities. Each guarantor is a 100 percent owned subsidiary of the Partnership. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture. There are no significant restrictions on the ability of the Partnership or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership or a guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Capitalized Interest

For the three-month periods ended March 31, 2013 and 2012, interest expense was net of capitalized interest of $9.7 million and $2.2 million, respectively.

5. Equity-Based Compensation

Certain employees of the Partnership’s general partner receive equity-based compensation through the Partnership’s equity-based compensation programs. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four years from the date of grant. Included in operating and general and administrative expenses is equity-based compensation of $7.4 million and $1.0 million for the three-month periods ended March 31, 2013 and 2012, respectively.

The LTIP provides for an aggregate of 3,500,000 common units to be awarded to employees, directors and consultants of the Partnership’s general partner and its affiliates through various award types, including unit awards, restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards. The LTIP has been designed to promote the interests of the Partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as employees, directors and consultants. As of March 31, 2013, there was $33.2 million of unrecognized compensation expense attributable to the LTIP, of which $31.1 million is expected to be recognized over a four year period following March 31, 2013.

The following table summarizes LTIP award activity for the three months ended March 31, 2013:

	Units			Value per Unit
Restricted units unvested at beginning of period		511,177		$	28.55
Granted		671,800			34.78
Vested		(49,790	)		28.95
Forfeited		(65,225	)		31.14
Restricted units unvested at end of period		1,067,962		$	32.29

6. Major Customers and Concentration of Credit Risk

Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, accounted for $202.5 million and $125.5 million of the Partnership’s revenues for the three-month periods ended March 31, 2013 and 2012, respectively.

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On March 31, 2013 and December 31, 2012, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings. On March 31, 2013 and December 31, 2012, Chesapeake accounted for $126.0 and $80.0 of the Partnership’s accounts receivable balance.

12

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7. Commitments and Contingencies

Certain property, equipment and operating facilities are leased under various operating leases. Costs are also incurred associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations.

The Partnership is from time to time subject to various legal actions and claims incidental to its business, including those arising out of employment-related matters. Management believes that these routine legal proceedings will not have a material adverse effect on the Partnership’s financial position, results of operations or cash flows. Once information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to the estimate of the likely exposure. There was not an accrual for legal contingencies as of March 31, 2013 or December 31, 2012.

8. Fair Value Measures

The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), and initial recognition of asset retirement obligations.

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

	March 31, 2013				December 31, 2012
	Carrying amount		Fair value (Level 2)		Carrying amount		Fair value (Level 2)
	($ in thousands)
Financial liabilities:
Revolving credit facility	$	277,000	$	277,000	$	—	$	—
2021 Notes		350,000		372,313		350,000		370,125
2022 Notes		750,000		805,785		750,000		810,000
2023 Notes		1,400,000		1,383,382		1,400,000		1,428,882

13

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The carrying amount of cash and cash equivalents (Level 1), accounts receivable and accounts payable reported on the balance sheet approximates fair value due to their short-term maturities.

9. Segment Information

Prior to the CMO Acquisition in December 2012, the Partnership’s operations were organized into a single business segment. The CMO Acquisition added assets in three new operating regions. Effective January 1, 2013, the Partnership’s chief operating decision maker began to analyze and make operating decisions based on geographic segments. The Partnership’s operations are divided into eight operating segments: Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica, Mid-Continent and Corporate. Summarized financial information for the reportable segments is shown in the following tables, presented in thousands.

Three months ended March 31, 2013

	Barnett			Eagle Ford			Haynesville			Marcellus			Niobrara
Revenues	$	93,084		$	57,959		$	33,474		$	3,729		$	2,302
Operating expenses		23,939			14,400			11,315			2,597			1,544
Depreciation and amortization expense		23,915			10,087			19,286			123			719
General and administrative expense		—			—			—			—			—
Other operating expense		—			—			—			—			—
Operating income (loss)	$	45,230		$	33,472		$	2,873		$	1,009		$	39
Income (loss) from unconsolidated affiliates	$	—		$	—		$	—		$	25,246		$	—
Capital expenditures	$	21,004		$	81,916		$	7,785		$	184	(1)	$	11,526	(2)
Total assets	$	1,571,188		$	984,486		$	1,323,957		$	1,216,897		$	99,775
	Utica			Mid-Continent			Corporate			Consolidated
Revenues	$	5,496		$	40,915		$	—		$	236,959
Operating expenses		2,546			18,204			8,218			82,763
Depreciation and amortization expense		1,200			8,598			2,722			66,650
General and administrative expense		—			—			23,734			23,734
Other operating expense		—			—			91			91
Operating income (loss)	$	1,750		$	14,113		$	(34,765	)	$	63,721
Income (loss) from unconsolidated affiliates	$	(161	)	$	(77	)	$	—		$	25,008
Capital expenditures	$	65,756	(3)	$	38,996	(4)	$	43,787		$	270,954
Total assets	$	483,305		$	755,108		$	416,698		$	6,851,414

⁽¹⁾  Amount excludes $93.2 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

⁽²⁾  Amount includes $5.8 million of capital expenditures attributable to noncontrolling interest owners.

⁽³⁾  Amount excludes $72.0 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $22.0 million of capital expenditures attributable to noncontrolling interest owners.

⁽⁴⁾  Amount excludes $0.3 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

14

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Three months ended March 31, 2012

	Barnett		Eagle Ford		Haynesville			Marcellus			Niobrara
Revenues	$	103,432	$	—	$	19,257		$	—			—
Operating expenses		26,200		—		4,147			—			—
Depreciation and amortization expense		22,571		—		7,786			—			—
General and administrative expense		—		—		—			—			—
Other operating expense		—		—		—			—			—
Operating income	$	54,661	$	—	$	7,324		$	—		$	—
Income from unconsolidated affiliates	$	—	$	—	$	—		$	12,987		$	—
Capital expenditures	$	38,678	$	—	$	6,577		$	—	(1)	$	—
Total Assets	$	1,597,302	$	—	$	530,800		$	943,109		$	—
	Utica		Mid-Continent		Corporate			Consolidated
Revenues	$	—	$	31,985	$	—		$	154,674
Operating expenses		—		12,363		5,972			48,682
Depreciation and amortization expense		—		7,497		584			38,438
General and administrative expense		—		—		11,478			11,478
Other operating expense		—		—		(45	)		(45	)
Operating income	$	—	$	12,125	$	(17,989	)	$	56,121
Income from unconsolidated affiliates	$	—	$	—	$	—		$	12,987
Capital expenditures	$	—	$	22,667	$	12,671		$	80,593
Total Assets	$	—	$	549,517	$	196,758		$	3,817,486

⁽¹⁾  Amount excludes $81.4 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

10. Subsequent Events

On April 2, 2013, the Partnership completed an equity offering of 10.35 million common units, including 1.35 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $39.86 per common unit. The Partnership received offering proceeds (net of underwriting discounts and commissions) of $400.1 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units and an approximate $8.4 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. The proceeds were used for general partnership purposes, including repayment of amounts outstanding under the Partnership’s revolving credit facility.

On April 24, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.4675 per unit, together with the corresponding distribution to the Class B unitholders and the general partner. The cash distributions will be paid on May 15, 2013, to unitholders of record at the close of business on May 8, 2013, and to the general partner.

15

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

Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Access Midstream Partners, L.P. (NYSE: ACMP) and its subsidiaries thereafter. The “GIP I Entities” refers to, collectively, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P., the “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, and “GIP” refers to the GIP I Entities and their affiliates and the GIP II Entities, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB). “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK). “Total,” when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

Overview

We are a growth-oriented publicly traded Delaware limited partnership formed in 2010 to own, operate, develop and acquire natural gas, natural gas liquids (“NGLs”) and oil gathering systems and other midstream energy assets. We are principally focused on natural gas and NGL gathering, the first segment of midstream energy infrastructure that connects natural gas and NGLs produced at the wellhead to third-party takeaway pipelines.

We provide our midstream services to Chesapeake, Total, Mitsui & Co. (“Mitsui”), Anadarko Petroleum Corporation (“Anadarko”), Statoil ASA (“Statoil”) and other leading producers under long-term, fixed-fee contracts. We operate assets in our Barnett Shale region in north-central Texas; our Eagle Ford Shale region in South Texas; our Haynesville Shale region in northwest Louisiana; our Marcellus Shale region primarily in Pennsylvania and West Virginia; our Niobrara Shale region in eastern Wyoming; our Utica Shale region in eastern Ohio; and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins.

Our CMO Acquisition and Williams’ Acquisition of 50 Percent of Our General Partner

On December 20, 2012, we acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of CMD’s affiliates, 100 percent of the issued and outstanding equity interests in Chesapeake Midstream Operating, L.L.C. (“CMO”) for total consideration of $2.16 billion (the “CMO Acquisition”). As a result of the CMO Acquisition, we now own certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended our assets and operations in the Haynesville, Marcellus and Mid-Continent regions. The acquired assets included, in the aggregate, approximately 1,675 miles of pipeline and 4.3 million (gross) dedicated acres as of the date of the acquisition. We also assumed various gas gathering and processing agreements associated with the assets that have terms ranging from 10 to 20 years and that, in certain cases, include cost of service or fee redetermination mechanisms.

Concurrently with the CMO Acquisition, the GIP I Entities sold to Williams 34,538,061 of our subordinated units and 50 percent of the outstanding equity interests in Access Midstream Ventures, L.L.C., the sole member of our general partner, for cash consideration of approximately $1.8 billion (the “Williams Acquisition”). As a result of the closing of the Williams Acquisition, the GIP II Entities and Williams together own and control our general partner and the GIP I Entities no longer have any ownership interest in us or our general partner.

Our Commercial Agreements with Producers

We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts, and increasingly through processing contracts, all of which limit our direct commodity price exposure.

16

Future revenues under our commercial agreements with producers will be derived pursuant to terms that will vary depending on the applicable operating region. The following outlines the key economic provisions of our commercial agreements by region.

Barnett Shale Region.Under our gas gathering agreements with Chesapeake and Total, we have agreed to provide the following services in our Barnett Shale region for the fees and obligations outlined below:

• Gathering, Treating and Compression Services. We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per thousand cubic feet (“Mcf”) for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems received our customers’ natural gas. We refer to these fees collectively as the Barnett Shale fee. Our Barnett Shale fee is subject to an annual rate escalation of two percent at the beginning of each year.

• Acreage Dedication. Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in our Barnett Shale region.

• Minimum Volume Commitments. Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments for each year through December 31, 2018 and for the six-month period ending June 30, 2019. Approximately 75 percent of the aggregate minimum volume commitment is attributed to Chesapeake, and approximately 25 percent is attributed to Total. The minimum volume commitments increase, on average, approximately 3 percent per year. If either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the six months ending June 30, 2019, and then against the minimum volume commitments of each preceding year. If the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.

• Fee Redetermination.In May 2012, we entered into an agreement with Chesapeake and Total relating to the initial redetermination period. The agreement called for an upward adjustment of the Barnett Shale fee and was effective July 1, 2012. We and each of Chesapeake and Total, as applicable, have the right to request an additional redetermination of the Barnett Shale fee during a two-year period beginning on September 30, 2014. The fee redetermination mechanism is intended to support a return on our invested capital. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. The cumulative upward or downward adjustment for the Barnett Shale region is capped at 27.5 percent of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. If we and Chesapeake or Total, as applicable, do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee.

17

• Well Connection Requirement. Subject to required notice by Chesapeake and Total and certain exceptions, we have generally agreed to connect new operated drilling pads and new operated wells within our Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period. During the minimum volume period, if we fail to complete a connection in the acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection.

• Fuel and Lost and Unaccounted For Gas. We have agreed with Chesapeake and Total on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s and Total’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

Eagle Ford Shale Region.Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services for the fees and obligations outlined below:

• Gathering, Compression, Dehydration and Treating Services. We will gather, compress, dehydrate and treat natural gas and liquids for the producers within the Eagle Ford Shale region in exchange for a cost of service based fee for natural gas and liquids gathered and treated on our gathering systems. The cost of service components will include revenue, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We refer to these fees collectively as the Eagle Ford fee.

• Acreage Dedication. Subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Eagle Ford Shale formation through existing and future wells with a surface location within the dedicated area in the Eagle Ford Shale region.

• Fee Redetermination. During 2013 and 2014, the Eagle Ford fee is determined by a fee tiering mechanism that calculates the Eagle Ford fee on a monthly basis according to the quantity of gas delivered to us by our producer customer relative to its scheduled deliveries. Effective on January 1, 2015 and January 1 of each year thereafter for a period of 20 years from July 1, 2012, the Eagle Ford fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these adjustments.

• Well Connection Requirement. Subject to required notice by our producer customer, we will have the option to connect new operated wells within our Eagle Ford Shale region acreage dedications as requested by the producer customer. If we elect not to connect a new operated well, the producer will be provided alternative forms of release. Subject to certain conditions specified in the applicable gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer customer’s acreage dedication in certain circumstances.

• Fuel and Lost and Unaccounted For Gas. We have agreed with the producer customer to a cap on fuel and lost and unaccounted for gas on our systems with respect to the producer customer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then-current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

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Haynesville Shale Region.Under our gas gathering agreements with Chesapeake, we have agreed to provide the following services for the fees and obligations outlined below:

Springridge Gathering System

• Gathering, Treating and Compression Services.We gather, treat and compress natural gas in exchange for fees per Mcf for natural gas gathered and per Mcf for natural gas compressed, which we refer to as the Springridge fees. The Springridge fees for these systems are subject to an annual specified rate escalation at the beginning of each year.

• Minimum Volume Commitments. Pursuant to our gas gathering agreement, our producer customer has agreed to minimum volume commitments through December 31, 2013. In the event our producer customer does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, it will be obligated to pay us a fee equal to the Springridge fee for each Mcf by which the minimum volume commitment for the year exceeds the actual volumes gathered on our systems attributable to its production. To the extent natural gas gathered on our systems from our producer customer during any annual period exceeds its minimum volume commitment for the period, it will be obligated to pay us the Springridge fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the year 2013, and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.

• Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases within the Springridge acreage dedication.

• Fee Redetermination. The Springridge fees are subject to a redetermination mechanism. The first redetermination period included December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. We will determine an adjustment to fees for the gathering systems in the region with our producer customer based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, referred to as the redetermination period, made as of November 30, 2010. The annual upward or downward fee adjustment for the Springridge region is capped at 15 percent of the then-current fees at the time of redetermination.

• Well Connection Requirement. We have certain connection obligations for new operated drilling pads and operated wells of our producer customer in the acreage dedications. Our producer customer is required to provide us notice of new drilling pads and wells operated by our producer customer in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new operated drilling pads in the acreage dedication by the later of 30 days after the date the wells commence production and six months after the date of the connection notice. During the minimum volume period, if we fail to complete a connection in the Springridge acreage dedication by the required date, our producer customer, as its sole remedy for such delayed connection, is entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After the minimum volume period, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Our producer customer also is required to notify us of its wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, our producer customer has certain rights to have the well released from the dedication under the gas gathering agreement.

• Fuel and Lost and Unaccounted For Gas.We have agreed with our producer customer on caps on fuel and lost and unaccounted for gas on our systems with respect to our producer customer’s volumes. These caps do not apply to one of our compressor stations due to its historical performance relative to the caps. This station will be reviewed periodically to determine whether

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changes have occurred that would make it suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Mansfield Gathering System

• Gathering, Treating, Compression and Dehydration Services. We gather, treat, compress and dehydrate natural gas in exchange for a fixed fee per MMBtu for natural gas gathered. We refer to this fee as the Mansfield fee. The Mansfield fee is subject to an annual 2.5 percent rate escalation at the beginning of each year.

• Acreage Dedication. Subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas owned or controlled by it and produced from the Bossier and Haynesville formations through existing and future wells with a surface location within the dedicated area in the Mansfield acreage dedication.

• Minimum Volume Commitments. Pursuant to our gas gathering agreement, our producer customer has agreed to minimum volume commitments for each year through December 31, 2017. If our producer customer does not meet its minimum volume commitments to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, it will be obligated to pay us the difference between the minimum volume commitment and the volume of gas delivered from its wells.

• Fixed Fee/Tiered Fees. During the minimum volume commitment period, the Mansfield fee is a fixed fee on all monthly volumes. Subsequent to that period, our producer customer will pay a tiered fee that calculates the Mansfield fee on a monthly basis according to the quantity of gas delivered to us from our producer customer’s wells relative to its scheduled deliveries.

• Well Connection Requirement. We have certain connection obligations for new operated wells of our producer customer in the acreage dedications. Our producer customer is required to provide us notice of new wells that it operates in the acreage dedications. Subject to certain conditions specified in the applicable gas gathering agreement, we are generally required to connect new wells within specified timelines subject to minimum volume commitment delays for volumes that would have been received from the new wells during the minimum volume commitment period and penalties up to a specified cap after the minimum volume commitment period.

• Fuel and Lost and Unaccounted For Gas. We have agreed with our producer customer on percentage-based caps on fuel and lost and unaccounted for gas on our systems with respect to our producer customer’s volumes. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Marcellus Shale Region.Under our gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief, we have agreed to provide the following services in our Marcellus Shale region for our proportionate share (based on our ownership interest in the applicable systems) of the fees and obligations outlined below:

• Gathering and Compression Services.In systems operated by Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”), we gather and compress natural gas in exchange for fees per million British thermal units (“MMBtu”) of natural gas gathered and per MMBtu of natural gas compressed. The gathering fees are redetermined annually based on a cost of service mechanism, as described below. The compression fees escalate on January 1 of each year based on the consumer price index. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA generated by these assets and specified quarterly targets totaling $100 million in 2012 and $150 million in 2013. EBITDA generated by these assets exceeded the $100 million target for 2012 and no additional revenue related to the commitment was recognized. The target for 2013 represents the minimum amount of EBITDA we will recognize with the potential that throughput for these systems will generate EBITDA in excess of the guaranteed amounts. In the systems acquired as part of the CMO Acquisition, we gather and compress natural gas in exchange for a gathering fee per MMBtu, which is redetermined annually based on a cost of service mechanism.

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• Acreage Dedication.Pursuant to our gas gathering agreements, subject to certain exceptions, the shippers and producers have agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells with a surface location within the designated dedicated areas.

• Fee Redetermination.Each January 1, gathering fees for each gathering system under the gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments. Each January 1, gathering fees for each gathering system under the gas gathering agreement with Chief are adjusted based on the applicable producer price index. The change in the amount of the gathering fees under the Chief agreement is not to exceed 3 percent in any one year.

• Well Connections.We have the option to connect to new wells within the dedicated acreage. If we elect not to connect to any new well within the dedicated acreage, the shipper for such well may elect to have such well, and any subsequent wells within a two-mile radius (in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui) or a one-mile radius (in the case of Chief) of the surface location of such well, permanently released from the dedication area, or the shipper may elect to construct, at the shipper’s expense, a gathering system to connect to such well (and wells within a one-mile radius of such well in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui), in which case the shipper would pay us a reduced gathering fee for natural gas we receive through the shipper-installed asset. Alternatively, the shipper may require us to enter into an agreement pursuant to which we would construct the gathering system to connect to the well in exchange for a reimbursement by the shipper of the costs we incur in connection therewith. The shipper may elect to connect wells outside the dedicated area at its sole expense and pay us a reduced gathering fee for natural gas we receive from such wells, but gas from such outside wells will not be afforded the same priority as gas produced from wells located within the dedicated area. In the systems acquired as part of the CMO Acquisition, subject to certain conditions specified in the applicable gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication in certain circumstances.

• Fuel and Lost and Unaccounted For Gas. Under our gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui, we have agreed on caps on fuel and lost and unaccounted for gas on the systems. If we exceed the permitted cap, we must provide a cost estimate for a remedy that is reasonably expected to prevent exceeding the permitted cap in the future. At the election of the shippers we may pay such costs (which costs would then be included in the gathering fee redetermination) or the shippers may pay the costs. If we exceed the permitted cap and do not provide a proposal to the shippers to prevent exceeding the cap in the future within the required time period, we may incur our proportionate share (based on our ownership interest in the applicable system) of significant expenses in connection with the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this may subject us to direct commodity price risk.

Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chief, the shipper on each system is to furnish to us, at the shipper’s sole cost and expense, all necessary fuel gas to operate the system. Gas volumes lost solely due to our actions or inactions constituting gross negligence or willful misconduct are our sole responsibility. Additionally, we will bear the cost of natural gas lost in excess of one percent due to our failure to maintain adequate corrosion protection. If we lose natural gas due to our gross negligence or willful misconduct or our failure to maintain an adequate corrosion protection system, we may incur significant expenses in connection with the cost of the lost natural gas. Our responsibility for the cost of the lost gas may subject us to direct commodity price risk.

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Niobrara Shale Region.Under our gas gathering and processing agreement with Chesapeake, we have agreed to provide the following services for the fees and obligations outlined below:

• Gathering, Compression, Dehydration and Processing Services. We will gather, compress, dehydrate and process natural gas and liquids within the Niobrara region in exchange for a cost of service based fee for natural gas and liquids gathered on our gathering systems and for natural gas and liquids processed at our proposed processing facility. The cost of service components will include revenues, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We refer to these fees collectively as the Niobrara fee.

• Acreage Dedication. Subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Frontier Sand and the Niobrara Shale through existing and future wells with a surface location within the dedicated areas in the Niobrara Shale region.

• Fee Redetermination. Effective on January 1, 2014 and January 1st of each year thereafter for a period of 20 years from July 1, 2012, the Niobrara fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.

• Well Connections. Subject to required notice by our producer customer, we will have the option to connect new operated wells within our Niobrara region acreage dedications as requested by such producer customer. If we elect not to connect a new operated well, the producer customer will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections up to a specified cap, and the potential for a well pad release from the producer customer’s acreage dedication in certain circumstances.

• Fuel and Lost and Unaccounted For Gas. We have agreed with our producer customer to a cap on fuel and lost and unaccounted for gas on our systems with respect to the producer customer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Utica Shale Region.Under our commercial agreements with Chesapeake, Total and Enervest, we have agreed to provide the following services for the fees and obligations outlined below:

• Gathering, Compression, Dehydration, Processing and Fractionation Services. We will gather, compress and dehydrate natural gas and liquids in exchange for a cost of service based fee for natural gas and liquids gathered on our gathering systems. The cost of service components (i) for our 66 percent operating interest in a joint venture that owns five wet gas gathering systems (the “Cardinal Joint Venture”), and (ii) in the area covered by our 100 percent ownership interest in four dry gas gathering systems (the “Utica Dry”) will include revenues, compression expense (in the case of the Utica Dry only), deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We also will process and fractionate natural gas and liquids through our 49 percent non-operating interest in a joint venture that is currently constructing four 200 MMcf/d processing trains, a 135,000 barrel per day fractionation facility, approximately 870,000 barrels of NGL storage capacity and other ancillary assets (the “UEO Joint Venture”) for a fixed fee that escalates annually within a specified range. The Partnership refers to these fees collectively as the Utica fee.

• Acreage Dedication. Subject to certain exceptions, our producer customers have agreed to dedicate all of the natural gas and liquids owned or controlled by them and produced from the Utica Shale formation through existing and future wells with a surface location within the dedicated areas in the Utica Shale region. The UEO Joint Venture has processing and fractionation dedications with designated dedication areas from Chesapeake, Total and Enervest for a total of 800 MMcf/d.

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• Fee Redetermination. Beginning on October 1, 2013, for the Cardinal Joint Venture and January 1, 2014, for Utica Dry and annually thereafter, for a period of 20.75 years from January 1, 2012 (Cardinal Joint Venture) and 15 years from July 1, 2012 (Utica Dry), the gathering fee portion of the Utica fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.

• Well Connections. In the Cardinal Joint Venture, we are generally required to connect new wells within specified timelines subject to penalties for delayed connections in the form of a temporary reduction in the gathering fee for the new well. In Utica Dry, subject to required notice by the producer customer, we will have the option to connect new operated wells within our dedicated acreage as requested by the producer customer. If we elect not to connect a new operated well, the producer customer will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication in certain circumstances.

• Processing and Fractionation Performance Standards. We have agreed with our producer customers to certain performance standards for the UEO Joint Venture, including guaranteed in-service dates, minimum facility run-time standards, minimum propane recovery standards, and fuel caps. If the UEO Joint Venture fails to achieve any of these performance standards as specified, the fees associated with these services will be temporarily reduced.

• Fuel and Lost and Unaccounted For Gas. We have agreed with the producer customers to a cap on fuel and lost and unaccounted for gas on our systems with respect to each producer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk. In Utica Dry, exceeding the permitted cap does not result in a reimbursement to the Utica producers if we respond in a timely manner with a proposed solution.

Mid-Continent Region.Under our gas gathering agreement with our producer customers, we have agreed to provide the following services for the fees and obligations outlined below:

• Gathering, Treating and Compression and Processing Services.We gather, treat, compress and process natural gas and NGLs in exchange for system-based services fees per Mcf for natural gas gathered and per Mcf for natural gas compressed. We refer to the fees collectively as the Mid-Continent fee. The Mid-Continent fees for these systems are subject to an annual two and a half percent rate escalation at the beginning of each year.

• Acreage Dedication.Pursuant to our gas gathering agreement, subject to certain exceptions, our producer customers have agreed to dedicate all of the natural gas and liquids owned or controlled by them and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication.

• Fee Redetermination. The Mid-Continent fees are redetermined at the beginning of each year through 2019. We and our producer customers will determine an adjustment to fees for the gathering systems in the region with our producer customers based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15 percent of the then current fees at the time of redetermination.

• Well Connection Requirement.Subject to required notice by our producer customers and certain exceptions, we have generally agreed to use our commercially reasonable efforts to connect new operated drilling pads and new operated wells in our Mid-Continent region acreage dedications as requested by our producer customers through June 30, 2019.

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• Fuel and Lost and Unaccounted For Gas.We have agreed with our producer customers on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to our producer customers volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

As part of the CMO Acquisition, we acquired a 33% equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC. Under a gas processing agreement with Chesapeake and Anadarko, Ranch Westex JV LLC provides gas processing services under a cost of service fee arrangement.

All Regions. If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes of to a third party properties within the our acreage dedications, it does so subject to the terms of the gas gathering agreement, including our dedication, and it will be required to cause the third party to acknowledge and take assignment of the counterparty’s obligations under the existing gas gathering agreement with the Partnership, subject to our consent. Our producer customers’ dedication of the gas produced from applicable properties under our gas gathering agreements will run with the land in order to bind successors to the producer customers’ interest, as well as any interests in the dedicated properties subsequently acquired by the producer customer.

Other Arrangements

Services Arrangements.Under our services agreement with Chesapeake, Chesapeake has agreed to provide us with certain general and administrative services and any additional services we may request. We reimburse Chesapeake for such general and administrative services in any given month subject to a cap equal to $0.0310 per Mcf multiplied by the volume (measured in Mcf) of natural gas and liquids that we gather, treat or compress. The fee is calculated as the lesser of $0.0310 per Mcf gathered or actual corporate overhead costs, excluding those overhead costs that are billed directly to the Partnership. The $0.0310 per Mcf cap is subject to an annual upward adjustment on October 1 of each year equal to 50 percent of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. The cap contained in the services agreement does not apply to our direct general and administrative expenses.

Additionally, pursuant to an employee secondment agreement, specified employees of Chesapeake were seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner, subject to specified exceptions and limitations, reimbursed Chesapeake on a monthly basis for substantially all costs and expenses it incurred relating to such seconded employees.

On June 15, 2012, in connection with the closing of the first portion of the acquisition by the GIP II Entities of Chesapeake’s ownership interest in the Partnership (the “GIP Acquisition”), we entered into a letter agreement with Chesapeake regarding the terms on which Chesapeake will provide certain transition services to the Partnership and our general partner following the GIP Acquisition. Among other things, the letter agreement provides for the continuation of our services agreement and secondment agreement with Chesapeake until December 31, 2013. On June 29, 2012, we entered into an amendment to the letter agreement amending certain terms relating to the insurance coverage to be provided under our services agreement and altering the workers’ compensation insurance endorsements for our general partner under our secondment agreement. On December 20, 2012 in connection with the CMO Acquisition, we entered into another amendment to the letter agreement amending certain terms relating primarily to the extension of transition services for technology related services through March 2014 and through June 2014 for certain field communication support services. The secondment agreement and employee secondment agreement each terminated on January 1, 2013.

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How We Evaluate Our Operations

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput volumes, (ii) revenues, (iii) operating expenses, (iv) Adjusted EBITDA, (v) distributable cash flow and (vi) segment operating income.

Throughput Volumes

Our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems in our operating regions in order to maintain or increase throughput volumes on our gathering systems as a whole. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to attract natural gas and liquids volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

Revenues

Our revenues are driven primarily by our contractual terms with our customers, the actual volumes of natural gas we gather, treat and compress, and increasingly by the actual volumes of natural gas we process. Our revenues are supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total in the case of our Barnett Shale and Chesapeake in the case of our Haynesville Shale as well as fee redetermination and cost of service provisions in our other regions. We contract with producers to gather natural gas or liquids from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas and liquids that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For both the three month period ended March 31, 2013 and the three month period ended March 31 2012, Chesapeake accounted for approximately 77 percent of the natural gas volumes on our gathering systems as an increase in Chesapeake throughput in our Eagle Ford region was offset by an increase in throughput by other customers in the Marcellus region. For the three months ended March 31, 2013 and 2012, Chesapeake accounting for approximately 85 percent and 81 percent, respectively, of our revenues.

Our revenues are also impacted by other aspects of our contractual agreements, including rate redetermination, cost of service and other contractual provisions and our management constantly evaluates capital spending and its impact on future revenue generation.

Operating Expenses

Our management seeks to maximize the profitability of our operations by minimizing operating expenses without compromising environmental protection and employee safety. Operating expenses are comprised primarily of field operating costs (which include labor, treating and chemicals, and measurements services among other items), compression expense, ad valorem taxes and other operating costs, some of which are independent of the volumes that flow through our systems but fluctuate depending on the scale of our operations during a specific period.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before income tax expense, interest expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results.

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Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to capital structure, historical cost basis, or financing methods;

• our ability to incur and service debt and fund capital expenditures;

• the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe it is appropriate to exclude certain items from EBITDA because we believe these items affect the comparability of operating results. We believe that the presentation of Adjusted EBITDA in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income.

Distributable Cash Flow

Our Partnership agreement defines Distributable Cash Flow (“DCF”) as Adjusted EBITDA attributable to the Partnership adjusted for:

• Addition of interest income;

• Subtraction of net cash paid for interest expense;

• Subtraction of maintenance capital expenditures; and

• Subtraction of income taxes.

DCF is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is in part measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. The GAAP measure most directly comparable to DCF is net cash provided by operating activities.

Segment Operating Income

Prior to the CMO Acquisition in December 2012, our operations were organized into a single business segment. The CMO Acquisition added assets in three new operating regions. Effective January 1, 2013, our chief operating decision maker began to analyze and make operating decisions based on geographic segments. Our operations are divided into eight operating segments: Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica, Mid-Continent and Corporate.

Reconciliation to GAAP measures

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow are presented because they are helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all

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items that affect net income and net cash provided by operating activities. You should not consider either Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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The following table presents a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and distributable cash flow to the GAAP financial measures of net income and net cash provided by operating activities:

	Three Months Ended March 31,
	2013				2012
	($ in thousands)
Reconciliation of adjusted EBITDA and distributable cash flow to net income:
Net income attributable to Access Midstream Partners, L.P.		$	59,538		$	52,366
Interest expense			27,062			15,958
Income tax expense			1,240			839
Depreciation and amortization expense			66,650			38,438
Other			(640	)		(45	)
Income from unconsolidated affiliates			(25,008	)		(12,987	)
EBITDA from unconsolidated affiliates(1)			39,459			23,860
Expense for non-cash equity awards			7,390			—
Implied minimum volume commitment			8,750			—
Adjusted EBITDA		$	184,441		$	118,429
Maintenance capital expenditures			(27,500	)		(18,500	)
Cash portion of interest expense			(25,092	)		(14,655	)
Income tax expense			(1,240	)		(839	)
Distributable Cash Flow		$	130,609		$	84,435

	Three Months Ended March 31,
	2013				2012
	($ in thousands)
Reconciliation of adjusted EBITDA and distributable cash flow to net cash provided by operating activities:
Cash Provided By Operating Activities		$	80,130		$	67,215
Changes in assets and liabilities			26,343			12,534
Interest expense			27,062			15,958
Income tax expense			1,240			839
Other non-cash items			(5,933	)		(1,977	)
EBITDA from unconsolidated affiliates(1)			39,459			23,860
Expense for non-cash equity awards			7,390			—
Implied minimum volume commitment			8,750			—
Adjusted EBITDA		$	184,441		$	118,429
Maintenance capital expenditures			(27,500	)		(18,500	)
Cash portion of interest expense			(25,092	)		(14,655	)
Income tax expense			(1,240	)		(839	)
Distributable Cash Flow		$	130,609		$	84,435

	Three Months Ended March 31,
(1) EBITDA from unconsolidated affiliates is calculated as follows:	2013				2012
		($ in thousands)
Net Income		$	25,008		$	12,987
Depreciation and amortization expense			14,466			10,901
Other			(15	)		(28	)
EBITDA from unconsolidated affiliates		$	39,459		$	23,860

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	Three Months Ended March 31,
	2013				2012
GAAP Capital Expenditures		$	270,954		$	80,593
Adjusted for:
Capital expenditures included in unconsolidated affiliates			165,506			81,354
Capital expenditures attributable to non-controlling interest			(27,752	)		—
Net Capital Expenditures		$	408,708		$	161,947

Results of Operations – Three Months Ended March 31, 2013 versus March 31, 2012

The following table sets forth certain information regarding revenues, operating expenses, other income and expenses, key performance metrics and operational data for the Partnership for the three months ended March 31, 2013 (the “Current Quarter”) and the three months ended March 31, 2012 (the “Prior Quarter”):

	Three Months Ended March 31,
	2013				2012			%
	($ in thousands, except operational data)
Revenues(1)		$	236,959		$	154,674			53.2	%
Operating expenses			82,763			48,682			70.0
Depreciation and amortization expense			66,650			38,438			73.4
General and administrative expense			23,734			11,478			106.8
Other operating (income) expense			91			(45	)		(302.2	)
Total operating expenses			173,238			98,553			75.8
Operating income			63,721			56,121			13.5
Income from unconsolidated affiliates			25,008			12,987			92.6
Interest expense			(27,062	)		(15,958	)		69.6
Other income			269			55			389.1
Income before income tax expense			61,936			53,205			16.4
Income tax expense			1,240			839			47.8
Net income		$	60,696		$	52,366			15.9
Key Performance Metrics:
Adjusted EBITDA(2)		$	184,441		$	118,429			55.7
Distributable cash flow(2)		$	130,609		$	84,435			54.7
Operational Data(3):
Wells connected during period			220			197			11.7
Wells connected at end of period			7,904			5,443			45.2
Throughput, Bcf per day			3.550			2.802			26.7
Miles of pipe at end of period			6,101			3,953			54.3
Gas compression (horsepower) at end of period			455,318			324,951			40.1

(1) If either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment in the Haynesville Shale region under the relevant gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each thousand cubic feet (“Mcf”) by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. Should payments be due under the minimum volume commitment with respect to any year, we recognize the associated revenues in the fourth quarter of that year.

(2) Adjusted EBITDA and distributable cash flow are defined and reconciled to their most directly comparable financial measures calculated and presented in accordance with GAAP below under the captionHow We Evaluate Our Operations within this Part I, Item 2.

(3) Operational data includes the gross results for equity investments except for throughput which represents the net throughput allocated to the Partnership’s interest.

The following tables reflect the Partnership’s revenues, throughput, operating expenses and operating expenses per Mcf of throughput by region for the three months ended March 31, 2013 and 2012 (please note that revenue, throughput and operating expenses related to our equity investments (primarily in the Marcellus Shale) are excluded from the tables below as the financial results for our equity investments are reported separately. Please read “Income from Unconsolidated Affiliates” in this Results of Operations section of Management’s Discussion and Analysis of Financial Condition and Results of Operations):

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	Three Months Ended March 31,
	2013		2012		% Change
	(In thousands, except percentages and throughput data)
Revenues(1):
Barnett Shale	$	93,084	$	103,432		(10.0	)%
Eagle Ford Shale		57,959		—		N.M.
Haynesville Shale		33,474		19,257		73.8
Marcellus Shale		3,729		—		N.M.
Niobrara Shale		2,302		—		N.M.
Utica Shale		5,496		—		N.M.
Mid-Continent		40,915		31,985		27.9
	$	236,959	$	154,674		53.2	%
Throughput (bcf)(1):
Barnett Shale		95.9		116.4		(17.6	)%
Eagle Ford Shale		20.5		—		N.M.
Haynesville Shale		69.3		37.7		83.8
Marcellus Shale		77.6		—		N.M.
Niobrara Shale		0.9		—		N.M.
Utica Shale		4.9		—		N.M.
Mid-Continent		50.3		48.7		3.3
		319.4		202.8		57.5	%
Operating Expenses(1):
Barnett Shale	$	23,939	$	26,200		(8.6	)%
Eagle Ford Shale		14,400		—		N.M.
Haynesville Shale		11,315		4,147		172.8
Marcellus Shale		2,597		—		N.M.
Niobrara Shale		1,544		—		N.M.
Utica Shale		2,546		—		N.M.
Mid-Continent		18,204		12,363		47.2
Corporate		8,218		5,972		37.6
	$	82,763	$	48,682		70.0	%
Expenses ($ per mcf):
Barnett Shale	$	0.25	$	0.23		8.7	%
Eagle Ford Shale		0.70		—		N.M.
Haynesville Shale		0.16		0.11		45.5
Marcellus Shale		1.31		—		N.M.
Niobrara Shale		0.91		—		N.M.
Utica Shale		0.36		—		N.M.
Mid-Continent		0.36		0.25		44.0
Corporate		—		—		—
	$	0.33	$	0.24		41.7	%

(1) Throughput in all regions represents the net throughput allocated to the Partnership’s interest. Revenues and expenses presented above reflect only consolidated results of operations.

Segment Reporting

We present information in this MD&A by segment. The segment information appearing in Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting. Beginning on January 1, 2013, we conduct our operations in the following segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent region and Corporate.

Barnett Shale

Revenues. For the Current Quarter, Barnett Shale revenues totaled $93.1 million compared to $103.4 million in the Prior Quarter, a decrease of $10.3 million, or 10.0 percent. A decrease in throughput due to decreased drilling activity resulted in an $18.2 million decrease in revenue which was partially offset by an annual fixed fee rate escalation of two percent and fee redetermination in July 2012 of $0.05 per mcf. Because throughput in the Barnett Shale during the Current Quarter was significantly below contractual minimum volume commitment levels, we expect to recognize additional revenue related to volume shortfall in the 2013 fourth quarter. The minimum volume commitment is measured annually and

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the associated revenue is recognized in the fourth quarter of each year. If our estimate of minimum volume commitment was recognized quarterly, revenue would have increased $8.8 million in the Current Quarter based on the projected full year volume shortfall.

Operating Expenses. For the Current Quarter, operating expenses were $23.9 million, or $0.25 per Mcf, compared to $26.2 million, or $0.23 per Mcf, during the Prior Quarter. The decrease in total operating expense is the result of a decrease in compensation and other costs as we anticipated a decrease in throughput in this region and adjusted the cost structure to fit the expected level of activity. While total operating costs have decreased, operating expense per Mcf has increased due to fixed costs and declining volumes.

Eagle Ford Shale

We acquired the Eagle Ford Shale assets in December 2012.

Revenues. Our Current Quarter revenues in the Eagle Ford totaled $58.0 million and were primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. We connected 119 new wells to our gathering systems in this region during the Current Quarter and we expect throughput from these wells to contribute to our results in future periods.

Operating Expenses. For the Current Quarter, operating expenses totaled $14.4 million or $0.70 per Mcf. The most significant operating expenses in this region are compensation and compression costs.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $10.1 million and relates almost entirely to depreciation of our operating assets in this region.

Haynesville Shale

Revenues. For the Current Quarter, Haynesville Shale revenues totaled $33.5 million compared to $19.3 million in the Prior Quarter, an increase of $14.2 million, or 73.8 percent. An overall increase in throughput of 83.8 percent resulted from production from the Mansfield gathering system acquired in December 2012, offset by a volume decrease for the Springridge gathering system. Haynesville revenues in the Current Quarter were positively impacted by an annual rate escalation of 2.5 percent and rate redetermination of 15 percent on the Springridge gathering system, both effective January 1, 2013.

Operating Expenses. For the Current Quarter, operating expenses were $11.3 million, or $0.16 per Mcf compared to $4.1 million, or $0.11 per Mcf during the Prior Quarter. All of our operating costs in this region increased significantly as a result of the acquisition of the Mansfield system in December 2012. While natural gas gathered in the area serviced by the Mansfield gathering system requires additional treating services, we continue to reduce our operating costs in this dry gas region to address the decrease in throughput caused by the low natural gas price environment.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $19.3 million compared to $7.8 million during the Prior Quarter. The increase is almost entirely the result of the December 2012 acquisition of the Mansfield gathering system as we did not spend a significant amount of capital in this region in 2012 due to reduced drilling activity by our producer customer.

Marcellus Shale

Marcellus Shale revenues and expenses reflect only the results of the Marcellus gathering systems acquired in December 2012. The large majority of our assets in the Marcellus Shale are accounted for as equity investments and included in Income from Unconsolidated Affiliates. See further discussion below under “Income from Unconsolidated Affiliates” in this section of Marcellus Shale results of operations.

Revenues. Revenues from the Marcellus assets acquired in December 2012 totaled $3.7 million during the Current Quarter, primarily related to throughput on those gathering systems and the rates charged for gathering such throughput.

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Operating Expenses. Operating expenses for the assets acquired in December 2012 was $2.6 million in the Current Quarter and related primarily to compensation and compression costs.

Income from Unconsolidated Affiliates.In December 2011, we acquired all of the issued and outstanding common units of Appalachia Midstream. We operate 100 percent of and own an interest in 10 gas gathering systems in the Marcellus Shale, primarily in Pennsylvania and West Virginia. The remaining interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates for the Appalachia Midstream assets was $25.2 million and $13.0 million for the Current Quarter and Prior Quarter, respectively. The increase was the result of increased drilling by our producer customers in the Marcellus Shale as well as an increase in the number of wells we connected to our system in 2012. We connected 227 new wells to our Appalachia Midstream gathering systems in 2012. The following table summarizes the results of the Appalachia Midstream assets (net to our interest) for the Current Quarter and Prior Quarter:

	Three Months Ended March  31, 2013		Three Months Ended March  31, 2012
Revenues ($ in thousands)	$	46,022	$	29,259
Throughput (Bcf)		76.4		52.2
Operating expenses ($ in thousands)	$	6,706	$	3,734
Expenses ($ per Mcf)		0.09		0.07

Niobrara Shale

We acquired 50 percent of the Niobrara Shale assets in December 2012. Because we operate the assets and have contractual discretion to make operating decisions for the assets, we are deemed to control the assets and thus, we consolidate 100 percent of the assets and results of operation in our financial results. We present the noncontrolling interest for these assets in Noncontrolling Interests on the condensed consolidated balance sheet and in Net Income Attributable to Noncontrolling Interests on the condensed consolidated statement of operations.

Revenues. Our Current Quarter revenues in the Niobrara totaled $2.3 million and were primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. We continue to invest significant capital in this region and expect to connect a significant number of wells to our gathering systems that will drive volume growth in future periods.

Operating Expenses. For the Current Quarter, operating expenses totaled $1.5 million. The most significant operating expenses in this region are compensation and compression costs.

Utica Shale

In the CMO Acquisition, we acquired a 100 percent ownership interest in four natural gas gathering systems, a 66 percent operating interest in the Cardinal Joint Venture and a 49 percent interest in the UEO Joint Venture. Because we operate the assets and have contractual discretion to make operating decision for the Cardinal Joint Venture, we are deemed to control the assets and thus, we consolidated 100 percent of the assets and results of operations in our financial results and reflect the ownership of the other interest owners through a noncontrolling interest in the income and equity of the investment. The UEO Joint Venture is accounted for as an equity investment because the power to direct the activities which are most significant to the UEO Joint Venture’s economic performance is shared between us and the other equity holders.

Revenues. Our Current Quarter revenues in the Utica totaled $5.5 million and were primarily attributable to the amount of throughput and rates charged for such throughput on our gathering systems and gathering systems included in the Cardinal Joint Venture. We continue to invest significant capital in this region that will drive volume and revenue growth in future periods.

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Operating Expenses. For the Current Quarter, operating expenses totaled $2.5 million. The most significant operating expenses in this region are compensation and compression costs.

Mid-Continent

Revenues. For the Current Quarter, Mid-Continent revenues totaled $40.9 million compared to $32.0 million in the Prior Quarter, an increase of $8.9 million, or 27.9 percent. Throughput in the Mid-Continent region increased 3.3 percent, contributing $1.1 million of additional revenues and a 2.5 percent annual rate increase and a 15 percent increase in fees as a result of rate redetermination, both effective January 1, 2013, contributed additional revenue in this region.

Operating Expenses. For the Current Quarter, operating expenses were $18.2 million, or $0.36 per Mcf compared to $12.4 million, or $0.25 per Mcf during the Prior Quarter. The increase occurred across all operating costs in this region as we continue to experience and prepare for increased drilling activity in this liquids-rich region by our producer customers.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $8.6 million compared to $7.5 million during the Prior Quarter. We spent significant capital in the liquids-rich Mid-Continent region in 2012 and expect to continue to spend additional capital in this region in 2013 in order to provide various services to producers in this region.

Corporate

Operating Expenses. For the Current Quarter, operating expenses were $8.2 million compared to $6.0 million during the Prior Quarter. The increase in operating expenses resulted from additional technical resources to support assets acquired in 2012 as well as an increase in risk management expense.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $2.7 million compared to $0.6 million during the Prior Quarter. The increase in depreciation expense is a result of capital expenditures to back office infrastructure made in 2012.

General and Administrative Expense. During the Current Quarter, general and administrative expenses were $23.7 million compared to $11.5 million during the Prior Quarter. This increase is primarily attributable to additional overhead expenses resulting from the increased scale of the Partnership’s operations following the CMO Acquisition, additional expense from equity-based, long-term incentive compensation influenced by the recent increase in the Partnership’s unit price, as well as transition costs as the Partnership develops an independent back office infrastructure.

Interest Expense. Interest expense was $27.1 million for the Current Quarter compared to $16.0 million for the Prior Quarter. These amounts were net of $9.7 million and $2.2 million of capitalized interest during the Current Quarter and the Prior Quarter, respectively. The increase is related to interest expense on the 2023 Notes, issued in December 2012. We also incur interest expense on our outstanding senior notes and borrowings under our revolving credit facility. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

Income Tax Expense.Income tax expense is attributable to franchise taxes in the state of Texas. The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the unaudited condensed consolidated financial statements, other than Texas Franchise Tax.

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Liquidity and Capital Resources

Our ability to finance operations and fund capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses as well as the availability of borrowings under our revolving credit facility and our access to the capital markets. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. SeeRisk Factorsin our annual report on Form 10-K for the year ended December 31, 2012.

Working Capital (Deficit). Working capital is defined as the amount by which current assets exceed current liabilities and may indicate the potential need for short-term funding. As of March 31, 2013, we had a working capital deficit of $94.6 million and as of December 31, 2012, we had a working capital deficit of $39.5 million.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the three months ended March 31, 2013 and 2012, were as follows:

	Three Months Ended March 31,
	2013			2012
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	80,130		$	67,215
Investing activities	$	(356,628	)	$	(125,448	)
Financing activities	$	211,816		$	58,236

Operating Activities. Net cash provided by operating activities was $80.1 million for the Current Quarter compared to $67.2 million during the Prior Quarter. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, amortization and gains or losses on the sales of fixed assets. Please read “Results of Operations” above in this Management’s Discussion and Analysis of Financial Condition and Results of Operations. The changes in cash flow are also impacted by timing impacts on working capital accounts.

Investing Activities. Net cash used in investing activities for the Current Quarter increased $231.2 million compared to the Prior Quarter. Approximately $356.6 million was used in investing activities during 2013. This amount included approximately $271.0 million in additions to property, plant and equipment and $111.8 million in additions to our investment in unconsolidated affiliates.

Financing Activities. Net cash provided by (used in) financing activities increased $153.6 million for the Current Quarter as compared to the Prior Quarter. This increase was primarily attributable to an increase in net borrowings.

Sources of Liquidity

At March 31, 2013, our potential sources of liquidity included:

• cash on hand;

• cash generated from operations;

• borrowing availability under our revolving credit facility; and

• capital raised through debt and equity markets.

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

Cash flow from operations is a significant source of liquidity we use to fund capital expenditures, pay distributions and service debt. We have historically and expect in the future to use capacity on our credit facility and the capital markets to fund growth capital and acquire natural gas, natural gas liquids and oil gathering systems and other midstream energy assets, allowing us to execute our growth strategy.

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Revolving Credit Facility

On December 12, 2012, we amended our senior secured revolving credit facility. The amended revolving credit facility matures in June 2016 and provides up to $1 billion of borrowing capacity, including a sub-limit of $50 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the revolving credit facility’s accordion feature allows us to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the revolving credit facility. As of March 31, 2013, we had approximately $277.0 million outstanding under our revolving credit facility. As of December 31, 2012, there were no borrowings outstanding.

Borrowings under the revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. The revolving credit facility is secured by all of our assets, and loans thereunder (other than swing line loans) bear interest at our option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to our leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to our leverage ratio. If we reach investment grade status, we will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while we are subject to the leverage-based pricing grid, according to our leverage ratio and (b) 0.20 percent to 0.35 percent per annum while we are subject to the ratings-based pricing grid, according to our senior unsecured long-term debt ratings.

Additionally, our revolving credit facility contains various covenants and restrictive provisions which limit our and our subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If we fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. Our revolving credit facility also has cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit our ability, as well as the ability of certain of our subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require us to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for us to maintain the EBITDA to interest expense ratio and allows for us to release all collateral securing the revolving credit facility if we reach investment grade status. The revolving credit facility agreement also requires us to maintain a consolidated leverage ratio of 5.5 to 1.0 (or 5.0 to 1.0 after we have released all collateral upon achieving investment grade status). We were in compliance with all covenants under the agreement at March 31, 2013 and December 31, 2012.

Senior Notes

On December 19, 2012, we and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a public offering of $1.4 billion in aggregate principal amount of 4.875 percent senior notes due 2023 (the “2023 Notes”). We used a portion of the net proceeds to fund a portion of the purchase price for the CMO Acquisition, and the balance to repay borrowings outstanding under our revolving credit facility. Debt issuance costs of $25.8 million are being amortized over the life of the 2023 Notes.

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On January 11, 2012, we and ACMP Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). We used a portion of the net proceeds to repay all borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $13.8 million are being amortized over the life of the 2022 Notes.

On April 19, 2011, we and ACMP Finance Corp. completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 ( the “2021 Notes”). We used a portion of the net proceeds to repay borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $8.2 million are being amortized over the life of the 2021 Notes.

The 2023 Notes will mature on May 15, 2023, and interest is payable on May 15 and November 15 of each year. We have the option to redeem all or a portion of the 2023 Notes at any time on or after December 15, 2017, at the redemption price specified in the indenture relating to the 2023 Notes, plus accrued and unpaid interest. We may also redeem the 2023 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to December 15, 2017. In addition, we may redeem up to 35 percent of the 2023 Notes prior to December 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. We have the option to redeem all or a portion of the 2022 Notes at any time on or after January 15, 2017, at the redemption price specified in the indenture relating to the 2022 Notes, plus accrued and unpaid interest. We may also redeem the 2022 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to January 15, 2017. In addition, we may redeem up to 35 percent of the 2022 Notes prior to January 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2021 Notes will mature on April 15, 2021 and interest is payable on the 2021 Notes on April 15 and October 15 of each year, beginning on October 15, 2011. We have the option to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture, plus accrued and unpaid interest. We may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, we may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2023 Notes, 2022 Notes and the 2021 Notes indentures contain covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets including equity interests in our subsidiaries; (2) pay distributions on, redeem or purchase our units, or redeem or purchase our subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to us; (7) consolidate, merge or transfer all or substantially all of our, or certain of our subsidiaries’, assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2023 Notes, 2022 Notes or the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the indentures, has occurred or is continuing, many of these covenants will terminate.

We, as the parent company, have no independent assets or operations. Our operations are conducted by our subsidiaries through our primary operating company subsidiaries, Access MLP Operating, L.L.C. and Access Midstream Operating, L.L.C. Each of Access MLP Operating, L.L.C., Access Midstream Operating, L.L.C. and our other subsidiaries is a guarantor, other than ACMP Finance Corp., our indirect 100 percent owned subsidiary whose sole purpose is to act as co-issuer of any debt securities. Each guarantor is our 100 percent owned subsidiary. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant

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defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture. There are no significant restrictions on our ability or the ability of any guarantor to obtain funds from our or its respective subsidiaries by dividend or loan. None of our assets or the assets of any guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Equity Issuance

On December 18, 2012, we completed an equity offering of 18.4 million common units, including 2.4 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $32.15 per common unit.

We received offering proceeds (net of underwriting discounts, commissions and offering expenses) of approximately $569.3 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units. We used the net proceeds to pay a portion of the purchase price for the CMO Acquisition.

Subscription Agreement

On December 20, 2012, we sold 5.9 million Class B units to each of the GIP II Entities and Williams and 5.6 million Class C units to each of the GIP II Entities and Williams, in each case pursuant to the subscription agreement. We received aggregate proceeds of approximately $712.1 million in exchange for the sale of Class B units and Class C units, inclusive of the capital contribution made by our general partner to maintain its two percent general partner interest in us following the issuance of common, Class B and Class C units.

Capital Requirements

Our business is capital-intensive, requiring significant investment to grow our business as well as to maintain and improve existing assets. We categorize capital expenditures as either:

• maintenance capital expenditures, which include those expenditures required to maintain our long-term operating capacity and/or operating income and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or

• growth capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating and compression throughput from current levels and reduce costs or increase revenues.

For the Current Quarter, growth capital expenditures totaled $381.2 million and maintenance capital expenditures totaled $27.5 million. Total 2013 first quarter capital expenditures included $165.5 million for the Partnership’s share of capital expenditures in entities accounted for as equity investments. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute most of the cash generated from operations to our unitholders and our general partner, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and general partner, borrowings under our revolving credit facility and future issuances of equity and debt securities.

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Distributions

	Declaration Date		Record Date		Distribution Date		Distribution Declared		Total Cash Distribution
2013									($ in thousands)
First quarter		April 24, 2013		May 8, 2013		May 15, 2013	$	0.4675	$	93,358
2012
Fourth quarter		January 25, 2013		February 6, 2013		February 13, 2013	$	0.4500	$	84,073
Third quarter		October 25, 2012		November 7, 2012		November 14, 2012		0.4350		67,081
Second quarter		July 27, 2012		August 7, 2012		August 14, 2012		0.4200		64,164
First quarter		April 27, 2012		May 8, 2012		May 15, 2012		0.4050		61,543

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. We make significant estimates which impact depreciation and assumptions regarding future net cash flows. Although we believe these estimates are reasonable, actual results could differ from our estimates.

We consider depreciation and evaluation of long-lived assets for impairment to be critical policies and estimates. These policies and estimates are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2012.

Forward-Looking Statements

Certain statements and information in this quarterly report on Form 10-Q may constitute forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

• our dependence on Chesapeake, Total, Mitsui, Anadarko Petroleum Corporation and Statoil for a majority of our revenues;

• the impact on our growth strategy and ability to increase cash distributions if producers do not increase the volume of natural gas they provide to our gathering systems;

• oil and natural gas realized prices;

• the termination of our gas gathering agreements;

• the availability, terms and effects of acquisitions;

• our potential inability to maintain existing distribution amounts or pay the minimum quarterly distribution to our unitholders;

• the limitations that our level of indebtedness may have on our financial flexibility;

• our ability to obtain new sources of natural gas, which is dependent on factors largely beyond our control;

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• the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;

• competitive conditions;

• the unavailability of third-party pipelines interconnected to our gathering systems or the potential that the volumes we gather do not meet the quality requirement of such pipelines;

• new asset construction may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks;

• our exposure to direct commodity price risk may increase in the future;

• our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

• hazards and operational risks that may not be fully covered by insurance;

• our dependence on Chesapeake for substantially all of our compression capacity;

• our lack of industry diversification; and

• legislative or regulatory changes, including changes in environmental regulations, environmental risks, regulations by the Federal Energy Regulatory Commission and liability under federal and state environmental laws and regulations.

Other factors that could cause our actual results to differ from our projected results are described under the caption “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2012, and in our other reports and registration statements filed from time to time with the SEC.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

ITEM 3.Quantitative and Qualitative Disclosures About Market Risk

We are dependent on Chesapeake, Total and other producers for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake, Total or other producers of gathering, treating and compression fees. Chesapeake’s debt ratings for its senior notes are below investment grade, and they may remain below investment grade for the foreseeable future. Additionally, we are also subject to the risk that one or more of these customers default on its obligations under its gas gathering agreements with us. Not all of our counterparties under our gas gathering agreements are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.

Interest Rate Risk

Interest rates have recently experienced near record lows. If interest rates rise, our financing costs would increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Commodity Price Risk

We attempt to mitigate commodity price risk by contracting our operations on a long-term fixed-fee basis and through various provisions in our gas gathering agreements that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in natural gas prices or disparity in oil and natural gas pricing could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding any minimum volume commitments, fee redetermination provisions and cost of service provisions in our

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commercial agreements with producers, a reduction in volumes of natural gas gathered by our systems could adversely affect both our profitability and our cash flows. Adverse effects on our cash flows from reductions in natural gas prices could adversely affect our ability to make cash distributions to our unitholders.

We have agreed with our producer customers on caps on fuel and lost and unaccounted for gas on certain of our gathering systems in our operating regions. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

Additionally, an increase in commodity prices could result in increased costs of steel and other products that we use in the operation of our business, as well as the cost of obtaining rights-of-way for property on which our assets are located. Accordingly, our operating expenses and capital expenditures could increase as a result of an increase in commodity prices.

ITEM 4.Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at a reasonable level of assurance as of March 31, 2013.

There has been no change in the Partnership’s internal control over financial reporting during the quarter ended March 31, 2013, that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.Legal Proceedings

We are not party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial position.

ITEM 1A.Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, the reader should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012. There have been no material changes in our risk factors from those disclosed in Part I, Item 1A, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

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

In connection with a public offering of the Partnership’s common units, on April 2, 2013, our general partner made an additional capital contribution to the Partnership of approximately $8.4 million to maintain its two percent interest in the Partnership. These issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

ITEM 3.Defaults Upon Senior Securities

Not applicable.

ITEM 4.Mine Safety Disclosures

Not applicable.

ITEM 5.Other Information

Not applicable.

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ITEM 6.Exhibits

The following exhibits are filed as a part of this report:

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith		Furnished Herewith
31.1	J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.						X
31.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.						X
32.1	J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.								X
32.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.								X
101.INS	XBRL Instance Document.								X
101.SCH	XBRL Taxonomy Extension Schema Document.								X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.								X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.								X
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document.								X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.								X

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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.

	ACCESS MIDSTREAM PARTNERS, L.P.
	By: Access Midstream Partners GP, L.L.C., its general partner
Date: May 3, 2013	By:	/s/    J. MIKE STICE
		J. Mike Stice
		Chief Executive Officer

Date: May 3, 2013	By:	/s/    DAVID C. SHIELS
		David C. Shiels
		Chief Financial Officer

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INDEX TO EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith		Furnished Herewith
31.1	J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.						X
31.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.						X
32.1	J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.								X
32.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.								X
101.INS	XBRL Instance Document.								X
101.SCH	XBRL Taxonomy Extension Schema Document.								X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.								X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.								X
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document.								X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.								X

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