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ACMP > SEC Filings for ACMP > Form 10-Q on 30-Jul-2014All Recent SEC Filings

Show all filings for ACCESS MIDSTREAM PARTNERS LP

Form 10-Q for ACCESS MIDSTREAM PARTNERS LP


30-Jul-2014

Quarterly Report


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 . . .

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