FILED PURSUANT TO RULE 424(b)(3)
REGISTRATION NO. 333-192852

American Energy Capital Partners, LP

Supplement No. 6 dated December 24, 2014 to the Prospectus dated May 8, 2014

The Prospectus for American Energy Capital Partners, LP consists of this Supplement No.6, the Prospectus dated May 8, 2014, Supplement No. 1 dated June 18, 2014, Supplement No. 2 dated July 21, 2014, Supplement No. 3 dated August 14, 2014, Supplement No. 4 dated November 14, 2014 and Supplement No. 5 dated November 26, 2014. This Supplement No. 6 will be delivered with the Prospectus, Supplement No. 1, Supplement No. 2, Supplement No. 3, Supplement No. 4 and Supplement No. 5. The primary purposes of this Supplement No. 6 are to:

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update the status of the offering;

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update the suitability standards for Arkansas and Ohio investors;

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update disclosure in the Prospectus; and

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provide a new Subscription Agreement as Exhibit B-1, which replaces in its entirety the Subscription Agreement included as Exhibit B in the Prospectus, and a new multi-offering subscription agreement as Exhibit B-2 to this Supplement No. 6.

Status of the Offering. The Partnership is currently offering common units. As of the close of business on November 30, 2014, the Partnership had received subscriptions of $4,494,385 for 237,954.544 common units from 74 investors. The Partnership’s escrow account was terminated and the Partnership held its first closing on June 16, 2014. As of the close of business on November 30, 2014, the Partnership had 99,762,045.456 common units remaining available for sale. On September 19, 2014, the Partnership declared distributions payable to unitholders of record each day during the applicable period at a rate equal to $0.00328767123 per day. The distributions will be deemed to accrue with respect to each unit commencing on the escrow break date on which such unit was issued and will be payable by the 5th day following each month end to unitholders of record at the close of business each day during the prior month. The Partnership may reduce the amount of distributions paid or suspend distribution payments at any time.

As of the date hereof, the Partnership owns no operating property and has no historical operating cash flows. Additionally, the Partnership’s organizational documents permit it to pay distributions from any source, and it may use sources other than operating cash flows to fund distributions, including unlimited amounts of proceeds from this offering, which may reduce the amount of capital the Partnership ultimately invests in properties or other permitted investments, and negatively impact the value of your investment.

Suitability Standards. The suitability requirements set forth under the heading “Suitability Standards — General Suitability Requirements for Purchasers of Common Units Representing Limited Partners Interests” beginning on page 6 of the Prospectus are hereby revised to include the standards below:

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Arkansas Investors. If you are a resident of Arkansas, you must have either a minimum net worth of $250,000 and had during the last tax year, or estimate that you will have during the current tax year, gross income of $100,000, or, in the alternative, a minimum net worth of $500,000. In no event should an investment in the Partnership exceed more than 10% of your net worth. In all cases, net worth shall be determined exclusive of homes, home furnishings and automobiles.

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Ohio Investors. It shall be unsuitable for an Ohio investor’s aggregate investment in interests of the Partnership, Affiliates of the Partnership and in other non-traded oil and gas programs to exceed ten percent (10%) of his or her liquid net worth. ‘Liquid net worth’ shall be defined as that portion of net worth (total assets exclusive of home, home furnishings, and automobiles minus total liabilities) that is comprised of cash, cash equivalents, and readily marketable securities.

Distributions. The carryover paragraph on the top of page 18 of the Prospectus under the heading “Prospectus Summary — Distributions” is hereby revised to read in full as follows:

All of the distributions you receive from us will be considered a return of capital until you have received 100% of your investment in our Units. In this regard, there is no limitation on the amount of distributions that can be funded from offering proceeds or financing proceeds except that funds will not be advanced or

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borrowed by us for the purpose of making distributions to you and the other Unitholders if the amount advanced or borrowed would exceed our accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. If a distribution is not being funded entirely from Partnership revenues, investors residing in Maryland, North Dakota, Ohio and Oklahoma will be provided disclosure that provides the percentage and dollar amount that is being funded from Partnership revenues and the percentage and dollar amount that is being funded by offering proceeds or borrowings.

Conflicts of Interest — Conflicts with the Manager — Conflicts Involving Other Activities of the Manager and Its Affiliates. The following is hereby added as the first full paragraph on page 68 of the prospectus:

Affiliates of the Manager have agreed to provide other entities the right to participate in opportunities affiliates of the Manager develop in the Southern Wolfcamp play area of the Central Permian Basin in West Texas, the Utica Shale and liquids rich portion of the Marcellus Shale areas in Ohio, Pennsylvania and West Virginia and the Woodford Shale area of Central Northern Oklahoma, opportunities to acquire or develop midstream assets in the continental United States and opportunities involving properties in the continental United States that consist exclusively of properties that will not be operated by the Manager or any of its affiliates. The Management Agreement provides that the Manager is not required to offer us opportunities to acquire any such properties, however the Partnership is not prohibited from acquiring properties that it identifies in any of those areas, or to acquire or develop midstream assets in the continental United States or to acquire oil and gas properties that are exclusively properties that will not be operated by the Manager or any of its affiliates. As a result, if the Partnership seeks to acquire properties that it identifies in any of those areas that will not be operated by the Manager or any of its affiliates, then the Manager will not manage such properties and we may compete with an entity that is managed by an affiliate of the Manager. In addition, the Management Agreement provides that the Manager is not required to refer to us any properties that Aubrey K. McClendon or any entity of which he is an affiliate has an interest in or right to acquire pursuant to the Chesapeake Energy Corporation Founders Well Participation Program. Further, affiliates of the Manager have agreed to perform management services similar to those under the Management Agreement with us on behalf of an oil and gas program with similar investment objectives to ours that may compete with us.

Market Overview. We are focused on helping our Unitholders take advantage of opportunistic producing and drilling property acquisitions in the current oil and gas market. We believe this opportunity is the result of recent improvements in hydraulic fracturing and horizontal drilling techniques. Although the acquisition of oil and gas properties is highly competitive, we believe our Manager’s experience and expertise will be of benefit to us. Our investment goals are as follows:

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to acquire producing and non-producing oil and gas properties with development potential and to enhance the value of our properties through drilling and other development activities;

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to make distributions to the holders of our Units, which we intend to be at a targeted distribution rate of 6% per annum, non-compounded, on the $20.00 original purchase price per Unit, or a targeted annual distribution rate of $1.20 per Unit, payable monthly commencing with a distribution for the fourth whole month following the initial closing date;

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beginning five to seven years after the initial closing date, to engage in a liquidity transaction in which we will sell our properties and distribute the net sales proceeds to our partners or list our common units on a national securities exchange; and

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to enable our Unitholders to invest in oil and gas properties in a tax efficient manner.

Although we have not yet identified or selected any prospective properties and, accordingly, this is a “blind pool” offering, we anticipate that we will routinely use hydraulic fracturing techniques in drilling and completing most of the development wells we drill, depending primarily on the area where the wells are situated and the targeted geological formation, which we further anticipate may include tight oil or gas formations.

Our Manager’s management team is led by seasoned professionals who have raised over $10 billion for the acquisition and development of oil and natural gas assets. Also, our Manager’s management team has

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previous experience in leading Chesapeake Energy Corporation, which was the most active driller in the US at one time and was the US’s largest gross producer of natural gas and a top 10 domestic producer of oil and natural gas liquids. Our Manager’s chief executive officer has more than 30 years of oil and natural gas experience. We believe a number of factors differentiate us from other oil and gas programs, including our intent to reinvest in additional oil and gas properties during our term, conduct development activities on the properties we acquire, our lack of legacy issues, our opportunistic buy and sell strategy, our management team and the Manager’s management team.

Oil and Natural Gas Overview

The growth in US oil and natural gas production related to the improved economics of shale extraction techniques has made the US the #1 natural gas producer in the world. Projections are that the US will be #1 in oil by 2020, surpassing Russia and Saudi Arabia. Based on information provided by the Energy information Administration (EIA), US oil production is expected to rise to over 9 million barrels per day in 2015. In natural gas, US production is forecast to rise to 25 trillion cubic feet by 2015.

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Source: U.S. Energy Information Administration (EIA) estimates.

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Also, the EIA projects that US natural gas production will grow by an average of 1.6% per year from 2012 to 2040, which is more than double the annual growth rate in total US natural gas consumption projected over that period. This projected growth is not only expected to permit US natural gas production to satisfy US demand but also permit the US to become a net exporter of natural gas beginning in 2017.

U.S. Dry Natural Gas Production
(trillion cubic feet)

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Source: EIA Annual Energy Outlook Market Trends

EIA AEO 2014 Forecast of U.S. Natural Gas Production,
2014 ~ 2040 (trillion cubic feet)

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Source: EIA Annual Energy Outlook 2014

According to the EIA, US natural gas consumption growth is expected to be driven by increased use by power plants, as well as industrial and transportation use. US manufacturing output by natural gas-intensive industries is projected by the EIA to expand significantly through 2025 as the availability of abundant supplies of relatively low priced natural gas promotes renewed growth of US manufacturing. Furthermore, when burned natural gas produces about 45% less carbon dioxide than coal, according to the EIA, which may contribute to increased demand for natural gas in the future. Additionally, US exports of natural gas are expected to commence in late 2015, with EIA projections indicating more than 2 tcf will be exported annually by 2020.

Notwithstanding, increased production of oil and gas, including enhanced technology such as hydraulic fracturing and horizontal drilling, may result in a downward trend for oil and gas prices, which could reduce our cash flow and the amount we can distribute to our investors or use to acquire additional properties.

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Of the abundant energy sources, natural gas has 44% less CO2eq/kWh (equivalents per kilowatt hour) than oil and 53% less than coal.

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Note: Data is the 50^th percentile for each technology from a meta study of more than 50 papers
Data source: IPCC Special Report on Renewable Energy Sources and Climate Change Mitigation

Conventional vs. Unconventional Shale

We anticipate that we will drill wells in unconventional formations which are fine-grained, organic-rich, sedimentary rocks (usually shales and similar rocks) and are pervasive throughout a large area and are not significantly affected by pressure exerted by water in the ground. Although unconventional formations may be as porous as other sedimentary reservoir rocks, their extremely small pore sizes and lack of permeability make them relatively resistant to hydrocarbon flow. The lack of permeability means that the oil and gas typically remain in the source rock unless natural or artificial fractures occur.

Characteristics of Conventional Play

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Oil and gas trapped in Structural and stratigraphic traps

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Often have fluid contacts (water/oil/gas)

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Inventory of large undrilled structures limited

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Often high variability in reservoir

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Characteristics of unconventional Play

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Oil/gas generated, stored and trapped in the Shale

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Generally subtle fluid contacts

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Often consistent rock quality

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Generally expansive productive fairways

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High repeatability

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Horizontal Drilling vs. Vertical Drilling

Depending primarily on the area where the wells are situated and the targeted geological formation, we may drill both vertical wells and horizontal wells. Horizontal drilling is a drilling process in which the well is turned horizontally at depth. It is normally used to extract energy from a source that itself runs horizontally, such as a layer of shale rock. Since the horizontal section of a well is at great depth, the well must include a

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vertical part as well. Generally speaking, drilling a horizontal well is a more complicated and expensive process than drilling a conventional vertical well. When drilling a horizontal well, the driller must first determine the depth of the energy-rich layer. This is done by drilling a conventional vertical well, and analyzing the rock fragments that appear at the surface from each depth. Once the depth of the shale is determined, the driller withdraws the drilling assembly, and then inserts a special bit assembly into the ground that allows the driller to keep track of its vertical and horizontal location. The driller calculates an appropriate spot above the shale in which the drill must start to turn horizontally. That spot is known as the “kickoff point.” From there, the drill bit is progressively angled so that it creates a borehole that curves horizontally. Horizontal drilling has been a common practice since the 1980s when improved equipment, motors, and other technology were developed, and in recent years, it has been shown in many cases to be more productive than vertical drilling in terms of reserves per well drilled. Accordingly, a corresponding increase in the use of horizontal drilling has occurred. However, the reserves found in horizontal wells, if any, may not be offset by the increased costs of drilling horizontal wells.

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Horizontal Drilling vs. Conventional Drilling

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As shown in the charts below, the benefits of the technological advancements of horizontal drilling and hydraulic fracturing include improved drilling outcomes and higher per well recoveries. Twenty-five years ago, more than 30% of the wells drilled onshore in the US were uneconomic compared to less than 10% today. In terms of per well recoveries, twenty-five years ago, each productive well developed an average of approximately 100,000 barrels of oil equivalent in reserves. Today, each productive well is developing over 100,000 barrels of oil equivalent in reserves. Notwithstanding, oil and natural gas drilling operations are inherently speculative and

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subject to risk, including the risk that the Partnership may drill wells that are productive, but do not produce enough revenue to return the investment made, and from time to time dry holes.

Improved Drilling Outcomes

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Source: U.S. Energy Information Administration and Baker Hughes. EIA information available through 2010 for drilling outcomes and 2012 for incremental reserves. Total wells drilled and estimates for drilling outcomes provided by Baker Hughes and historical AECP analysis, respectively, in 2011 and 2012.

Improved Drilling Outcomes

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Market Trends

We believe horizontal drilling and hydraulic fracturing allow oil and gas investments in the on-shore US market to generate more stable cash flow and in some cases capital appreciation at reduced risks when compared to earlier drilling approaches. Rather than drilling for oil or natural gas in an unproven area that has no concrete historic production records and has been unexplored as a site for potential oil and gas output, or “wildcat drilling,” we intend to focus on more certain developmental drilling where the existence of hydrocarbons is already known. The EIA has determined that the industry is drilling one-third to one-fourth as many uneconomic wells, or dry holes, as it did 25 years ago and each productive well is developing more reserves that it did 25 years ago, clearly benefiting from such new technologies. Notwithstanding our intended focus on properties with development drilling opportunities, the increased costs associated with the new technology for horizontal drilling and hydraulic fracking in shale formations creates a risk that the partnership may not receive a return of the amount of its investment in the particular well. We will focus on producing and non-producing oil and gas properties. We expect the non-producing properties will require additional drilling to generate cash flow and increase reserves. Also, we anticipate that the combination of proved developed producing (“PDP”) and proved-undeveloped drilling locations (“PUD”) will result in increased value over time as reserves rise. We believe this combination of activities will result in our drilling fewer uneconomic wells than the industry average. Notwithstanding, there is a risk that we will drill dry holes or wells that are productive, but do not produce enough revenue to return the investment made.

The Manager’s Industry Experience

Access to Data

Aubrey K. McClendon, the Chief Executive Officer of the Manager, has over 30 years of experience in the oil and gas industry. Also, Mr. McClendon formed the Manager and its affiliate, American Energy Partners, LP, or “AELP,” in February 2013. Through Mr. McClendon’s participation in the Chesapeake Energy Corporation’s, or Chesapeake, Founders Well Participation Program, Mr. McClendon has access to a significant amount of information with many of the active domestic productive and non-productive plays in the US. We use the term “play” to describe a set of known or postulated oil and gas accumulations sharing similar geographic and temporal properties, such as source rock, migration pathway, timing, trapping mechanism and hydrocarbon type. While we expect to benefit from this extensive access to information, none of Mr. McClendon, the Manager or their affiliates will have an obligation to offer to sell to us any interest it may own in any particular prospect or property, which could result in a conflict of interest with us.

Operational Track Record

Oil and gas investments and operations require a specialized skill set. The Manager’s executive management team includes many of the same people responsible for founding and building Chesapeake, which grew to become the #2 natural gas producer and the #11 oil and natural gas liquids producer in the US. Because of the different fees, structure and capitalization, however, our activities may not create the same results. The Manager’s senior management team has:

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helped build an organization at Chesapeake that once operated 175 drilling rigs;

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supervised more than 12,000 well completions;

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managed operations teams with more than 2,000 employees, 23,000 operated wells and 40,000 total properties;

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led the initial development of several major domestic oil and gas plays;

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participated in approximately 200 acquisitions from 1990 to 2012 greater than $10 million with a combined value of approximately $28 billion; and

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acquired non-producing acreage, producing oil and gas properties, minerals and companies.

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Capital Management Experience

Since its inception in 2013, AELP and its affiliates have raised more than $14 billion of institutional capital and started five E&P companies with over 600,000 net acres and more than 60,000 barrels of oil equivalent per day of production, one mineral company, one midstream company and two non-traded limited partnerships. We expect to benefit from the Manager’s access to property acquisition opportunities as it participates in the AELP property review and evaluation process.

Investment Considerations

We believe a number of factors differentiate us from other oil and gas programs, including:

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Opportunistic Buy and Sell Strategy: We intend to acquire high-quality producing and non-producing properties with a potential for development appreciation, increase the cash flow of the properties, and sell the properties, typically within five to seven years after acquisition through asset sales, a company sale, or list our Units on a national securities exchange.

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No Legacy Issues: Unlike many existing oil and gas companies, we own no properties and we are not burdened by problems with previously acquired properties. In addition, our Unitholders are not being asked to invest money into previously acquired properties that are not performing as originally expected.

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Experienced Management Team: The executives of our General Partner have extensive experience as sponsors of alternative investments and the executives of our Manager have extensive experience in the oil and natural gas industry.

Notwithstanding the similar names, however, an investment in us is not an investment in the Manager, AELP or any of their affiliated companies and the Manager’s affiliation with these different entities creates a conflict of interest as to whether those entities or we are allocated a particular prospect by the Manager.

Management — Executive Management Team. The biographical information for Aubrey K. McClendon on page 102 of the Prospectus is hereby replaced in its entirety as follows:

Aubrey K. McClendon has served as chief executive officer of the Manager since its formation in December 2013. Mr. McClendon is a well-known entrepreneur and manager with over 30 years of experience in the oil and natural gas industry. Previously, he served as chairman and chief executive officer of Chesapeake Energy Corporation, or Chesapeake. By press release dated January 29, 2013, Chesapeake announced that Aubrey K. McClendon, its co-founder, chief executive officer and president, had agreed to retire from Chesapeake on the earlier of April 1, 2013, or when his successor was appointed. Mr. McClendon served as Chesapeake’s chief executive officer since its inception in 1989 and served as chairman of the board from its founding until 2012. Effective April 1, 2013, Mr. McClendon retired as an executive officer of, and is no longer affiliated with, Chesapeake. Under his leadership, Chesapeake grew from a $50,000 startup in 1989 to the nation’s largest gross producer of natural gas and a top 10 domestic producer of oil and natural gas liquids with an enterprise value of approximately $30 billion with approximately 10,000 employees at the time of his departure. In addition, during his tenure Chesapeake became the most active driller of new wells in the U.S. and once operated approximately 175 drilling rigs, the largest driller of horizontal shale wells, the second largest natural gas producer and the 11th largest natural gas liquids and oil producer in the United States and one of the largest U.S. leasehold and 3D seismic owners. During his leadership, Chesapeake discovered the Haynesville Shale, Utica Shale, Powder River Niobrara Shale, Tonkawa Sand and Mississippi Lime unconventional plays, and led the initial development of major domestic oil and natural gas plays in Marcellus Shale in Pennsylvania and West Virginia, the Utica Shale in Ohio, the Haynesville Shale in Louisiana, the Fayetteville Shale in Arkansas, the Eagle Ford Shale in Texas, and the Barnett Shale in Texas. Also, through Chesapeake’s drilling programs, Mr. McClendon has personally participated in approximately 11% of all of the horizontal wells drilled in the United States over the past 20 years. From 1990 to 2012, key management team members of Chesapeake under Mr. McClendon participated in approximately 200 acquisitions by Chesapeake of acreage, producing oil and gas properties, minerals and companies in amounts greater than $10 million, with a combined value of approximately $28 billion. Mr. McClendon earned a Bachelor of Arts in History from Duke University in 1981.

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Subscription Agreements. The form of subscription agreement included in this Supplement No. 6 is hereby added as Exhibit B-1 to the Prospectus. Exhibit B-1 will hereby replace Exhibit B-1 — Subscription Agreement of Supplement No. 1 in its entirety. The form of multi-offering subscription agreement included in this Supplement No. 6 is hereby added as Exhibit B-2 to the Prospectus. Exhibit B-2 will hereby replace Exhibit B-2 — Multi-Offering Subscription Agreement of Supplement No. 2 in its entirety.

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Exhibit B-1 to Prospectus