10-Q 1 acmp-10q_20140630.htm 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2014

¨	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)

(877) 413-1023

(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 July 23, 2014, the registrant had 190,794,543 common units outstanding.

ACCESS MIDSTREAM PARTNERS, L.P.

INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2014

	PART I.

Financial Information
		Page
Item 1.	Financial Statements (Unaudited):

	Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1

	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	2

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	3

	Condensed Consolidated Statement of Changes in Partners’ Capital for the Six Months Ended June 30, 2014	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58

Item 4.	Controls and Procedures	58

	PART II.

Other Information

Item 1.	Legal Proceedings	59

Item 1A.	Risk Factors	59

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61

Item 3.	Defaults Upon Senior Securities	61

Item 4.	Mine Safety Disclosures	61

Item 5.	Other Information	61

Item 6.	Exhibits	62

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2014			2013
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	36,675		$	17,229
Accounts receivable		181,939			222,409
Prepaid expenses		12,382			10,182
Other current assets		12,312			8,111
Total current assets		243,308			257,931

Property, plant and equipment
Gathering systems		6,406,548			5,974,940
Other fixed assets		361,933			175,411
Less: Accumulated depreciation		(999,219	)		(859,551	)
Total property, plant and equipment, net		5,769,262			5,290,800
Investments in unconsolidated affiliates		2,103,530			1,936,603
Intangible customer relationships, net		360,502			372,391
Deferred loan costs, net		64,061			59,721
Total assets	$	8,540,663		$	7,917,446
LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:
Accounts payable	$	63,649		$	37,520
Accrued liabilities		272,555			268,952
Total current liabilities		336,204			306,472

Long-term liabilities
Long-term debt		3,805,397			3,249,230
Other liabilities		9,269			8,954
Total long-term liabilities		3,814,666			3,258,184

Commitments and contingencies (Note 7)
Partners' capital:
Common units (190,051,818 and 177,801,147 issued and outstanding at at June 30, 2014 and December 31, 2013, respectively)		3,572,779			3,343,145
Class B units (12,680,044 and 12,424,358 issued and outstanding at June 30, 2014 and December 31, 2013, respectively)		337,312			318,472
Class C units (zero and 11,199,268 issued and outstanding at June 30, 2014 and December 31, 2013, respectively)		-			322,896
General partner interest		120,912			114,393
Total partners' capital attributable to Access Midstream Partners, L.P.		4,031,003			4,098,906
Noncontrolling interest		358,790			253,884
Total partners' capital		4,389,793			4,352,790
Total liabilities and partners' capital	$	8,540,663		$	7,917,446

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

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	($ in thousands, except per unit data)

Revenues	$	292,934		$	247,242		$	570,012		$	484,201

Operating expenses
Operating expenses		97,523			82,844			190,436			165,607
Depreciation and amortization expense		89,976			71,869			175,520			138,519
General and administrative expense		37,257			25,089			71,437			48,823
Other operating (income) expense		(317	)		1,892			1,488			1,983

Total operating expenses		224,439			181,694			438,881			354,932

Operating income		68,495			65,548			131,131			129,269

Other income (expense)
Income from unconsolidated affiliates		48,063			33,745			90,941			58,753
Interest expense		(42,903	)		(27,732	)		(81,476	)		(54,794	)
Other income		198			126			590			395

Income before income tax expense		73,853			71,687			141,186			133,623
Income tax expense		1,385			1,260			3,189			2,500

Net income		72,468			70,427			137,997			131,123
Net income attributable to noncontrolling interests		5,014			1,214			9,465			2,372

Net income attributable to Access Midstream Partners, L.P.	$	67,454		$	69,213		$	128,532		$	128,751

Limited partner interest in net income
Net income attributable to Access Midstream Partners, L.P.	$	67,454		$	69,213		$	128,532		$	128,751
Less general partner interest in net income		(23,526	)		(5,995	)		(43,142	)		(10,787	)
Limited partner interest in net income	$	43,928		$	63,218		$	85,390		$	117,964

Net income per limited partner unit - basic and diluted
Common units	$	0.18		$	0.18		$	0.33		$	0.32
Subordinated units	$	-		$	0.31		$	-		$	0.60

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

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2014			2013
	($ in thousands)
Cash flows from operating activities
Net income	$	137,997		$	131,123
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		175,520			138,519
Income from unconsolidated affiliates		(90,941	)		(58,753	)
Other non-cash items		12,602			6,676
Distribution of earnings received from unconsolidated affiliates		155,358			-
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		46,309			(23,592	)
(Increase) decrease in other assets		(5,312	)		1,905
Increase (decrease) in accounts payable		25,733			(10,896	)
Increase in accrued liabilities		5,495			32,598
Net cash provided by operating activities		462,761			217,580

Cash flows from investing activities
Additions to property, plant and equipment		(521,170	)		(545,594	)
Purchase of compression assets		(159,210	)		-
Investments in unconsolidated affiliates		(220,378	)		(263,710	)
Proceeds from sale of assets		14,296			31,696
Net cash used in investing activities		(886,462	)		(777,608	)

Cash flows from financing activities
Proceeds from long-term borrowings		1,053,471			875,500
Payments on long-term debt borrowings		(1,246,971	)		(659,300	)
Proceeds from issuance of common units		52,155			399,922
Proceeds from issuance of senior notes		750,000			-
Distributions to unitholders		(252,145	)		(177,430	)
Capital contributions from noncontrolling interests		95,441			71,414
Payments on capital lease obligations		(1,983	)		-
Debt issuance costs		(8,777	)		(5,377	)
Other		1,956			8,328
Net cash provided by financing activities		443,147			513,057

Net increase (decrease) in cash and cash equivalents		19,446			(46,971	)
Cash and cash equivalents, beginning of period		17,229			64,994

Cash and cash equivalents, end of period	$	36,675		$	18,023

Supplemental disclosure of non-cash investing activities
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	33,566		$	(25,244	)
Changes in other liabilities related to asset retirement obligations	$	1,016		$	105

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

ACCESS MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)

	Partners' Equity
	Limited Partners												Non-
										General			controlling
	Common			Class B			Class C			Partner			interest		Total
($ in thousands)
Balance at December 31, 2013	$	3,343,145		$	318,472		$	322,896		$	114,393		$	253,884	$	4,352,790
Net income		78,941			5,274			1,175			43,142			9,465		137,997
Distribution to unitholders		(207,772	)		-			(6,215	)		(38,158	)		-		(252,145	)
Conversion of Class C units to common units		321,151			-			(321,151	)		-			-		-
Contributions from noncontrolling interest owners		-			-			-			-			95,441		95,441
Non-cash equity based compensation		2,020			-			-			-			-		2,020
Issuance of general partner interests		-			-			-			1,535			-		1,535
Issuance of common units		52,155			-			-			-			-		52,155
Beneficial conversion feature of Class B units		822			(822	)		-			-			-		-
Amortization of beneficial conversion feature of Class B and Class C units		(17,683	)		14,388			3,295			-			-		-
Balance at June 30, 2014	$	3,572,779		$	337,312		$	-		$	120,912		$	358,790	$	4,389,793

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

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, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”), Total Gas and Power North America, Inc. and Total E&P USA, Inc., a wholly owned subsidiary of Total, S.A. (“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 II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).

Williams Acquisition

At June 30, 2014, the GIP II Entities held 2,068,692 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, 48,742,361 common units and 6,340,022 Class B units. At June 30, 2014, The GIP II Entities’ ownership represented an aggregate 26.6 percent limited partner interest in the Partnership. At June 30, 2014, Williams held 2,068,692 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, 40,137,695 common units and 6,340,022 Class B units. At June 30, 2014, Williams ownership represented an aggregate 22.5 percent limited partner interest in the Partnership. The public held 101,171,762 common units, representing a 48.9 percent limited partner interest in the Partnership.

MidCon Acquisition

On March 31, 2014, the Partnership acquired certain midstream compression assets from MidCon Compression, L.L.C. (“MidCon”), a wholly owned subsidiary of Chesapeake, for approximately $160 million. The acquisition added natural gas compression assets, historically leased from MidCon, in the rapidly growing Utica Shale and Marcellus Shale regions. The acquired assets include more than 100 compression units with a combined capacity of approximately 200,000 horsepower.

Equity Issuances

On August 2, 2013, the Partnership entered into an Equity Distribution Agreement (“ATM”) under which it may offer and sell common units, in amounts, at prices and on terms to be determined by market conditions and other factors, having an aggregate market value of up to $300 million. The Partnership is under no obligation to issue equity under the ATM. For the three-month period ended June 30, 2014, the Partnership sold an aggregate of 772,819 common units under the ATM for net proceeds of approximately $44.6 million, net of approximately $0.4 million in commissions, plus an approximate $0.9 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. For the six-month period ended June 30, 2014, the Partnership sold an aggregate of 909,219 common units under the ATM for net proceeds of approximately $52.2 million, net of approximately $0.5 million in commissions, plus an approximate $1.0 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. The Partnership used the proceeds for general partnership purposes.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 $399.8 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units, plus 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.

Basis of Presentation

The accompanying financial statements and related notes present the unaudited condensed consolidated balance sheets of the Partnership as of June 30, 2014 and December 31, 2013. They also include the unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2014 and 2013, the unaudited condensed consolidated statements of cash flows for the Partnership for the six-month periods ended June 30, 2014 and 2013, and the unaudited changes in partners’ capital of the Partnership for the six-month period ended June 30, 2014.

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, 2013, as amended.

The results of operations for the six-month period ended June 30, 2014, are not indicative of results that may be expected for the full fiscal year.

Income Taxes

As a master limited partnership, the Partnership is a pass-through entity and is not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generated flow through to the owners, and accordingly, do not result in a provision for income taxes.

2. Partnership Capital and Distributions

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distributes all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the three and six-month periods ended June 30, 2014, the Partnership paid cash distributions to its unitholders of approximately $130.0 million and $252.1 million, respectively, representing a $0.555 per common unit distribution for the three-month period ended December 31, 2013 and a $0.575 per common unit distribution for the three-month period ended March 31, 2014. Please read Note 12 (Subsequent Events) to the condensed consolidated financial statements, concerning distributions declared on July 24, 2014, for the three-month period ended June 30, 2014.

General Partner Interest and Incentive Distribution Rights

The Partnership’s general partner is entitled to two percent of all quarterly distributions that the Partnership makes prior to its liquidation. 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 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 Class B 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.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 interests that it may acquire.

Conversion of Subordinated Units

Upon payment of the cash distribution for the second quarter of 2013, the subordination period with respect to the Partnership’s 69,076,122 subordinated units expired and all outstanding subordinated units converted into common units on a one-for-one basis on August 15, 2013. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Conversion of Class C Units

Under the partnership agreement, the Class C units became convertible into common units on a one-for-one basis at the election of either the Partnership or the holders of the Class C units on February 10, 2014 (the first business day following the record date for the Partnership’s 2013 fourth quarter cash distribution). After February 10, 2014, the Partnership received notice from certain of the GIP II Entities and Williams, as holders of the Class C units, of their election to convert all of the Class C units. All of the outstanding Class C units were converted into common units on a one-for-one basis effective February 19, 2014. The common units resulting from this conversion participate pro rata with the other common units in quarterly distributions. The conversion did not impact the amount of cash distributions paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Class B Units

The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit is the quotient of the quarterly distribution paid to the Partnership’s common units 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 Partnership or the holders of such Class B unit into a common unit on a one-for-one basis. In the event of the Partnership’s liquidation, the holders of Class B units will be entitled to receive out of the Partnership’s 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 the Partnership’s net income or net loss among the partners. All Class B units are held indirectly by affiliates of the Partnership’s general partner. The Class B units were issued at a discount to the market price of the common units into which they are convertible. This discount totaled $58.3 million and represents a beneficial conversion feature, which was reflected as an increase in common unitholders’ capital and a decrease in Class B unitholders’ capital to reflect the fair value of the Class B units at issuance. The beneficial conversion feature is considered a non-cash distribution recognized ratably from the issuance date of December 20, 2012, through the conversion date, resulting in an increase in Class B unitholders’ capital and a decrease in common unitholders’ capital.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 the Partnership’s 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 Partnership’s Long-Term Incentive Plan (“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 that quarterly period.

Basic and diluted net income per limited partner unit is 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.

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	($ in thousands, except per unit data)
Net income attributable to Access Midstream Partners, L.P.	$	67,454		$	69,213		$	128,532		$	128,751
Less general partner interest in net income		(23,526	)		(5,995	)		(43,142	)		(10,787	)

Limited partner interest in net income	$	43,928		$	63,218		$	85,390		$	117,964

Net income allocable to common units⁽¹⁾	$	33,915		$	19,116		$	61,257		$	32,563
Net income allocable to subordinated units		—			21,721			—			41,558
Net income allocable to Class B units⁽¹⁾		10,013			10,755			19,663			20,985
Net income allocable to Class C units⁽¹⁾		—			11,626			4,470			22,858
Limited partner interest in net income	$	43,928		$	63,218		$	85,390		$	117,964
Net income per limited partner unit – basic and diluted
Common units	$	0.18		$	0.18		$	0.33		$	0.32
Subordinated units	$	—		$	0.31		$	—		$	0.60
Weighted average limited partner units outstanding - basic and diluted
Common units		190,953,800			108,673,392			187,609,231			103,575,719
Subordinated units		—			69,076,122			—			69,076,122
Total		190,953,800			177,749,514			187,609,231			172,651,841

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

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Long-Term Debt

The following table presents the Partnership’s outstanding debt as of June 30, 2014 and December 31, 2013 (in thousands):

	June 30, 2014		December 31, 2013
Revolving credit facility	$	150,000	$	343,500
5.875 percent senior notes due April 2021		750,000		750,000
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
4.875 percent senior notes due March 2024		750,000		—
Premium on 5.875 percent senior notes due April 2021		5,397		5,730

Total long-term debt	$	3,805,397	$	3,249,230

The following table presents the Partnership’s average interest rate and average debt balance for the three-months ended June 30, 2014:

	Average Interest Rate			Average Balance
				(in thousands)
Revolving credit facility		2.159	%	$	91,901
5.875 percent senior notes due April 2021		5.875			750,000
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
4.875 percent senior notes due March 2024		4.875			750,000
Premium on 5.875 percent senior notes due April 2021		5.875			5,564

Revolving Credit Facility

On May 13, 2013, the Partnership amended and restated its existing senior secured revolving credit facility. The amended and restated revolving credit facility matures in May 2018 and includes revolving commitments of $1.75 billion, including a sublimit of $100.0 million for same-day swing line advances and a sub-limit of $200.0 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 $2.0 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 0.50 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 1.50 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 0.375 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.15 percent to 0.30 percent per annum while the Partnership is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 or 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 $50 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 the Partnership has released all collateral upon achieving investment grade status). The Partnership was in compliance with all covenants under the agreement at June 30, 2014.

Senior Notes

On March 7, 2014, the Partnership and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a public offering of $750 million in aggregate principal amount of 4.875 percent senior notes due 2024 (the “2024 Notes”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under the Partnership’s revolving credit facility, including amounts incurred to fund the purchase price of and certain expenses relating to the Partnership’s purchase of compression assets from MidCon and the balance for general partnership purposes. Debt issuance costs of $8.8 million are being amortized over the life of the 2024 Notes.

On August 14, 2013, the Partnership and ACMP Finance Corp. issued $400 million in aggregate principal amount of additional 5.875 percent senior notes due 2021 (the “Additional Notes”). The Additional Notes are additional to the $350 million of 2021 Notes initially issued on April 19, 2011 and are fully fungible with, rank equally with and form a single series with the 2021 Notes. The Additional Notes were issued at a price of 101.5 percent of the principal amount plus accrued interest from April 15, 2013, resulting in net proceeds of $400.8 million, which was used for general partnership purposes, including funding working capital, repayment of indebtedness and funding the Partnership’s capital expenditure program. Debt issuance costs of $5.8 million are being amortized over the life of the Additional Notes.

On December 19, 2012, the Partnership and ACMP Finance Corp. 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 Partnership’s December 2012 acquisition of certain assets from Chesapeake (the “CMO Acquisition”), and the balance to repay borrowings outstanding under the Partnership’s revolving credit facility. Debt issuance costs of $25.9 million are being amortized over the life of the 2023 Notes.

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.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The 2024 Notes will mature on March 15, 2024, and interest is payable on March 15 and September 15 of each year. The Partnership has the option to redeem all or a portion of the 2024 Notes at any time on or after March 15, 2019, at the redemption price specified in the indenture relating to the 2024 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2024 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 March 15, 2019. In addition, the Partnership may redeem up to 35 percent of the 2024 Notes prior to March 15, 2017 under certain circumstances with the net cash proceeds from certain equity offerings.

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 indentures governing the 2024 Notes, the 2023 Notes, the 2022 Notes and the 2021 Notes 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 2024 Notes, 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 subsidiary, Access MLP Operating, L.L.C, a direct 100 percent owned subsidiary of the Partnership. Access MLP Operating, L.L.C. and each of the Partnership’s other subsidiaries is a guarantor, other than Cardinal Gas Services, L.L.C., Jackalope Gas Gathering Services, L.L.C. and ACMP Finance Corp., an indirect 100 percent owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities. Each guarantor is a direct or indirect 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.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Capitalized Interest

For the three-month periods ended June 30, 2014 and 2013, interest expense was net of capitalized interest of $9.8 million and $10.2 million, respectively, and $19.9 million for each of the six-month periods ended June 30, 2014 and 2013.

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.

Certain key members of management have been designated as participants in the Management Incentive Compensation Plan which is made up of two components. The first component is an annual cash bonus based on “excess” cash distributions made by the Partnership above a specified target amount with respect to each fiscal quarter during which the award is outstanding. The second component is based on an increase in value of the Partnership’s common units at the end of a specified five-year period beginning on the award commencement date. As a result of the Williams Acquisition, both components of the Management Incentive Compensation Plan vested on July 1, 2014, resulting in total compensation expense of $41.1 million. Please read Note 12 (Subsequent Events) to the condensed consolidated financial statements.

Included in operating expense, general and administrative expense, and income from unconsolidated affiliates is total equity-based compensation of $14.0 million and $8.9 million for the three-month periods ended June 30, 2014 and 2013, respectively. Included in operating expense, general and administrative expense, and income from unconsolidated affiliates is equity-based compensation of $23.8 million and $16.3 million for the six-month periods ended June 30, 2014 and 2013, respectively.

The LTIP provides for an aggregate of 3.5 million 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 June 30, 2014, there was $38.5 million of unrecognized compensation expense attributable to the LTIP, of which $38.5 million will be recognized in the third quarter of 2014, as a result of the Williams Acquisition. Please read Note 12 (Subsequent Events) to the condensed consolidated financial statements for information regarding the acquisition.

The following table summarizes LTIP award activity for the six months ended June 30, 2014:

	Units			Value per Unit
Restricted units unvested at beginning of period		1,182,288		$	36.11
Granted		277,061		$	53.78
Vested		(139,403	)	$	33.48
Forfeited		(149,584	)	$	36.59
Restricted units unvested at end of period		1,170,362		$	40.55

6. Major Customers and Concentration of Credit Risk

Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, accounted for $240.6 million and $210.6 million of the Partnership’s revenues for the three-month periods ended June 30, 2014 and 2013, respectively, and $470.1 million and $413.1 million for the six-month periods ended June 30, 2014 and 2013, respectively.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On June 30, 2014 and December 31, 2013, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings. On June 30, 2014 and December 31, 2013, Chesapeake accounted for $144.1 million and $176.5 million of the Partnership’s accounts receivable balance.

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.

From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceedings for which a final disposition could have a material effect on the Partnership’s results of operations, cash flows or financial position. 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 Partnership’s likely exposure. There were no accruals for legal contingencies as of June 30, 2014 or December 31, 2013.

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.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	June 30, 2014				December 31, 2013
	Carrying amount		Fair value (Level 2)		Carrying amount		Fair value (Level 2)
	($ in thousands)
Financial liabilities:

Revolving credit facility	$	150,000	$	150,000	$	343,500	$	343,500
Premium on 2021 Notes		5,397		5,397		5,730		5,730
2021 Notes		750,000		805,313		750,000		801,098
2022 Notes		750,000		827,813		750,000		804,848
2023 Notes		1,400,000		1,477,882		1,400,000		1,355,382
2024 Notes		750,000		794,063		—		—

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

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

9. Segment Information

The Partnership’s operations are divided into eight operating segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent region and Corporate.

Summarized financial information for the reportable segments is shown in the following tables, presented in thousands.

Three months ended June 30, 2014

	Barnett		Eagle Ford		Haynesville			Marcellus				Niobrara
Revenues	$	83,788	$	84,016	$	29,076		$	3,930			$	5,577
Operating expenses		22,538		15,509		10,986			2,197				2,997
Depreciation and amortization expense		25,080		15,727		20,624			2,330				1,486
General and administrative expense		-		-		-			-				-
Other operating expense		-		-		-			-				-
Operating income (loss)	$	36,170	$	52,780	$	(2,534	)	$	(597	)		$	1,094

Income (loss) from unconsolidated affiliates	$	-	$	-	$	-		$	40,671			$	-

Capital expenditures	$	2,777	$	46,090	$	2,596		$	9,347		⁽¹⁾	$	57,860	⁽²⁾
Total assets	$	1,463,190	$	1,249,178	$	1,241,495		$	1,584,405			$	236,668

				Mid-
	Utica			Continent		Corporate			Consolidated
Revenues	$	33,899		$	52,648	$	-		$	292,934
Operating expenses		11,805			19,442		12,049			97,523
Depreciation and amortization expense		5,369			10,816		8,544			89,976
General and administrative expense		-			-		37,257			37,257
Other operating expense		-			-		(317	)		(317	)
Operating income (loss)	$	16,725		$	22,390	$	(57,533	)	$	68,495

Income (loss) from unconsolidated affiliates	$	4,584		$	2,808	$	-		$	48,063

Capital expenditures	$	85,541	⁽³⁾	$	22,434	$	24,894		$	251,539
Total assets	$	1,408,825		$	805,808	$	551,094		$	8,540,663

⁽¹⁾	Amount excludes $37.7 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

⁽²⁾	Amount includes $28.9 million of capital expenditures attributable to noncontrolling interest owners.

⁽³⁾	Amount excludes $75.7 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $28.4 million of capital expenditures attributable to noncontrolling interest owners.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Three months ended June 30, 2013

	Barnett		Eagle Ford		Haynesville		Marcellus			Niobrara
Revenues	$	90,384	$	67,752	$	30,621	$	4,012		$	2,431
Operating expenses		23,963		14,951		9,109		198			1,946
Depreciation and amortization expense		24,000		13,362		19,471		38			1,156
General and administrative expense		-		-		-		-			-
Other operating expense		-		-		-		-			-
Operating income (loss)	$	42,421	$	39,439	$	2,041	$	3,776		$	(671	)

Income (loss) from unconsolidated affiliates	$	-	$	-	$	-	$	34,492		$	-

Capital expenditures	$	13,395	$	83,443	$	2,777	$	5	⁽¹⁾	$	11,671		⁽²⁾
Total assets	$	1,558,776	$	1,062,109	$	1,308,901	$	1,322,496		$	103,844

					Mid-
	Utica				Continent			Corporate			Consolidated
Revenues	$	7,238			$	44,804		$	-		$	247,242
Operating expenses		2,269				16,975			13,433			82,844
Depreciation and amortization expense		2,265				8,208			3,369			71,869
General and administrative expense		-				-			25,089			25,089
Other operating expense		-				-			1,892			1,892
Operating income (loss)	$	2,704			$	19,621		$	(43,783	)	$	65,548

Income (loss) from unconsolidated affiliates	$	(929	)		$	182		$	-		$	33,745

Capital expenditures	$	94,023		⁽³⁾	$	29,134	⁽⁴⁾	$	40,192		$	274,640
Total assets	$	669,413			$	758,322		$	432,709		$	7,216,570

⁽¹⁾	Amount excludes $75.9 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 $112.0 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $33.8 million of capital expenditures attributable to noncontrolling interest owners.

⁽⁴⁾	Amount excludes $2.3 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Six months ended June 30, 2014

	Barnett		Eagle Ford		Haynesville			Marcellus				Niobrara
Revenues	$	171,606	$	162,106	$	56,533		$	5,301			$	12,089
Operating expenses		47,758		31,347		21,076			3,113				5,295
Depreciation and amortization expense		50,382		30,763		40,931			3,237				2,873
General and administrative expense		-		-		-			-				-
Other operating expense		-		-		-			-				-
Operating income (loss)	$	73,466	$	99,996	$	(5,474	)	$	(1,049	)		$	3,921

Income (loss) from unconsolidated affiliates	$	-	$	-	$	-		$	81,203			$	-

Capital expenditures	$	8,792	$	123,573	$	6,246		$	15,802		⁽¹⁾	$	88,518	⁽²⁾
Total assets	$	1,463,190	$	1,249,178	$	1,241,495		$	1,584,405			$	236,668

				Mid-
	Utica			Continent		Corporate			Consolidated
Revenues	$	58,473		$	103,904	$	-		$	570,012
Operating expenses		20,223			37,351		24,273			190,436
Depreciation and amortization expense		9,403			21,417		16,514			175,520
General and administrative expense		-			-		71,437			71,437
Other operating expense		-			-		1,488			1,488
Operating income (loss)	$	28,847		$	45,136	$	(113,712	)	$	131,131

Income (loss) from unconsolidated affiliates	$	5,110		$	4,628	$	-		$	90,941

Capital expenditures	$	181,179	⁽³⁾	$	39,456	$	57,604		$	521,170
Total assets	$	1,408,825		$	805,808	$	551,094		$	8,540,663

⁽¹⁾	Amount excludes $70.9 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

⁽²⁾	Amount includes $44.9 million of capital expenditures attributable to noncontrolling interest owners.

⁽³⁾	Amount excludes $151.9 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $59.3 million of capital expenditures attributable to noncontrolling interest owners.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Six months ended June 30, 2013

	Barnett		Eagle Ford		Haynesville		Marcellus			Niobrara
Revenues	$	183,468	$	125,711	$	64,095	$	7,741		$	4,733
Operating expenses		47,902		29,351		20,424		2,795			3,490
Depreciation and amortization expense		47,915		23,449		38,757		161			1,875
General and administrative expense		-		-		-		-			-
Other operating expense		-		-		-		-			-
Operating income (loss)	$	87,651	$	72,911	$	4,914	$	4,785		$	(632	)

Income (loss) from unconsolidated affiliates	$	-	$	-	$	-	$	59,738		$	-

Capital expenditures	$	34,399	$	165,359	$	10,562	$	189	⁽¹⁾	$	23,197		⁽²⁾
Total assets	$	1,558,776	$	1,062,109	$	1,308,901	$	1,322,496		$	103,844

					Mid-
	Utica				Continent			Corporate			Consolidated
Revenues	$	12,734			$	85,719		$	-		$	484,201
Operating expenses		4,815				35,179			21,651			165,607
Depreciation and amortization expense		3,465				16,806			6,091			138,519
General and administrative expense		-				-			48,823			48,823
Other operating expense		-				-			1,983			1,983
Operating income (loss)	$	4,454			$	33,734		$	(78,548	)	$	129,269

Income (loss) from unconsolidated affiliates	$	(1,090	)		$	105		$	-		$	58,753

Capital expenditures	$	159,779		⁽³⁾	$	68,130	⁽⁴⁾	$	83,979		$	545,594
Total assets	$	669,413			$	758,322		$	432,709		$	7,216,570

⁽¹⁾	Amount excludes $169.1 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

⁽²⁾	Amount includes $11.6 million of capital expenditures attributable to noncontrolling interest owners.

⁽³⁾	Amount excludes $184.0 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $55.8 million of capital expenditures attributable to noncontrolling interest owners.

⁽⁴⁾	Amount excludes $2.6 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.	Guarantor Condensed Consolidating Financial Information

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 subsidiary, Access MLP Operating, L.L.C., a direct 100 percent owned subsidiary of the Partnership. The Partnership’s obligations under its outstanding senior notes listed in Note 4 are fully and unconditionally guaranteed, jointly and severally, by certain of its direct and indirect 100 percent owned subsidiaries on a senior unsecured basis, 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. The Partnership’s subsidiaries Cardinal Gas Services, L.L.C. and Jackalope Gas Gathering Services, L.L.C. are not guarantors of the Partnership’s senior notes or credit facility.

Set forth below are condensed consolidating financial statements for the Partnership, as the parent company, on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2014 and December 31, 2013 and for the three and six months ended June 30, 2014 and 2013. These schedules are presented using the equity method of accounting for all periods presented. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2014

($ in thousands)

			Guarantor			Non-Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets
Cash and cash equivalents	$	-	$	8		$	36,667		$	-		$	36,675
Accounts receivable		-		153,556			28,383			-			181,939
Prepaid expenses		-		12,201			181			-			12,382
Other current assets		-		11,339			973			-			12,312
Total current assets		-		177,104			66,204			-			243,308

Property, plant and equipment
Gathering systems		-		5,457,491			949,057			-			6,406,548
Other fixed assets		-		361,800			133			-			361,933
Less: Accumulated depreciation		-		(975,412	)		(23,807	)		-			(999,219	)
Total property, plant and equipment, net		-		4,843,879			925,383			-			5,769,262
Investments in unconsolidated affiliates		3,225,723		2,642,277			-			(3,764,470	)		2,103,530
Intangible customer relationships, net		-		360,502			-			-			360,502
Intercompany receivable from parent		4,408,660		7,563			118			(4,416,341	)		-
Deferred loan costs, net		52,017		12,044			-			-			64,061

Total assets	$	7,686,400	$	8,043,369		$	991,705		$	(8,180,811	)	$	8,540,663


Current liabilities
Accounts payable	$	-	$	34,236		$	29,413		$	-		$	63,649
Accrued liabilities		-		215,753			56,802			-			272,555
Intercompany payable to parent		-		-			7,681			(7,681	)		-
Total current liabilities		-		249,989			93,896			(7,681	)		336,204

Long-term liabilities
Long-term debt		3,655,397		150,000			-			-			3,805,397
Intercompany payable to parent		-		4,408,660			-			(4,408,660	)		-
Other liabilities		-		8,997			272			-			9,269
Total long-term liabilities		3,655,397		4,567,657			272			(4,408,660	)		3,814,666

Partners' capital
Total partners' capital attributable to Access Midstream Partners, L.P.		4,031,003		3,225,723			897,537			(4,123,260	)		4,031,003
Noncontrolling interest		-		-			-			358,790			358,790
Total partners' capital		4,031,003		3,225,723			897,537			(3,764,470	)		4,389,793
Total liabilities and partners' capital	$	7,686,400	$	8,043,369		$	991,705		$	(8,180,811	)	$	8,540,663

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2013

($ in thousands)

			Guarantor			Non-Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets
Cash and cash equivalents	$	-	$	400		$	16,829		$	-		$	17,229
Accounts receivable		-		202,007			20,402			-			222,409
Prepaid expenses		-		10,182			-			-			10,182
Other current assets		-		7,569			542			-			8,111
Total current assets		-		220,158			37,773			-			257,931

Property, plant and equipment
Gathering systems		-		5,295,771			679,169			-			5,974,940
Other fixed assets		-		175,397			14			-			175,411
Less: Accumulated depreciation		-		(845,892	)		(13,659	)		-			(859,551	)
Total property, plant and equipment, net		-		4,625,276			665,524			-			5,290,800
Investments in unconsolidated affiliates		3,076,205		2,315,988			-			(3,455,590	)		1,936,603
Intangible customer relationships, net		-		372,391			-			-			372,391
Intercompany receivable from parent		3,882,291		3,105			20,330			(3,905,726	)		-
Deferred loan costs, net		46,140		13,581			-			-			59,721

Total assets	$	7,004,636	$	7,550,499		$	723,627		$	(7,361,316	)	$	7,917,446


Current liabilities
Accounts payable	$	-	$	36,638		$	882		$	-		$	37,520
Accrued liabilities		-		203,099			65,853			-			268,952
Intercompany payable to parent		-		-			23,435			(23,435	)		-
Total current liabilities		-		239,737			90,170			(23,435	)		306,472

Long-term liabilities
Long-term debt		2,905,730		343,500			-			-			3,249,230
Intercompany payable to parent		-		3,882,290			-			(3,882,290	)		-
Other liabilities		-		8,767			187			-			8,954
Total long-term liabilities		2,905,730		4,234,557			187			(3,882,290	)		3,258,184

Partners' capital
Total partners' capital attributable to Access Midstream Partners, L.P.		4,098,906		3,076,205			633,270			(3,709,475	)		4,098,906
Noncontrolling interest		-					-			253,884			253,884
Total partners' capital		4,098,906		3,076,205			633,270			(3,455,591	)		4,352,790
Total liabilities and partners' capital	$	7,004,636	$	7,550,499		$	723,627		$	(7,361,316	)	$	7,917,446

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2014

($ in thousands)

				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries		Eliminations			Consolidated

Revenues	$	-		$	253,458		$	39,476	$	-		$	292,934

Operating expenses
Operating expenses		-			80,031			17,492		-			97,523
Depreciation and amortization expense		-			84,452			5,524		-			89,976
General and administrative expense		-			35,354			1,903		-			37,257
Other operating (income) expense		-			(350	)		33		-			(317	)
Total operating expenses		-			199,487			24,952		-			224,439
Operating income		-			53,971			14,524		-			68,495

Other income (expense)
Income from unconsolidated affiliates		110,357			57,630			-		(119,924	)		48,063
Interest expense		(42,903	)		-			-		-			(42,903	)
Other income		-			141			57		-			198
Income before income tax expense		67,454			111,742			14,581		(119,924	)		73,853
Income tax expense		-			1,385			-		-			1,385
Net income		67,454			110,357			14,581		(119,924	)		72,468
Net income attributable to noncontrolling interests		-			-			-		5,014			5,014
Net income attributable to Access Midstream Partners, L.P.	$	67,454		$	110,357		$	14,581	$	(124,938	)	$	67,454

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2013

($ in thousands)

				Guarantor		Non-Guarantor
	Parent			Subsidiaries		Subsidiaries		Eliminations			Consolidated

Revenues	$	-		$	237,670	$	9,572	$	-		$	247,242

Operating expenses
Operating expenses		-			79,912		2,932		-			82,844
Depreciation and amortization expense		-			69,541		2,328		-			71,869
General and administrative expense		-			24,542		547		-			25,089
Other operating expense		-			1,892		-		-			1,892
Total operating expenses		-			175,887		5,807		-			181,694
Operating income		-			61,783		3,765		-			65,548

Other income (expense)
Income from unconsolidated affiliates		96,953			36,319		-		(99,527	)		33,745
Interest expense		(27,740	)		-		8		-			(27,732	)
Other income		-			111		15		-			126
Income before income tax expense		69,213			98,213		3,788		(99,527	)		71,687
Income tax expense		-			1,260		-		-			1,260
Net income		69,213			96,953		3,788		(99,527	)		70,427
Net income attributable to noncontrolling interests		-			-		-		1,214			1,214
Net income attributable to Access Midstream Partners, L.P.	$	69,213		$	96,953	$	3,788	$	(100,741	)	$	69,213

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2014

($ in thousands)

				Guarantor		Non-Guarantor
	Parent			Subsidiaries		Subsidiaries			Eliminations			Consolidated

Revenues	$	-		$	499,450	$	70,562		$	-		$	570,012

Operating expenses
Operating expenses		-			160,210		30,226			-			190,436
Depreciation and amortization expense		-			165,322		10,198			-			175,520
General and administrative expense		-			67,880		3,557			-			71,437
Other operating (income) expense		-			1,528		(40	)		-			1,488
Total operating expenses		-			394,940		43,941			-			438,881
Operating income		-			104,510		26,621			-			131,131

Other income (expense)
Income from unconsolidated affiliates		210,008			108,154		-			(227,221	)		90,941
Interest expense		(81,476	)		-		-			-			(81,476	)
Other income		-			533		57			-			590
Income before income tax expense		128,532			213,197		26,678			(227,221	)		141,186
Income tax expense		-			3,189		-			-			3,189
Net income		128,532			210,008		26,678			(227,221	)		137,997
Net income attributable to noncontrolling interests		-			-		-			9,465			9,465
Net income attributable to Access Midstream Partners, L.P.	$	128,532		$	210,008	$	26,678		$	(236,686	)	$	128,532

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2013

($ in thousands)

				Guarantor		Non-Guarantor
	Parent			Subsidiaries		Subsidiaries		Eliminations			Consolidated

Revenues	$	-		$	467,240	$	16,961	$	-		$	484,201

Operating expenses
Operating expenses		-			160,513		5,094		-			165,607
Depreciation and amortization expense		-			134,373		4,146		-			138,519
General and administrative expense		-			48,120		703		-			48,823
Other operating expense		-			1,983		-		-			1,983
Total operating expenses		-			344,989		9,943		-			354,932
Operating income		-			122,251		7,018		-			129,269

Other income (expense)
Income from unconsolidated affiliates		183,557			63,426		-		(188,230	)		58,753
Interest expense		(54,806	)		-		12		-			(54,794	)
Other income		-			380		15		-			395
Income before income tax expense		128,751			186,057		7,045		(188,230	)		133,623
Income tax expense		-			2,500		-		-			2,500
Net income		128,751			183,557		7,045		(188,230	)		131,123
Net income attributable to noncontrolling interests		-			-		-		2,372			2,372
Net income attributable to Access Midstream Partners, L.P.	$	128,751		$	183,557	$	7,045	$	(190,602	)	$	128,751

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2014

($ in thousands)

				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations		Consolidated

Cash flows from operating activities	$	-		$	405,796		$	56,965		$	-	$	462,761

Cash flows from investing activities
Additions to property, plant and equipment		-			(246,455	)		(274,715	)		-		(521,170	)
Purchase of compression assets		-			(159,210	)		-			-		(159,210	)
Investments in unconsolidated affiliates		-			(220,378	)		-			-		(220,378	)
Proceeds from sale of assets		-			14,296			-			-		14,296
Net cash used in investing activities		-			(611,747	)		(274,715	)		-		(886,462	)

Cash flows from financing activities
Proceeds from long-term borrowings		-			1,053,471			-			-		1,053,471
Payments on long-term debt borrowings		-			(1,246,971	)		-			-		(1,246,971	)
Proceeds from issuance of common units		52,155			-			-			-		52,155
Proceeds from issuance of senior notes		750,000			-			-			-		750,000
Distributions to unitholders		(252,145	)		-			-			-		(252,145	)
Capital contributions from noncontrolling interests		-			-			95,441			-		95,441
Payments on capital lease obligations		-			(1,983	)		-			-		(1,983	)
Debt issuance costs		(8,777	)		-			-			-		(8,777	)
Other		1,956			-			-			-		1,956
Intercompany advances, net		(543,189	)		401,042			142,147			-		-
Net cash provided by financing activities		-			205,559			237,588			-		443,147

Net increase in cash and cash equivalents		-			(392	)		19,838			-		19,446
Cash and cash equivalents, beginning of period		-			400			16,829			-		17,229
Cash and cash equivalents, end of period	$	-		$	8		$	36,667		$	-	$	36,675

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2013

($ in thousands)

				Guarantor			Non-Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations		Consolidated

Cash flows from operating activities	$	-		$	206,739		$	10,841		$	-	$	217,580

Cash flows from investing activities
Additions to property, plant and equipment		-			(356,868	)		(188,726	)		-		(545,594	)
Investments in unconsolidated affiliates		-			(263,710	)		-			-		(263,710	)
Proceeds from sale of assets		-			31,696			-			-		31,696
Net cash used in investing activities		-			(588,882	)		(188,726	)		-		(777,608	)

Cash flows from financing activities
Proceeds from long-term borrowings		-			875,500			-			-		875,500
Payments on long-term debt borrowings		-			(659,300	)		-			-		(659,300	)
Proceeds from issuance of common units		399,922			-			-			-		399,922
Proceeds from issuance of senior notes		-			-			-			-		-
Distributions to unitholders		(177,430	)		-			-			-		(177,430	)
Capital contributions from noncontrolling interests		-			-			71,414			-		71,414
Payments on capital lease obligations		-			-			-			-		-
Debt issuance costs		(660	)		(4,717	)		-			-		(5,377	)
Other		8,328			-			-			-		8,328
Intercompany advances, net		(230,160	)		107,444			122,716			-		-
Net cash provided by financing activities		-			318,927			194,130			-		513,057

Net increase in cash and cash equivalents		-			(63,216	)		16,245			-		(46,971	)
Cash and cash equivalents, beginning of period		-			63,216			1,778			-		64,994
Cash and cash equivalents, end of period	$	-		$	-		$	18,023		$	-	$	18,023

ACCESS MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

11. Recently Issued Accounting Standards

The Financial Accounting Standards Board (“FASB”) recently issued the following standard which the Partnership reviewed to determine the potential impact on its financial statements upon adoption.

On May 28, 2014, FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. The standard will eliminate the transaction and industry specific revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining revenue recognition. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under today’s guidance. This guidance will be effective for the Partnership beginning January 1, 2017. The Partnership is currently evaluating the impact of this new standard on its condensed consolidated financial statements.

12. Subsequent Events

On July 24, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.595 per unit, together with the corresponding distributions to the Class B unitholders and the general partner. The cash distributions will be paid on August 14, 2014, to unitholders of record at the close of business on August 7, 2014, and to the general partner.

On July 1, 2014, Williams acquired all of the interests in the Partnership and Access Midstream Ventures, L.L.C., the sole member of the General Partner, that were owned by the GIP II Entities. As a result of the closing of the Williams Acquisition, Williams owns 100% of the General Partner, and the GIP II Entities no longer have any ownership interest in the Partnership or the General Partner. As a result of the Williams Acquisition, all units outstanding under the LTIP at June 30, 2014, vested on July 1, 2014, resulting in total compensation expense of $38.5 million. Additionally, both components of the Management Incentive Compensation Plan vested on July 1, 2014, resulting in accelerated compensation expense of $41.1 million.

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 refer to Access Midstream Partners, L.P. (NYSE: ACMP) and its subsidiaries. The “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).

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 Energy Corporation (“Chesapeake”), Total Gas and Power North America, Inc. and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (“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 the Barnett Shale region in north-central Texas; the Eagle Ford Shale region in South Texas; the Haynesville Shale region in northwest Louisiana; the Marcellus Shale region primarily in Pennsylvania and West Virginia; the Niobrara Shale region in eastern Wyoming; the Utica Shale region in eastern Ohio; and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins

Williams Acquisition

On July 1, 2014, Williams acquired all of the interests in the Partnership and Access Midstream Ventures, L.L.C., the sole member of Access Midstream Partners GP, L.L.C. (the “General Partner”), that were owned by the GIP II Entities (the “Williams Acquisition”). As a result of the closing of the Williams Acquisition, Williams owns 100% of the General Partner, and the GIP II Entities no longer have any ownership interest in the Partnership or the General Partner. All of the equity awards previously issued under the Long-Term Incentive Plan vested on July 1, 2014 upon closing of the Williams Acquisition, resulting in compensation expense of $38.5 million. Additionally, both components of the Management Incentive Compensation Plan (“MICP”) vested on July 1, 2014, resulting in expected total cash payments to MICP participants of $88.8 million during the 2014 third quarter and compensation expense of $41.1 million in the 2014 third quarter. On July 16, 2014, we issued to certain key employees cash and equity retention awards that have various vesting periods between one and four years. Williams has proposed the merger of Williams Partners L.P. (NYSE:WPZ) (“Williams Partners”) with and into one of our subsidiaries. The proposed merger is subject to negotiation, review and approval by the conflicts committee of each partnership’s board of directors, as well as approval by each partnership’s board of directors.

Our Compression Acquisition

On March 31, 2014, we acquired certain midstream compression assets from MidCon Compression, L.L.C. (“MidCon”), a wholly owned subsidiary of Chesapeake, for approximately $160 million. The acquisition adds natural gas compression assets, historically leased from MidCon, in the rapidly growing Utica Shale and Marcellus Shale regions. This transaction provides the opportunity to insource a key cost element of our business model and adds the potential for additional future organic growth to the portfolio. The acquired assets include more than 100 compression units with a combined capacity of approximately 200,000 horsepower.

Our Commercial Agreements with Producers

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

Future fees 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 the 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. The 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 the 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 three 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 the 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.

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 the Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period. During the minimum volume commitment 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 natural 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 gather, compress, dehydrate and treat natural gas and liquids for Chesapeake 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 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, Chesapeake 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 natural gas delivered to us by Chesapeake relative to its scheduled deliveries. Effective on January 1, 2015 and January 1 of each year thereafter for a period of 18 years, 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 Chesapeake, we have the option to connect new operated wells within the Eagle Ford Shale region acreage dedications as requested by Chesapeake. If we elect not to connect a new operated well, Chesapeake 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 Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to the 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 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.

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.

Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake 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 determine adjustments to fees for the gathering systems in the region with Chesapeake 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 Chesapeake in the acreage dedications. Chesapeake is required to provide us notice of new drilling pads and wells operated by Chesapeake 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. If we fail to complete a connection in the Springridge acreage dedication by the required date, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Chesapeake is also 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, Chesapeake 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 Chesapeake on caps on fuel and lost and unaccounted for gas on our systems with respect to its 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 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, Chesapeake 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, Chesapeake has agreed to minimum volume commitments for each year through December 31, 2017. If Chesapeake 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 is obligated to pay us the Mansfield fee for each MMBtu by which the minimum volume commitment exceeded the actual volumes of natural gas delivered to us.

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 natural gas delivered to us from Chesapeake’s wells relative to its scheduled deliveries.

Well Connection Requirement. We have certain connection obligations for new operated wells in our acreage dedications. Chesapeake 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 Chesapeake on percentage-based caps on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’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 Energy Ltd. (“Epsilon”), Mitsui and Chief Oil & Gas LLC (“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 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.

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 for a period of 15 years. 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 three 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 natural gas from such outside wells will not be afforded the same priority as natural gas produced from wells located within the dedicated area.

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. Natural 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.

Niobrara Shale Region. Under our gas gathering and processing agreements with Chesapeake and RKI Exploration & Production, LLC (“RKI”), 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 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, each of Chesapeake and RKI have 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 1 of each year thereafter for a period of 20 years from July 1, 2012, our 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 Chesapeake and RKI, we will have the option to connect new operated wells within our Niobrara region acreage dedications as requested by our producer customers. If we elect not to connect a new operated well, either Chesapeake and RKI, as applicable, will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreements, 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 each Chesapeake and RKI to a cap on fuel and lost and unaccounted for gas on our systems with respect to the 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 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 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 a wet gas gathering system (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”) 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 process and fractionate natural gas and NGLs through our 49 percent non-operating interest in a joint venture (the “UEO Joint Venture”) that operates three processing facilities with a total capacity of 600 MMcf per day and planned incremental capacity of 400 MMcf per day by the end of 2015. The UEO Joint Venture operates two 45,000 barrel per day fractionation facilities and is currently constructing one additional 45,000 fractionation facility. The UEO Joint Venture also operates approximately 870,000 barrels of NGL storage capacity and other ancillary assets for a fixed fee that escalates annually within a specified range. We refer to these fees collectively as the Utica fee.

Acreage Dedication. Subject to certain exceptions, our producer customers have agreed to dedicate 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 from Chesapeake, Total, Enervest and American Energy – Utica, LLC in support of 1.0 bcf/d of capacity.

Fee Redetermination. Beginning on October 1, 2013, for the Cardinal Joint Venture and January 1, 2014, for the 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 is 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 the 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 the 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 agreements 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 determine adjustments 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.

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 are 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.

We own a 33.33 percent 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 natural gas processing services under a cost of service fee arrangement.

All Regions. If one of the counterparties to these gas gathering and processing agreements sells, transfers or otherwise disposes of properties within the our acreage dedications to a third party, it does so subject to the terms of the gas gathering and processing agreements, 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 and processing agreements with us, subject to our consent. Our producer customers’ dedication of the natural gas produced from applicable properties under our gas gathering and processing 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

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 us (the “GIP Acquisition”), we entered into a letter agreement with Chesapeake regarding the terms on which Chesapeake provides certain transition services to us and our general partner. Among other things, the letter agreement provided for the continuation of our services 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. On December 20, 2012, in connection with the CMO Acquisition, we entered into an amendment to the letter agreement amending certain terms relating primarily to the extension of transition services for technology related services through September 2014 for certain field communication support services.

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) segment operating income, (v) Adjusted EBITDA and (vi) distributable cash flow.

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, and the actual volumes of natural gas we gather, treat, compress, and 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 region and Chesapeake in the case of our Haynesville Shale region as well as fee redetermination and cost of service provisions in our other regions. We contract with producers to gather or process natural gas or liquids from individual wells located near our gathering systems or processing facilities. 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 the three-month periods ended June 30, 2014 and June 30, 2013, respectively, Chesapeake accounted for approximately 71.3 percent and 75.0 percent, respectively, of the natural gas volumes on our gathering systems and approximately 82.1 percent and 85.2 percent, respectively, of our revenues. For the six-month periods ended June 30, 2014 and June 30, 2013, respectively, Chesapeake accounted for approximately 71.3 percent and 75.9 percent, respectively, of the natural gas volumes on our gathering systems and 82.5 percent and 85.3 percent, respectively, of our revenues. Our revenues exclude revenue attributable to our equity investments, as those revenues are accounted for as part of our investments in unconsolidated affiliates.

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.

Segment Operating Income

Our operations are divided into eight operating segments: Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica, Mid-Continent and Corporate.

Adjusted EBITDA

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

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.

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 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.

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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	($ in thousands)
Reconciliation of adjusted EBITDA and distributable cash flow to net income:
Net income attributable to Access Midstream Partners, L.P.	$	67,454		$	69,213		$	128,532		$	128,751

Interest expense		42,903			27,732			81,476			54,794
Income tax expense		1,385			1,260			3,189			2,500
Depreciation and amortization expense		89,976			71,869			175,520			138,519
Other		(2,116	)		320			(2,897	)		(320	)
Income from unconsolidated affiliates		(48,063	)		(33,745	)		(90,941	)		(58,753	)
EBITDA from unconsolidated affiliates⁽¹⁾		73,042			49,751			139,568			89,210
Expense for non-cash equity awards		13,975			8,933			23,789			16,323
Implied minimum volume commitment		36,500			11,250			67,000			20,000

Adjusted EBITDA	$	275,056		$	206,583		$	525,236		$	391,024

Maintenance capital expenditures		(32,500	)		(27,500	)		(65,000	)		(55,000	)
Cash portion of interest expense		(40,750	)		(25,115	)		(77,374	)		(50,207	)
Income tax expense		(1,385	)		(1,260	)		(3,189	)		(2,500	)

Distributable Cash Flow	$	200,421		$	152,708		$	379,673		$	283,317

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	($ in thousands)
Reconciliation of adjusted EBITDA and distributable cash flow to net cash provided by operating activities:
Cash provided by operating activities	$	192,937		$	137,450		$	462,761		$	217,580

Changes in assets and liabilities		(28,252	)		(26,358	)		(72,225	)		(15	)
Distribution of earnings received from unconsolidated affiliates		(43,316	)		—			(155,358	)		—
Interest expense		42,903			27,732			81,476			54,794
Income tax expense		1,385			1,260			3,189			2,500
Other non-cash items		(14,118	)		(3,435	)		(24,964	)		(9,368	)
EBITDA from unconsolidated affiliates⁽¹⁾		73,042			49,751			139,568			89,210
Expense for non-cash equity awards		13,975			8,933			23,789			16,323
Implied minimum volume commitment		36,500			11,250			67,000			20,000

Adjusted EBITDA	$	275,056		$	206,583		$	525,236		$	391,024

Maintenance capital expenditures		(32,500	)		(27,500	)		(65,000	)		(55,000	)
Cash portion of interest expense		(40,750	)		(25,115	)		(77,374	)		(50,207	)
Income tax expense		(1,385	)		(1,260	)		(3,189	)		(2,500	)

Distributable Cash Flow	$	200,421		$	152,708		$	379,673		$	283,317

⁽¹⁾	EBITDA from unconsolidated affiliates is calculated as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014		2013
	($ in thousands)
Net income	$	48,063	$	33,745		$	90,941	$	58,753

Depreciation and amortization expense		24,857		16,007			48,507		30,473
Other		122		(1	)		120		(16	)

EBITDA from unconsolidated affiliates	$	73,042	$	49,751		$	139,568	$	89,210

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	($ in thousands)
GAAP Capital Expenditures	$	251,539		$	274,640		$	521,170		$	545,594

Adjusted for:
Capital expenditures included in unconsolidated affiliates		113,454			190,172			222,844			355,678
Capital expenditures attributable to noncontrolling interest		(57,315	)		(39,594	)		(104,262	)		(67,346	)

Net Capital Expenditures	$	307,678		$	425,218		$	639,752		$	833,926

Results of Operations – Three Months Ended June 30, 2014 versus June 30, 2013

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 June 30, 2014 (the “Current Quarter”) and the three months ended June 30, 2013 (the “Prior Quarter”):

	Three Months Ended June 30,
	2014			2013			% Change⁽⁴⁾
	($ in thousands, except operational data)
Revenues⁽¹⁾	$	292,934		$	247,242			18.5	%
Operating expenses		97,523			82,844			17.7
Depreciation and amortization expense		89,976			71,869			25.2
General and administrative expense		37,257			25,089			48.5
Other operating (income) expense		(317	)		1,892			N.M.
Total operating expenses		224,439			181,694			23.5
Operating income		68,495			65,548			4.5
Income from unconsolidated affiliates		48,063			33,745			42.4
Interest expense		(42,903	)		(27,732	)		54.7
Other income		198			126			57.1
Income before income tax expense		73,853			71,687			3.0
Income tax expense		1,385			1,260			9.9
Net income		72,468			70,427			2.9
Net income attributable to noncontrolling interests		5,014			1,214			N.M.
Net income attributable to Access Midstream Partners, L.P.	$	67,454		$	69,213			(2.5	)
Key Performance Metrics:
Adjusted EBITDA⁽²⁾	$	275,056		$	206,583			33.1
Distributable cash flow⁽²⁾	$	200,421		$	152,708			31.2
Operational Data⁽³⁾:
Throughput, Bcf per day		3.918			3.665			6.9
Miles of pipe at end of period		6,495			6,379			1.8
Gas compression (horsepower) at end of period		623,896			472,817			(32.0	)

(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 applicable 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 under the caption How 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 our interest.

(4)	N.M. - not meaningful

The following tables reflect our revenues, throughput, operating expenses and operating expenses per Mcf of throughput by region for the three months ended June 30, 2014 and 2013 (please note that revenue, throughput and operating expenses related to our equity investments (primarily in the Marcellus Shale region) 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):

	Three Months Ended June 30,
	2014		2013		% Change⁽²⁾
	($ In thousands, except percentages and throughput data)
Revenues⁽¹⁾:
Barnett Shale	$	83,788	$	90,384		(7.3	)%
Eagle Ford Shale		84,016		67,752		24.0
Haynesville Shale		29,076		30,621		(5.0	)
Marcellus Shale		3,930		4,012		(2.0	)
Niobrara Shale		5,577		2,431		N.M.
Utica Shale		33,899		7,238		N.M.
Mid-Continent		52,648		44,804		17.5
	$	292,934	$	247,242		18.5	%
Throughput (bcf)⁽¹⁾:
Barnett Shale		84.3		93.2		(9.5	)%
Eagle Ford Shale		26.6		23.5		13.2
Haynesville Shale		55.3		63.2		(12.5	)
Marcellus Shale		107.9		90.7		19.0
Niobrara Shale		2.0		0.9		N.M.
Utica Shale		29.1		6.7		N.M.
Mid-Continent		51.4		55.3		(7.1	)
		356.6		333.5		6.9	%
Operating Expenses⁽¹⁾:
Barnett Shale	$	22,538	$	23,963		(5.9	)%
Eagle Ford Shale		15,509		14,951		3.7
Haynesville Shale		10,986		9,109		20.6
Marcellus Shale		2,197		198		N.M.
Niobrara Shale		2,997		1,946		54.0
Utica Shale		11,805		2,269		N.M.
Mid-Continent		19,442		16,975		14.5
Corporate		12,049		13,433		(10.3	)
	$	97,523	$	82,844		17.7	%
Expenses ($ per mcf):
Barnett Shale	$	0.27	$	0.26		3.8	%
Eagle Ford Shale		0.58		0.64		(9.4	)
Haynesville Shale		0.20		0.14		42.9
Marcellus Shale		2.75		0.12		N.M.
Niobrara Shale		0.75		1.12		(33.0	)
Utica Shale		0.27		0.23		17.4
Mid-Continent		0.38		0.31		22.6
Corporate		—		—		—
	$	0.37	$	0.33		12.1	%

(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.

(2)	N.M – not meaningful

Segment Reporting

We present information in this Management’s Discussion and Analysis of Financial Condition and Results of Operations 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. 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 $83.8 million compared to $90.4 million in the Prior Quarter, a decrease of $6.6 million, or 7.3 percent. A decrease in throughput due to decreased drilling activity resulted in an $8.7 million decrease in revenue which was partially offset by an annual fixed fee rate escalation of two percent on January 1, 2014. 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 2014 fourth quarter. The minimum volume commitment is measured annually and 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 $32.5 million in the Current Quarter based on the projected full year volume shortfall.

Operating Expenses. For the Current Quarter, operating expenses were $22.5 million, or $0.27 per Mcf, compared to $24.0 million, or $0.26 per Mcf, during the Prior Quarter. The decrease in total operating expense is primarily the result of a decrease in compression expense due to lower compressor rates for 2014. While total operating costs remained consistent compared to 2013, operating expenses per mcf have increased as a result of both decreased drilling activity in the region caused by the low natural gas price environment and the natural decline of existing wells.

Depreciation and Amortization Expense. For the Current Quarter and the Prior Quarter, depreciation expense was $25.1 million and $24.0 million, respectively. The increase was due to capital expenditures made in this region during 2014 and 2013.

Eagle Ford Shale

Revenues. For the Current Quarter, revenues in the Eagle Ford totaled $84.0 million compared to $67.8 million in the Prior Quarter, an increase of $16.2 million, or 24.0 percent. The increase in revenues was primarily attributable to a 13.2 percent increase in throughput, a contractual increase in fees and additional services provided in this region in 2014.

Operating Expenses. For the Current Quarter, operating expenses totaled $15.5 million or $0.58 per Mcf, compared to $15.0 million, or $0.64 per Mcf, during the Prior Quarter. The most significant operating expenses in this region are compression and compensation costs, both of which increased from the Prior Quarter due to increased activity in this region.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $15.7 million compared to $13.4 million during the Prior Quarter. The increase was due to capital expenditures made in this region during 2014 and 2013.

Haynesville Shale

Revenues. For the Current Quarter, Haynesville Shale revenues totaled $29.1 million compared to $30.6 million in the Prior Quarter, a decrease of $1.5 million, or 5.0 percent. A decrease in throughput due to a decrease in drilling activity by Chesapeake resulted in a $3.7 million decrease in revenue which was partially offset by an annual rate escalation of 2.5 percent, and in the Springridge gathering system only, rate redetermination of 15 percent, both effective January 1, 2014. Because throughput in the Haynesville Shale during the Current Quarter was below contractual minimum volume commitment levels, we expect to recognize additional revenue related to volume shortfall in the 2014 fourth quarter. The minimum volume commitment is measured annually and 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 $4.0 million in the Current Quarter based on the projected full year volume shortfall.

Operating Expenses. For the Current Quarter, operating expenses were $11.0 million, or $0.20 per Mcf compared to $9.1 million, or $0.14 per Mcf during the Prior Quarter. The increase in operating expenses is primarily a result of increased ad valorem taxes due to reassessments on the properties for 2014.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $20.6 million compared to $19.5 million during the Prior Quarter. The increase relates almost entirely to depreciation of our operating assets in this region.

Marcellus Shale

On September 4, 2013 we sold Mid-Atlantic Gas Services, L.L.C. (“Mid-Atlantic”) to Chesapeake for net proceeds of $32.9 million. Mid-Atlantic was acquired in December 2012 and consisted of midstream assets in the Marcellus Shale region. These assets were not part of our equity method investment in Appalachia Midstream. The net proceeds equaled our basis in the assets; thus, no gain or loss was recognized as a result of the sale.

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.

Income from Unconsolidated Affiliates. We own an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale region in Pennsylvania and West Virginia. The remaining average 53 percent interests in these assets are owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates for the Appalachia Midstream assets was $40.7 million and $34.5 million for the Current Quarter and Prior Quarter, respectively. Revenues (net to our interest) for the Current Quarter and Prior Quarter were $68.7 million and $58.3 million, respectively. The net increase was the result of throughput growth and increased drilling by our producer customers in the Marcellus Shale as well as increased construction activity where we invested $289.7 million of capital in 2013. Operating expenses for the Current Quarter and Prior Quarter were $11.3 million and $8.2 million, respectively. The increase in operating expenses is consistent with the increase in revenues in the Marcellus region. The margin for these assets is strong as a result of lower operating expenses than in many other regions of the United States. These lower operating expenses are primarily due to high reservoir pressures that reduce the need for compression in the transportation of commodities. We expect our margin in the Marcellus Shale to remain strong; however, we could experience a slight decrease in our margin over time as the need for additional compression increases. 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 June 30, 2014		Three Months Ended June 30, 2013
Revenues ($ in thousands)	$	68,692	$	58,261
Throughput (Bcf)		107.1		89.0
Operating expenses ($ in thousands)	$	11,324	$	8,203
Expenses ($ per Mcf)		0.11		0.09

Niobrara Shale

We own a 50 percent interest in certain gas gathering, compression and processing assets in the Niobrara Shale region. 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 consolidated 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 $5.6 million compared to $2.4 million in the Prior Quarter, an increase of $3.2 million. The increase in throughput resulted primarily from a $3.4 million increase in revenue offset by a fee redetermination decrease effective January 1, 2014. 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 $3.0 million, or $0.75 per Mcf compared to $1.9 million, or $1.12 per Mcf during the Prior Quarter. Operating expenses are expected to increase throughout 2014 as construction activity increases and we prepare to provide additional gathering and processing services in this region in future periods. The most significant operating expenses in this region are compression costs and compensation.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $1.5 million compared to $1.2 million during the Prior Quarter. The increase was due to capital expenditures made in this region during 2014 and 2013.

Utica Shale

In the Utica Shale region, we own 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 four wholly-owned gas gathering assets and have contractual discretion to make operating decisions for the Cardinal Joint Venture, we are deemed to control the assets and, as a result, 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 $33.9 million compared to $7.2 million in the Prior Quarter, an increase of $26.7 million. The growth is primarily the result of increased throughput due to increased drilling and compression activity which resulted in a $24.2 million increase in revenue.

Operating Expenses. For the Current Quarter, operating expenses totaled $11.8 million, or $0.27 per Mcf compared to $2.3 million, or $0.23 per Mcf during the Prior Quarter. The increase in operating expenses is primarily a result of the increase in operating activity in the Utica Shale region.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $5.4 million compared to $2.3 million during the Prior Quarter. The increase was due to capital expenditures made in this region during 2014 and 2013.

Income from unconsolidated affiliates. For the Current Quarter and the Prior Quarter, income (loss) from unconsolidated affiliates was $4.6 million and $(0.9) million, respectively.

Mid-Continent

Revenues. For the Current Quarter, Mid-Continent revenues totaled $52.6 million compared to $44.8 million in the Prior Quarter, an increase of $7.8 million, or 17.5 percent. This increase was caused primarily by a 2.5 percent annual rate increase and a 15 percent increase in fees as a result of rate redetermination, both effective January 1, 2014, offset by a 7.1 percent decrease in throughput.

Operating Expenses. For the Current Quarter, operating expenses were $19.4 million, or $0.38 per Mcf compared to $17.0 million, or $0.31 per Mcf during the Prior Quarter. The increase occurred across most operating costs in this region as a result of our increased activity driven by greater drilling activity in this liquids-rich region by our producer customers.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $10.8 million compared to $8.2 million during the Prior Quarter. The increase was due to capital expenditures made in this region during 2014 and 2013.

Income from unconsolidated affiliates. We own a 33.33 percent equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC. For the Current Quarter and the Prior Quarter, income from unconsolidated affiliates was $2.8 million and $0.2 million, respectively.

Corporate

Operating Expenses. For the Current Quarter, operating expenses were $12.0 million compared to $13.4 million during the Prior Quarter. The decrease in operating expenses resulted from a decrease in ad valorem taxes as a result of 2014 reassessments and most other operating costs as we focused our operating growth in the other segments.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Quarter was $8.5 million compared to $3.4 million during the Prior Quarter. The increase in depreciation expense is a result of capital expenditures to back office infrastructure made in 2014 and 2013.

General and Administrative Expense. During the Current Quarter, general and administrative expenses were $37.3 million compared to $25.1 million during the Prior Quarter. This increase is primarily attributable to an increase in contract labor of $1.4 million and compensation of $8.1 million, which was primarily a result of increased equity compensation due to an increase in our unit price.

Interest Expense. Interest expense was $42.9 million for the Current Quarter compared to $27.7 million for the Prior Quarter. These amounts were net of $9.8 million and $10.2 million of capitalized interest during the Current Quarter and the Prior Quarter, respectively. The increase is related to interest expense on the 2021 Notes and 2024 Notes issued in August 2013 and March 2014, respectively. 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.

Results of Operations – Six Months Ended June 30, 2014 versus June 30, 2013

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 six months ended June 30, 2014 (the “Current Period”) and the six months ended June 30, 2013 (the “Prior Period”):

	Six Months Ended June 30,
	2014			2013			% Change⁽⁴⁾
	($ in thousands, except operational data)
Revenues⁽¹⁾	$	570,012		$	484,201			17.7	%
Operating expenses		190,436			165,607			15.0
Depreciation and amortization expense		175,520			138,519			26.7
General and administrative expense		71,437			48,823			46.3
Other operating expense		1,488			1,983			(25.0	)
Total operating expenses		438,881			354,932			23.7
Operating income		131,131			129,269			1.4
Income from unconsolidated affiliates		90,941			58,753			54.8
Interest expense		(81,476	)		(54,794	)		48.7
Other income		590			395			49.4
Income before income tax expense		141,186			133,623			5.7
Income tax expense		3,189			2,500			27.6
Net income		137,997			131,123			5.2
Net income attributable to noncontrolling interests		9,465			2,372			N.M.
Net income attributable to Access Midstream Partners, L.P.	$	128,532		$	128,751			N.M.
Key Performance Metrics:
Adjusted EBITDA⁽²⁾	$	525,236		$	391,024			34.3
Distributable cash flow⁽²⁾	$	379,673		$	283,317			34.0
Operational Data⁽³⁾:
Throughput, Bcf per day		3.873			3.607			7.4
Miles of pipe at end of period		6,495			6,379			1.8
Gas compression (horsepower) at end of period		623,896			472,817			(32.0	)

(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 under the caption How 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.

(4)	N.M. - not meaningful

The following tables reflect the Partnership’s revenues, throughput, operating expenses and operating expenses per Mcf of throughput by segment for the six months ended June 30, 2014 and 2013 (please note that revenue and operating expenses related to our equity investments (primarily in the Marcellus Shale region) 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):

	Six Months Ended June 30,
	2014		2013		% Change⁽²⁾
	($ In thousands, except percentages and throughput data)
Revenues⁽¹⁾:
Barnett Shale	$	171,606	$	183,468		(6.5	)%
Eagle Ford Shale		162,106		125,711		29.0
Haynesville Shale		56,533		64,095		(11.8	)
Marcellus Shale		5,301		7,741		(31.5	)
Niobrara Shale		12,089		4,733		N.M.
Utica Shale		58,473		12,734		N.M.
Mid-Continent		103,904		85,719		21.2
	$	570,012	$	484,201		17.7	%
Throughput (bcf)⁽¹⁾:
Barnett Shale		171.8		189.1		(9.1	)%
Eagle Ford Shale		50.6		44.0		15.0
Haynesville Shale		105.6		132.5		(20.3	)
Marcellus Shale		216.4		168.3		28.6
Niobrara Shale		4.4		1.8		N.M.
Utica Shale		50.1		11.6		N.M.
Mid-Continent		102.2		105.6		(3.2	)
		701.1		652.9		7.4	%
Operating Expenses⁽¹⁾:
Barnett Shale	$	47,758	$	47,902		(0.3	)%
Eagle Ford Shale		31,347		29,351		6.8
Haynesville Shale		21,076		20,424		3.2
Marcellus Shale		3,113		2,795		11.4
Niobrara Shale		5,295		3,490		51.7
Utica Shale		20,223		4,815		N.M.
Mid-Continent		37,351		35,179		6.2
Corporate		24,273		21,651		12.1
	$	190,436	$	165,607		15.0	%
Expenses ($ per mcf):
Barnett Shale	$	0.28	$	0.25		12.0	%
Eagle Ford Shale		0.62		0.67		(7.5	)
Haynesville Shale		0.20		0.15		33.3
Marcellus Shale		2.22		0.93		N.M.
Niobrara Shale		0.60		1.01		40.6
Utica Shale		0.27		0.28		3.6
Mid-Continent		0.37		0.33		12.1
Corporate		—		—		—
	$	0.37	$	0.33		12.1	%

(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.

(2)	N.M. – not meaningful

Segment Reporting

Barnett Shale

Revenues. For the Current Period, Barnett Shale revenues totaled $171.6 million compared to $183.5 million in the Prior Period, a decrease of $11.9 million, or 6.5 percent. A decrease in throughput due to decreased drilling activity resulted in an $16.8 million decrease in revenue which was partially offset by an annual fixed fee rate escalation of two percent on January 1, 2014. Because throughput in the Barnett Shale during the Current Period was significantly below contractual minimum volume commitment levels, we expect to recognize additional revenue related to volume shortfall in the 2014 fourth quarter. The minimum volume commitment is measured annually and 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 $59.0 million in the Current Period based on the projected full year volume shortfall.

Operating Expenses. For the Current Period, operating expenses were $47.8 million, or $0.28 per Mcf, compared to $47.9 million, or $0.25 per Mcf, during the Prior Period. Total operating expenses remained flat due to an increase in ad valorem taxes, which was a result of capital investment in the Barnett Shale region in 2013, offsetting a decrease in compression expense. While total operating costs remained consistent, operating expense per Mcf has increased due to both decreased drilling activity in the region caused by the low natural gas price environment and the natural decline of existing wells.

Depreciation and Amortization Expense. For the Current Period and the Prior Period, depreciation expense was $50.4 million and $47.9 million, respectively. The increase was due to capital expenditures made in this region during 2014 and 2013.

Eagle Ford Shale

Revenues. For the Current Period, revenues in the Eagle Ford totaled $162.1 million compared to $125.7 million in the Prior Period, an increase of $36.4 million, or 29.0 percent. The increase in revenues was primarily attributable to a 15.0 percent increase in throughput, a contractual increase in fees and additional services provided in this region.

Operating Expenses. For the Current Period, operating expenses totaled $31.3 million or $0.62 per Mcf, compared to $29.4 million, or $0.67 per Mcf, during the Prior Period. The most significant operating expenses in this region are compression and compensation costs, which both increased from the Prior Period due to increased activity in this region.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $30.8 million compared to $23.5 million during the Prior Period. The increase was due to capital expenditures made in this region during 2014 and 2013.

Haynesville Shale

Revenues. For the Current Period, Haynesville Shale revenues totaled $56.5 million compared to $64.1 million in the Prior Period, a decrease of $7.6 million, or 11.8 percent. A decrease in throughput due to a decrease in drilling activity by Chesapeake resulted in a $12.6 million decrease in revenue which was partially offset by an annual rate escalation of 2.5 percent, and in the Springridge gathering system only, rate redetermination of 15 percent, both effective January 1, 2014. Because throughput in the Haynesville Shale during the Current Period was below contractual minimum volume commitment levels, we expect to recognize additional revenue related to volume shortfall in the 2014 fourth quarter. The minimum volume commitment is measured annually and 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 $8.0 million in the Current Period based on the projected full year volume shortfall.

Operating Expenses. For the Current Period, operating expenses were $21.1 million, or $0.20 per Mcf compared to $20.4 million, or $0.15 per Mcf during the Prior Period. The increase in operating expenses is primarily a result of increased ad valorem taxes due to reassessments on the properties for 2014.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $40.9 million compared to $38.8 million during the Prior Period. The increase relates almost entirely to depreciation of our operating assets in this region.

Marcellus Shale

Income from Unconsolidated Affiliates. We own an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale region in Pennsylvania and West Virginia. The remaining average 53 percent interests in these assets are owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates for the Appalachia Midstream assets was $81.2 million and $59.7 million for the Current Period and Prior Period, respectively. Revenues (net to our interest) for the Current Period and Prior Period were $137.0 million and $104.3 million, respectively. The net increase was the result of throughput growth and increased drilling by our producer customers in the Marcellus Shale as well as increased construction activity where we invested $289.7 million of capital in 2013. Operating expenses for the Current Period and Prior Period were $20.3 million and $14.9 million, respectively. The increase in operating expenses is consistent with the increase in revenues in the Marcellus region. The margin for these assets is strong as a result of lower operating expenses than in many other regions of the United States. These lower operating expenses are primarily due to high reservoir pressures that reduce the need for compression in the transportation of commodities. We expect our margin in the Marcellus Shale to remain strong; however, we could experience a slight decrease in our margin over time as the need for additional compression increases. The following table summarizes the results of the Appalachia Midstream assets (net to our interest) for the Current Period and Prior Period:

	Six Months Ended June 30, 2014		Six Months Ended June 30, 2013
Revenues ($ in thousands)	$	137,025	$	104,283
Throughput (Bcf)		215.0		165.4
Operating expenses ($ in thousands)	$	20,320	$	14,909
Expenses ($ per Mcf)		0.09		0.09

Niobrara Shale

Revenues. Our Current Period revenues in the Niobrara totaled $12.1 million compared to $4.7 million in the Prior Period, an increase of $7.4 million. The increase in throughput resulted primarily from a $7.4 million increase in revenue offset by a fee redetermination decrease effective January 1, 2014. 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 Period, operating expenses totaled $5.3 million, or $0.60 per Mcf compared to $3.5 million, or $1.01 per Mcf during the Prior Period. Operating expenses are expected to increase throughout 2014 as construction activity increases and we prepare to provide additional gathering and processing services in this region in future periods. The most significant operating expenses in this region are compression costs and compensation.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $2.9 million compared to $1.9 million during the Prior Period. The increase was due to capital expenditures made in this region during 2014 and 2013.

Utica Shale

In the Utica Shale region, we own 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 four wholly-owned gas gathering 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 Period revenues in the Utica totaled $58.5 million compared to $12.7 million in the Prior Period, an increase of $45.8 million. The growth is primarily the result of increased throughput due to increased drilling and compression activity which resulted in a $44.0 million increase in revenue.

Operating Expenses. For the Current Period, operating expenses totaled $20.2 million, or $0.27 per Mcf compared to $4.8 million, or $0.28 per Mcf during the Prior Period. The increase in operating expenses is primarily a result of the increase in operating activity in the Utica Shale region.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $9.4 million compared to $3.5 million during the Prior Period. The increase was due to capital expenditures made in this region during 2014 and 2013.

Income from unconsolidated affiliates. For the Current Period and the Prior Period, income (loss) from unconsolidated affiliates was $5.1 million and $(1.1) million, respectively.

Mid-Continent

Revenues. For the Current Period, Mid-Continent revenues totaled $103.9 million compared to $85.7 million in the Prior Period, an increase of $18.2 million, or 21.2 percent. This increase was caused primarily by a 2.5 percent annual rate increase and a 15 percent increase in fees as a result of rate redetermination, both effective January 1, 2014, offset by a 3.2 decrease in throughput.

Operating Expenses. For the Current Period, operating expenses were $37.4 million, or $0.37 per Mcf compared to $35.2 million, or $0.33 per Mcf during the Prior Period. The increase occurred across all operating costs in this region as we continue to experience increased drilling activity in this liquids-rich region by our producer customers.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $21.4 million compared to $16.8 million during the Prior Period. The increase was due to capital expenditures made in this region during 2014 and 2013.

Income from unconsolidated affiliates. We own a 33.33 percent equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC. For the Current Period and the Prior Period, income from unconsolidated affiliates was $4.6 million and $0.1 million, respectively.

Corporate

Operating Expenses. For the Current Period, operating expenses were $24.3 million compared to $21.7 million during the Prior Period. The increase in operating expenses was due to an increase in compensation of $5.1 million from additional technical resources to support our growth and a decrease in ad valorem taxes due to 2014 reassessments.

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $16.5 million compared to $6.1 million during the Prior Period. The increase in depreciation expense is a result of capital expenditures to back office infrastructure made in 2014 and 2013.

General and Administrative Expense. During the Current Period, general and administrative expenses were $71.4 million compared to $48.8 million during the Prior Period. This increase is primarily attributable to an increase in contract labor of $3.2 million and compensation of $14.6 million, which was primarily a result of increased equity compensation due to an increase in our unit price.

Interest Expense. Interest expense was $81.5 million for the Current Period compared to $54.8 million for the Prior Period. These amounts were net of $19.9 million of capitalized interest during both the Current Period and the Prior Period. The increase is related to interest expense on the 2021 Notes and 2024 Notes issued in August 2013 and March 2014, respectively. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

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. See Risk Factors in our annual report on Form 10-K for the year ended December 31, 2013, as amended.

Working Capital (Deficit). Working capital is defined as the amount by which current assets exceed current liabilities, is an indication of liquidity and the potential need for short-term funding. As of June 30, 2014, we had a working capital deficit of $92.9 million and as of December 31, 2013, we had a working capital deficit of $48.5 million.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the six months ended June 30, 2014 and June 30, 2013, were as follows:

	Six Months Ended June 30,
	2014			2013
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	462,761		$	217,580
Investing activities	$	(886,462	)	$	(777,608	)
Financing activities	$	443,147		$	513,057

Operating Activities. Net cash provided by operating activities was $462.8 million for the Current Period compared to $217.6 million during the Prior Period. 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. The increase was primarily attributable to distributions of earnings received from our unconsolidated affiliates and the timing impacts on our working capital accounts. Please read “Results of Operations” above in this Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Investing Activities. Net cash used in investing activities for the Current Period increased $108.9 million compared to the Prior Period. Approximately $886.5 million was used in investing activities during 2014. This amount included approximately $521.2 million in additions to property, plant and equipment, $159.2 million in the purchase of compression assets and $220.4 million in additions to our investments in unconsolidated affiliates.

Financing Activities. Net cash provided by financing activities decreased $69.9 million for the Current Period as compared to the Prior Period. This decrease was primarily attributable to an increase in payments on long-term borrowings offset by the issuance of senior notes during 2014.

Sources of Liquidity

At June 30, 2014, our sources of liquidity included:

·	cash on hand;

·	cash generated from operations;

·	borrowings 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.

Revolving Credit Facility

On May 13, 2013, we amended and restated our existing senior secured revolving credit facility. The amended and restated revolving credit facility matures in May 2018 and includes aggregate revolving commitments of $1.75 billion, including a sub-limit of $100.0 million for same-day swing line advances and a sub-limit of $200.0 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 $2.0 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 June 30, 2014, we had approximately $150.0 million of borrowings outstanding under our revolving credit facility. As of December 31, 2013, we had approximately $343.5 million of borrowings outstanding under our 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 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 0.50 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 1.50 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 0.375 percent per annum while we are subject to the leverage-based pricing grid, according to our leverage ratio and (b) 0.15 percent to 0.30 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 or 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 $50 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 June 30, 2014 and December 31, 2013.

Senior Notes

On March 7, 2014, we and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a public offering of $750 million in aggregate principal amount of 4.875 percent senior notes due 2024 (the “2024 Notes”). We used a portion of the net proceeds to repay borrowings outstanding under our revolving credit facility, including amounts incurred to fund the purchase price of and certain expenses related to our purchase of compression assets from MidCon, and for general partnership purposes, including funding working capital and our capital expenditure program. Debt issuance costs of $8.8 million are being amortized over the life of the 2024 Notes.

On August 14, 2013, we and ACMP Finance Corp. issued $400 million in aggregate principal amount of additional 5.875 percent senior notes due 2021 (the “Additional Notes”). The Additional Notes are additional to the $350 million of 2021 Notes initially issued on April 19, 2011 and are fully fungible with, rank equally with and form a single series with the 2021 Notes. The Additional Notes were issued at a price of 101.5 percent of the principal amount plus accrued interest from April 15, 2013, resulting in net proceeds of $400.8 million, which was used for general partnership purposes, including funding working capital, repayment of indebtedness and funding our capital expenditure program. Debt issuance costs of $5.8 million are being amortized over the life of the Additional Notes.

On December 19, 2012, we and ACMP Finance Corp. 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.

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 2024 Notes will mature on March 15, 2024, and interest is payable on March 15 and September 15 of each year. We have the option to redeem all or a portion of the 2024 Notes at any time on or after March 15, 2019, at the redemption price specified in the indenture relating to the 2024 Notes, plus accrued and unpaid interest. We may also redeem the 2024 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 March 15, 2019. In addition, we may redeem up to 35 percent of the 2024 Notes prior to March 15, 2017 under certain circumstances with the net cash proceeds from certain equity offerings.

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 indentures governing the 2024 Notes, the 2023 Notes, the 2022 Notes and the 2021 Notes 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 subsidiary, Access MLP Operating, L.L.C., our direct 100 percent owned subsidiary. Access MLP Operating, L.L.C., Access Midstream Operating, L.L.C. and each of our other subsidiaries is a guarantor, other than Cardinal Gas Services, L.L.C., Jackalope Gas Gathering Services, L.L.C. and 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 direct or indirect 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 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 Issuances

On August 2, 2013, we entered into an Equity Distribution Agreement (“ATM”) under which it may offer and sell common units, in amounts, at prices and on terms to be determined by market conditions and other factors, having an aggregate market value of up to $300 million. We are under no obligation to issue equity under the ATM. During the three-month period ended June 30, 2014, we sold an aggregate of 772,819 common units under the ATM for net proceeds of approximately $44.6 million, net of approximately $0.4 million in commissions, plus an approximate $0.9 million capital contribution from our general partner to maintain its two percent general partner interest. During the six-month period ended June 30, 2014, we sold an aggregate of 909,219 common units under the ATM for net proceeds of approximately $52.2 million, net of approximately $0.5 million in commissions, plus an approximate $1.0 million capital contribution from our general partner to maintain its two percent general partner interest. We used the proceeds for general partnership purposes.

On April 2, 2013, we 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. We received offering proceeds (net of underwriting discounts and commissions) of $399.8 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 our general partner to maintain its two percent general partner interest. The proceeds were used for general partnership purposes, including repayment of amounts outstanding under our revolving credit facility.

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, compression and processing throughput from current levels and reduce costs or increase revenues.

For the Current Period, growth capital expenditures totaled $574.8 million and maintenance capital expenditures totaled $65.0 million. Current Period capital expenditures included $222.8 million for our 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.

Distributions

Declaration
Date

Record

Date

Distribution
Date

Distribution
Declared

Total Cash
Distribution

2014

($ in thousands)

Second quarter

July 18, 2014

August 7, 2014

August 14, 2014

0.5950

138,469

First quarter

April 24, 2014

May 8, 2014

May 15, 2014

0.5750

129,993

2013

Fourth quarter

January 24, 2014

February 7, 2014

February 14, 2014

0.5550

122,131

Third quarter

October 25, 2013

November 7, 2013

November 14, 2013

0.5350

113,910

Second quarter

July 24, 2013

August 7, 2013

August 14, 2013

0.4850

97,780

First quarter

April 24, 2013

May 8, 2013

May 15, 2013

0.4675

93,358

Off-Balance Sheet Arrangements of Debt or Other Commitments

We have various other commitments which are disclosed in Note 7 (Commitments and Contingencies) and Note 8 (Fair Value Measures) of Note to Condensed Consolidated Financial Statements. We do not believe these commitments will prevent us from meeting our liquidity needs.

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, 2013, as amended.

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 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 or processing facilities;

·	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;

·	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 Exterran Partners, L.P. (“Exterran”) for a significant portion 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, 2013, as amended, and in Part II, “Item 1A. Risk Factors” in this quarterly report on Form 10-Q 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 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 June 30, 2014.

There has been no change in the Partnership’s internal control over financial reporting during the quarter ended June 30, 2014, that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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 risk factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013, as amended, and in Part II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no significant changes or updates to our risk factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2013, as amended, except as follows:

The announcement of the proposed merger with Williams Partners could materially adversely affect our future business and operations or result in a loss of our employees.

In connection with the announcement of the proposed merger with Williams Partners, it is possible that some customers, suppliers and other persons with whom we have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us as a result of the merger, which could negatively impact our revenues, earnings and cash flows, as well as the market prices of our common units, regardless of whether the merger is completed. Similarly, our current and prospective employees may experience uncertainty about their future roles with us following completion of the merger, which may materially adversely affect the ability of us to attract and retain key employees.

The proposed merger with Williams Partners may not be approved by the conflicts committee of each partnership’s board of directors or each partnership’s board of directors, or the terms on which such approval might be granted may differ from the initially proposed terms.

The proposed merger is subject to approval by the conflicts committee of each partnership’s board of directors, as well as each partnership’s board of directors. In connection with obtaining such approvals, the terms of the proposed merger, including the consideration to be paid in the proposed merger, will be subject to negotiation with each partnership’s conflicts committee. Either partnership’s respective conflicts committee or board of directors may not approve the proposed merger or, if such approval is granted, the terms on which the proposed merger is approved may be significantly different than the initially proposed terms. Further, the market prices of our common units and William Partners’ common units could fluctuate significantly following the announcement of a definitive agreement with respect to the proposed merger.

The successful execution of the integration strategy following the consummation of the proposed merger will involve considerable risks and may not be successful.

If the proposed merger is consummated, the success of the proposed merger would depend, in part, on the ability of the combined company to benefit from the combination of our business with the business of Williams Partners. Realizing benefits from the proposed merger would depend in part on the integration of assets, operations, functions and personnel while maintaining adequate focus on the core businesses of the combined company. Any cost savings, economies of scale, enhanced liquidity or other operational efficiencies, as well as revenue enhancement opportunities anticipated from the combination of us and Williams Partners, or other synergies, may not occur.

Williams, through its ownership of Access Midstream Ventures, L.L.C. (“Access Midstream Ventures”), indirectly owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Williams and Access Midstream Ventures, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our common unitholders.

Access Midstream Ventures, which is owned and controlled by Williams, owns and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are also officers and directors of Williams and Access Midstream Ventures. Although our general partner has a contractual duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Access Midstream Ventures. Conflicts of interest will arise between Williams, Access Midstream Ventures and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Williams and/or Access Midstream Ventures over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

•

Neither our partnership agreement nor any other agreement requires Williams or Access Midstream Ventures to pursue a business strategy that favors us. For example, Williams is not a party to any agreement that prohibits it from competing against us in our gas gathering and processing operations and for gathering, processing and acquisition opportunities. It is possible that Williams could preclude us from pursuing opportunities in which Williams has a competitive interest.

•	Our general partner is allowed to take into account the interests of parties other than us, such as Williams or Access Midstream Ventures, in resolving conflicts of interest.

•	Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

•

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner.

•	Our general partner determines which costs incurred by it are reimbursable by us.

•	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

•

Our partnership agreement permits us to classify up to $120 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of its general partner interest or the incentive distribution rights.

•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our general partner intends to limit its liability regarding our contractual and other obligations.

•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80 percent of the common units.

•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Williams may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of July 1, 2014, Williams held an aggregate of approximately 88.9 million common units and approximately 12.7 million Class B units. 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 into a common unit on a one-for-one basis at the option of either us or the holder thereof. Additionally, we have agreed to provide Williams with certain registration rights with respect to its units. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

In connection with public offerings under the our Equity Distribution Agreement during the fourth quarter of 2013 and the first quarter of 2014, our general partner made additional capital contributions to us of $1.0 million on February 14, 2014 and $0.1 million on May 15, 2014, respectively, to maintain its two percent interest in us. 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.

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

10.1

First Amendment to Chesapeake Midstream Long-Term Incentive Plan, dated effective as of July 1, 2014.

8-K

001-34831

10.1

07/02/2014

10.2

Form of Restricted Phantom Unit Award Agreement.

8-K

001-34831

10.1

07/07/2014

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

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:	July 30, 2014	By:	/s/ J. MIKE STICE
			J. Mike Stice
			Chief Executive Officer

Date:	July 30, 2014	By:	/s/ DAVID C. SHIELS
			David C. Shiels
			Chief Financial Officer

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing Date

Filed
Herewith

Furnished
Herewith

10.1

First Amendment to Chesapeake Midstream Long-Term Incentive Plan, dated effective as of July 1, 2014.

8-K

001-34831

10.1

07/02/2014

10.2

Form of Restricted Phantom Unit Award Agreement.

8-K

001-34831

10.1

07/07/2014

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.