UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): December 19, 2012

ACCESS MIDSTREAM PARTNERS, L.P.

(Exact name of Registrant as specified in its Charter)

(405) 935-1500

(Registrant’s telephone number, including area code)

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

Section 1 — Registrant’s Business and Operations

Introductory Note

On December 20, 2012, Access Midstream Partners, L.P. (the “Partnership” or “we”) completed our previously announced acquisition of Chesapeake Midstream Operating, L.L.C. (“CMO”) from Chesapeake Midstream Development, L.L.C. (“CMD”), a Delaware limited liability company and wholly owned subsidiary of Chesapeake Energy Corporation. CMO, together with its subsidiaries, owns certain midstream gas gathering, processing and related assets in the Eagle Ford, Utica, Niobrara, Haynesville and Marcellus basins. We refer to this transaction as the “CMO Acquisition.”

Gas Gathering Agreements

On December 20, 2012, in connection with the closing of the CMO Acquisition, we entered into new gas gathering agreements (the “Gas Gathering Agreements”) with certain subsidiaries of Chesapeake Energy Corporation (such subsidiaries collectively, “Chesapeake”). For the avoidance of doubt, the joint ventures in the Utica region that we acquired in connection with the CMO Acquisition and that are described below did not enter into new gas gathering agreements. Each Gas Gathering Agreement defines the services, fees and obligations of the parties with respect to a particular oil and natural gas geologic formation or producing region of the United States. The terms of each region are:

Eagle Ford:

• Gathering, Compression, Dehydration and Treating Services. We will gather, compress, dehydrate and treat natural gas for Chesapeake within the Eagle Ford region in exchange for a cost-of-service based fee for natural gas gathered and treated on our gathering systems. The cost-of-service components will include 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. Pursuant to the applicable 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 natural gas and oil leases covering lands within an acreage dedication in the Eagle Ford region. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.

• Fee Redetermination. During 2013 and 2014, the Eagle Ford fee is determined by a fee tiering mechanism that calculates the Eagle Ford fee on a monthly basis according to the quantity of gas delivered to us by Chesapeake relative to its scheduled deliveries. Effective on January 1, 2015 and January 1st of each year thereafter for a period of 20 years from July 1, 2012, the Eagle Ford fee will be redetermined based on a cost-of-service calculation that provides a specified pre-income tax rate of return on invested capital.

• Well Connection Requirement. Subject to required notice by Chesapeake, we will have the option to connect new operated wells within our Eagle Ford 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. If the well is delayed for more than one year, then the well pad may be released from Chesapeake’s acreage dedication at Chesapeake’s option.

• 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 Chesapeake’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:

• Gathering, Compression, Dehydration, Processing and Fractionation Services. We will gather, compress and dehydrate natural gas in exchange for a cost-of-service based fee for natural gas gathered on our gathering systems. The cost-of-service components (i) for our 66% operating interest in a joint venture which owns five wet gas gathering systems (the “Cardinal JV”), and (ii) in the area covered by our 100% ownership interest in four dry gas gathering systems (the “Utica Dry”) will include compression expense (in the case of the Utica Dry only), deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We also will process and fractionate natural gas through our 59% non-operating interest in a joint venture that is currently constructing three 200 million cubic feet per day processing plants, a 90,000 barrel per day fractionation facility, approximately 870,000 barrels of NGL storage capacity and other ancillary assets (the “UEO JV”) for a fixed fee that escalates annually within a specified range. The Partnership refers to these fees collectively as the Utica fee.

• Acreage Dedication. Pursuant to the applicable 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 with a surface location within the designated dedicated areas. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to the Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake. The UEO JV has a processing and fractionation dedication with a designated dedication area from Chesapeake and Total E&P USA, Inc. for 600 MMcf/d.

• Fee Redetermination. Beginning on October 1, 2013 for the Cardinal JV and January 1, 2014 for Utica Dry and annually thereafter, for a period of 20.75 years from January 1, 2012 (Cardinal JV) and 15 years from July 1, 2012 (Utica Dry), the gathering fee portion of the Utica fee will be redetermined based on a cost of service calculation that provides a specified pre-income tax rate of return on invested capital.

• Well Connections. In the Cardinal JV, we are generally required to connect new wells within specified timelines subject to penalties for delayed connections in the form of a temporary reduction in the gathering fee for the new well. In Utica Dry, subject to required notice by Chesapeake, we will have the option to connect new operated wells within our dedicated acreage 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. If the well is delayed for more than one year, then the well pad may be released from Chesapeake’s acreage dedication at Chesapeake’s option.

• Processing and Fractionation Performance Standards. We have agreed with Chesapeake to certain performance standards for the UEO JV, including guaranteed in-service dates, minimum facility run-time standards, minimum propane recovery standards, and fuel caps. If the Partnership 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 Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk. In Utica Dry, exceeding the permitted cap does not result in a reimbursement to Chesapeake if we respond in a timely manner with a proposed solution.

Niobrara:

• Gathering, Compression, Dehydration and Processing Services. We will gather, compress, dehydrate and process natural gas within the Niobrara region in exchange for a cost-of-service based fee for natural gas gathered on our gathering systems and for natural gas processed at our proposed processing facility. The cost-of-service components will include 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. Pursuant to our gas gathering and processing 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 with a surface location within the designated dedicated areas. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.

• Fee Redetermination. Effective on January 1, 2014 and January 1st of each year thereafter for a period of 20 years from July 1, 2012, the Niobrara fee will be redetermined based on a cost-of-service calculation that provides a specified pre-income tax rate of return on invested capital.

• Well Connections. Subject to required notice by Chesapeake, we will have the option to connect new operated wells within our Niobrara 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. If the well is delayed for more than one year, then the well pad may be released from the Chesapeake’s acreage dedication at the Chesapeake’s option

• 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 Chesapeake’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:

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

• Acreage Dedication. Pursuant to the applicable 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 Haynesville Shale region acreage dedication. Chesapeake’s dedication of the natural gas produced from the applicable dedicated properties will run with the land in order to bind successors to the Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.

• Minimum Volume Commitments. Pursuant to the applicable 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, Chesapeake will be obligated to pay us the difference between the minimum volume commitment and the volume of gas delivered from Chesapeake’s wells.

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

• Well Connection Requirement. We will have certain connection obligations for new operated wells of Chesapeake in the 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 volume 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:

• Gathering, Compression and Dehydration Services. We will gather, compress and dehydrate natural gas for Chesapeake within the Marcellus region in exchange for a cost-of-service based fee for natural gas gathered on our gathering systems. The cost-of-service components include 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 Marcellus fee.

• Acreage Dedication. Pursuant to the applicable 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 natural gas and oil leases covering lands within an acreage dedication in the Marcellus region. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.

• Fee Redetermination. Effective on January 1, 2014 and January 1st of each year thereafter for a period of 15 years from July 1, 2012, the Marcellus fee will be redetermined based on a cost-of-service calculation that provides a specified pre-income tax rate of return on invested capital.

• Well Connection Requirement. Subject to required notice by Chesapeake, we will have the option to connect new operated wells within our Marcellus 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. If the well is delayed for more than one year, then the well pad may be released from Chesapeake’s acreage dedication at Chesapeake’s option.

• Fuel and Lost and Unaccounted For Gas. Production from existing gas gathering systems are not subject to a cap on fuel and lost and unaccounted for gas. For new Marcellus systems, we have agreed with Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’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.

Operating Agreement

On December 20, 2012, Access MLP Operating, LLC, (the “OLLC”), our operating subsidiary, entered into an Operating Agreement with Mid-America Midstream Gas Services, LLC, a subsidiary of Chesapeake (“Mid-America”) whereby the OLLC will provide management and operational activities for Mid-America with respect to certain gas gathering systems in return for a management fee.

Termination Agreement

On December 20, 2012, we entered into a Termination Agreement with a number of parties including CMD, whereby we terminated certain provisions of the omnibus agreement entered into between us and affiliates of Chesapeake at the time of our initial public offering, including our right of first offer with respect to (i) opportunities to develop or invest in midstream energy projects within five miles of our acreage dedications in the Barnett Shale and Mid-Continent regions, (ii) opportunities to succeed third parties in expiring midstream energy service contracts within the acreage dedications and within five miles thereof in the Barnett Shale and Mid-Continent regions and (iii) opportunities with respect to future midstream divestitures outside of the acreage dedications. Chesapeake also entered into a guaranty on December 20, 2012 with respect to CMD’s and its affiliates’ respective obligations under the transaction documents, and the Partnership has agreed to guaranty CMO and its subsidiaries’ obligations under the Gas Gathering Agreements.

The foregoing description is qualified in its entirety by reference to the full text of the Termination Agreement, which is filed as Exhibit 10.3 to this Current Report on Form 8-K and is incorporated in this Item 1.01 by reference.

Non-Solicitation Agreement

In connection with the CMO Acquisition, on December 20, 2012, we and CMD, Chesapeake Operating, Inc., Chesapeake Energy Marketing, Inc. and Chesapeake Energy Corporation entered into a Non-Solicitation Agreement (the “Non-Solicitation Agreement”) whereby for two years neither we nor our affiliates will actively solicit, from working interest owners in Chesapeake operated wells located in our dedication areas, the purchase of gas produced from such wells.

The foregoing description is qualified in its entirety by reference to the full text of the Non-Solicitation Agreement, which is filed as Exhibit 10.1 to this Current Report on Form 8-K and is incorporated in this Item 1.01 by reference.

Transition Services Agreement Amendment

On December 20, 2012 we entered into a Second Letter Amendment Agreement (the “Transition Services Agreement Amendment”) that amends that certain Letter Agreement, dated as of June 15, 2012, by and among Chesapeake, Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., us, Access Midstream Partners GP, L.L.C., a Delaware limited liability company and the general partner of the Partnership (the “General Partner”), the OLLC, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P. (as amended by that certain Letter Amendment Agreement, dated June 29, 2012, the “Letter Agreement”). This Transition Services Agreement Amendment extends the term of the Letter Agreement and provides for the extension of certain information technology services for the Partnership and its affiliates.

The foregoing description is qualified in its entirety by reference to the full text of the Transition Services Agreement Amendment, which is filed as Exhibit 10.2 to this Current Report on Form 8-K and is incorporated in this Item 1.01 by reference.

Amended and Restated Registration Rights Agreement

Pursuant to a Subscription Agreement dated December 11, 2012 (the “Subscription Agreement”), by and among us, the General Partner, GIP II Hawk Holdings Partnership, L.P. (“Hawk Holdings”) and The Williams Companies, Inc. (“Williams”), and in connection with the closing of the issuance of Convertible Class B units (the “Class B Units”) and Subordinated Class C units (the “Class C Units”) pursuant to the Subscription Agreement, on December 20, 2012, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., GIP II Eagle Holdings Partnership, L.P. (“Eagle Holdings”), Hawk Holdings, Williams (together with Eagle Holdings and Hawk Holdings, the “Registration Rights Parties”) and we entered into an Amended and Restated Registration Rights Agreement (the “Registration Rights Agreement”).

The Registration Rights Agreement grants to the Registration Rights Parties the right to cause us, at our own expense, to use our best efforts to register our common units (the “Common Units”), subordinated units, Class B Units and Class C Units held by the Registration Rights Parties for public resale, subject to certain limitations. The exercise of this right is limited to one request for registration on Form S-1 in any 12-month period and two requests for registration on Form S-3 in any twelve month period. Williams is not eligible to participate in any such registered resale of any units until such time as the other Registration Rights Parties own a number of units on an as-converted Common Unit basis equal to or less than the number of units on such basis held by Williams as of the date of the Registration Rights Agreement.

In the event we register any of our Common Units, the Registration Rights Parties also have the right to require us to use our best efforts to include Common Units held by them on any such registration statement, subject to certain limitations. The Registration Rights Agreement also provides for us to indemnify the applicable Registration Rights Parties and their affiliates in connection with the registration of Common Units.

The foregoing description is qualified in its entirety by reference to the full text of the Registration Rights Agreement, which is filed as Exhibit 4.3 to this Current Report on Form 8-K and is incorporated in this Item 1.01 by reference.

Item 2.01 Completion of Acquisition of Assets

On December 20, 2012, we completed our previously announced acquisition of CMO from CMD.

The aggregate consideration we paid to CMD was approximately $2.16 billion, subject to post-closing adjustments. The purchase price was funded with proceeds from the issuance of senior notes, the issuance of common units and the proceeds from the sale of our Class B Units and Class C Units described in Item 3.02 of this Current Report on Form 8-K.

On December 20, 2012, we sold (i) 5,929,025 Class B Units to each of Williams and Hawk Holdings and (ii) 5,599,634 Class C Units to each of Williams and Hawk Holdings, in each case pursuant to that certain Subscription Agreement described and included in our Current Report on Form 8-K filed December 12, 2012. We received aggregate proceeds of approximately $700 million in exchange for the sale of the Class B Units and the Class C Units, inclusive of the capital contribution made by the General Partner to maintain its 2% interest in the Partnership. The Class B Units and Class C Units were issued in reliance upon an exemption from the registration requirements under the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof.

To the extent required by Item 3.02 of Form 8-K, the information contained or incorporated in Items 1.01 and 5.03 of this Form 8-K relating to the issuance of our Class B Units and Class C Units is incorporated by reference in this Item 3.02. The description of our Class B Units, Class C Units and the Subscription Agreement can be found in our Current Report on Form 8-K filed December 12, 2012 and is incorporated in this Item 3.02 by reference.

The foregoing discussion is qualified in its entirety by reference to the full text of the Partnership Agreement Amendment (as defined below), which provides the terms and provisions of the Class B Units and Class C Units and is filed as Exhibit 3.1 to this Current Report on Form 8-K and incorporated into this Item 3.02 by reference.

Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P.

On December 20, 2012, in connection with the issuance of the Class B units and Class C Units, the General Partner executed an amendment (the “Amendment”) to the First Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”). The Amendment provides for the establishment of the Class B Units and the Class C Units and amends and restates certain sections of the Partnership Agreement regarding the allocation of income, gain, loss and deductions and the distribution of available cash from operating surplus. A description of the Partnership Agreement is contained in the section entitled “The Partnership Agreement” of our Registration Statement filed on Form S-3 on December 12, 2012 and is incorporated herein by reference.

The foregoing description and the description contained in our Registration Statement filed on Form S-3 on December 12, 2012 is qualified in its entirety by reference to the full text of the Partnership Agreement Amendment, which is filed as Exhibit 3.1 to this Current Report on Form 8-K and is incorporated into this Item 5.03 by reference.

Item 9.01 Financial Statements and Exhibits

SIGNATURE

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.

Dated: December 26, 2012

INDEX TO EXHIBITS