AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP - FORM 10-K

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP	Financial_Report.xls
EX-32 - EXHIBIT 32 - AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP	aecp-exhibit32x201410k.htm
EX-31.2 - EXHIBIT 31.2 - AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP	aecp-exhibit312x201410k.htm
EX-31.1 - EXHIBIT 31.1 - AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP	aecpexhibit-311x201410k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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 number: 333-192852

American Energy Capital Partners - Energy Recovery Program, LP

(Exact name of registrant as specified in its charter)



Delaware		46-4076419
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
405 Park Avenue, New York, NY		10022
(Address of principal executive offices)		(Zip Code)
(212) 415-6500
(Registrant's telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act: None
Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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. x Yes ¨ No

Indicate by check mark whether the registrant 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes x No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 definition of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer ¨	(Do not check if a smaller reporting company)	Smaller reporting company x

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

There is no established public market for the registrant's limited partnership interests. The registrant is currently conducting the ongoing initial public offering of its limited partnership interests pursuant to its registration statement on Form S-1 (File No. 333-192852) at a per unit price of up to $20. The aggregate market value of the registrant's limited partnership interest held by non-affiliates of the registrant as of June 30, 2014, the last business day of the registrant's most recently completed second fiscal quarter, was approximately $1.1 million based on a per share value of $20.00.

As of February 28, 2015, the Partnership had 339,386 Common Units outstanding.

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PART I		Page

Item 1.	Business	1
Item 1A.	Risk Factors	2
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosure	28

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	37
Item 9A.	Controls and Procedures	37
Item 9B.	Other Information	37

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	38
Item 11.	Executive Compensation	40
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	40
Item 13.	Certain Relationships and Related Transactions, and Director Independence	40
Item 14.	Principal Accounting Fees and Services	42

PART IV

Item 15.	Exhibits and Financial Statement Schedules	43

Signatures		44

Forward-Looking Statements

This Annual Report on Form 10-K ("Form 10-K") contains forward-looking statements. You can identify forward-looking statements by the use of forward-looking terminology such as “believes,” “expects,” “may,” “will,” “would,” “could,” “should,” “seeks,” “intends,” “plans,” “projects,” “estimates,” “anticipates,” “predicts” or “potential”, or by the negative of these words and phrases, or by similar words or phrases. You can also identify forward-looking statements by discussions of strategy, plans or intentions. Statements regarding the following subjects may be impacted by a number of risks and uncertainties which may cause our actual results, performance or achievements to be materially different from any future results, performances or achievements expressed or implied by the forward-looking statements:


•	our use of the proceeds of this offering;


•	our business and investment strategy;


•	our ability to make investments in a timely manner or on acceptable terms;


•	current credit market conditions and our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner and on terms that are consistent with what we project when we invest in a property;


•	the effect of general market, oil and gas market, economic and political conditions, including the recent economic slowdown and dislocation in the global credit markets;


•	our ability to make scheduled payments on our debt obligations;


•	our ability to generate sufficient cash flows to make distributions to our unitholders;


•	the degree and nature of our competition;


•	the availability of qualified personnel at our general partner, the dealer manager and the Manager; and


•	other subjects referenced in this Form 10-K, including those set forth under the caption “Risk Factors.”

The forward-looking statements contained in this Form 10-K reflect our beliefs, assumptions and expectations of our future performance, taking into account all information currently available to us. These beliefs, assumptions and expectations are subject to risks and uncertainties and can change as a result of many possible events or factors, not all of which are known to us. If a change occurs, our business, financial condition, liquidity and results of operations may vary materially from those expressed in our forward-looking statements. You should carefully consider these risks before you make an investment decision with respect to our common units.

For more information regarding risks that may cause our actual results to differ materially from any forward-looking statements, see “Risk Factors.” We disclaim any obligation to publicly update or revise any forward-looking statements to reflect changes in underlying assumptions or factors, new information, future events or other changes.

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PART I

Item 1. Business

Overview

American Energy Capital Partners - Energy Recovery Program, LP (formerly, American Energy Capital Partners, LP) and its consolidated subsidiary, AECP Operating Company, LLC (collectively referred to as the Partnership, we or our), were both formed in Delaware on October 30, 2013. The general partner is American Energy Capital Partners GP, LLC (the "General Partner"), which was formed in Delaware on October 30, 2013 and is wholly owned by AR Capital Energy Holdings, LLC (the "ARC Sponsor"). The ARC Sponsor is under common control with AR Capital, LLC. In connection with the formation of the Partnership, the General Partner made an initial capital contribution in the amount of $20 for its general partner interest.

On May 8, 2014, the U.S. Securities and Exchange Commission (the "SEC") declared effective our registration statement on Form S-1 (File No. 333-192852) (the "Registration Statement") filed under the Securities Act of 1933, as amended (the "Securities Act") and we commenced our initial public offering (the "Offering"), on a "reasonable best efforts" basis, of up to 100.0 million common units representing limited partnership interests ("Common Units") at a per unit price of up to $20.00. The Offering is expected to end on May 8, 2016, or two years from the effectiveness of the Registration Statement (the "final termination date"). On June 16, 2014, we commenced business operations after raising $2.0 million of gross proceeds (the "initial closing"), the amount required for us to release equity proceeds from escrow, and began business activities, including the acquisition and development of producing and non-producing oil and gas properties, including drilling activities.

We have no officers, directors or employees. Instead, the General Partner manages our day-to-day affairs. All decisions regarding our management are made by the board of directors of the General Partner and its officers. We entered into a management services agreement (the "Management Agreement") with AECP Management, LLC (the "Manager" or the "AECP Sponsor"). The General Partner will have full authority to direct the activities of the Manager under the Management Agreement. The Manager will provide us with management and operating services regarding substantially all aspects of operations. Realty Capital Securities, LLC ("RCS" or the "Dealer Manager") serves as the dealer manager of the Offering.

We were formed to acquire, develop, operate, produce and sell working and other interests in producing and non-producing oil and gas properties located onshore in the United States. We will seek to acquire working interests, leasehold interests, royalty interests, overriding royalty interests, production payments and other interests in producing and non-producing oil and gas properties. As of December 31, 2014, we had not identified or acquired any oil and gas properties. As we have not yet acquired oil and gas properties, our principal source of cash is the proceeds from our Offering, which we rely on to finance operations, distributions and capital investments.

Investment Objectives

We were formed to enable investors to invest in oil and gas properties located onshore in the United States. Our primary objectives are:


•	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;


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


•	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


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

The Properties We Intend to Acquire and Develop

We intend to target for acquisition producing and non-producing oil and gas properties that we expect will require additional drilling and other development activities to fully develop their potential. When we acquire a property, we will estimate the capital required to develop the property and plan to reserve a portion of our capital contributions, or a portion of any borrowing capacity available to us, to fund all or a portion of these estimated costs of development. We also plan to use our cash flow after the payment of targeted distributions to our unitholders to further develop our properties during our first five to seven years of operation after the initial closing date.

We do not expect to conduct a material amount of exploratory drilling on any non-producing properties we acquire, nor do we intend to acquire gathering systems, pipelines, treatment facilities, processing plants and other infrastructure, except in connection with the oil and gas properties we acquire.

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Competition

The oil and natural gas industry is highly competitive. We will encounter strong competition from independent oil and gas companies, master limited partnerships and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging for the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or other resources will permit.

Competition is strong for attractive oil and natural gas properties and there can be no assurances that we will be able to compete satisfactorily when attempting to make acquisitions. In general, sellers of producing properties are influenced primarily by the price offered for the property, although a seller also may be influenced by the financial ability of the purchaser to satisfy post-closing indemnifications, plugging and abandoning operations and similar factors.

We also may be affected by competition for drilling rigs, human resources and the availability of related oilfield services and equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Employees

We have no officers, directors or employees. Instead, the General Partner manages our day-to-day affairs. All decisions regarding our management are made by the board of directors of the General Partner and its officers. We entered into a Management Agreement with the Manager pursuant to which the Manager will provide us with management and operating services regarding substantially all aspects of operations. The General Partner will have full authority to direct the activities of the Manager under the Management Agreement.

Available Information

We electronically file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, with the U.S. Securities and Exchange Commission (the "SEC"). We also filed with the SEC our Registration Statement in connection with our current Offering. Individuals may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, or may obtain information by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet address at http://www.sec.gov that contains reports, proxy statements and information statements, and other information, which may be obtained free of charge. We will also provide copies of our filings without charge upon request.

Item 1A. Risk Factors

Our Common Units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations or cash flows could be materially adversely affected.

Risks Related to an Investment in the Partnership

The Offering is a blind pool offering. Because we have not yet identified any prospects or properties, you may not be able to evaluate our prospects or properties before making your investment decision, which makes your investment more speculative. In addition, we cannot assure you that we will be able to acquire prospects or properties on an economic basis or at all.

Because we are, in large part, relying on offering proceeds from our unitholders to finance the acquisitions of our prospects or properties, we have not yet identified any prospects or properties that we intend to acquire. Thus, you may not have the opportunity to evaluate any of the prospects or properties we select before we acquire them or prior to your investment in our Common Units. Unlike a business with established properties and an operating history, you may not have an opportunity before purchasing Common Units to evaluate geophysical, geological, economic or other information regarding the prospects and properties to be selected. Delays are likely in the investment of our offering proceeds because our offering period can extend over a number of months, and no prospects or properties will be acquired until after the initial closing of the Offering. If we select a prospect or property for acquisition during the offering period, we will file a prospectus supplement describing the prospect or property and its proposed acquisition. If you subscribe for Common Units prior to any such supplement, you will not be permitted to withdraw your subscription as a result of any subsequent selection of any prospect or property.

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In addition, because we are a recently formed Partnership with no prior operating history or assets, we cannot assure you that we will be able to acquire developed or undeveloped producing and nonproducing oil and gas properties on an economic basis or at all. We face a number of competitive risks related to the acquisition of properties, as described under “— Risks Related to Our Business — Competition with third parties in acquiring oil and gas properties and other investments may reduce our profitability and the return on your investment.” If we are unable to identify and acquire oil and gas properties on an economic basis, or at all, you may lose some or all of your investment, and we may have insufficient cash to pay distributions on our Common Units and service our debt obligations. Please read “— Risks Related to Our Business” and “Competition, Markets and Regulation.”

We have no prior operating history or established financing sources, this is the first oil and gas program sponsored by our ARC sponsor and its affiliates and our General Partner’s executive officers have no experience managing public oil and gas companies; additionally this is the first oil and gas program to which the Manager will provide management services.

Because we are a recently formed entity, we face many challenges, including, among other things:


•	we have no operating history, and accordingly, cannot accurately predict direct or administrative costs that will be associated with our operations;

•we do not currently own or operate, and since our formation have not owned or operated, any assets;

•we have no established financing sources;


•	none of the Manager or its affiliates has previously provided management services to an oil and gas drilling and production program like the Partnership; and


•	none of our General Partner, our ARC sponsor, our AECP sponsor have previously sponsored an oil and gas drilling and production program.

These and other factors make it difficult for us to accurately predict many important aspects of our business, including the prices at which we will be able to acquire properties, the costs of our operations and our sources of financing. We cannot assure you that we will succeed in achieving our goals, and our failure to do so could cause you to lose all or a significant portion of your investment or prevent us from generating sufficient available cash to be able to pay any distributions to you and the other unitholders.

Neither our General Partner nor the Manager has had any operations prior to the commencement of this Offering and our General Partner’s executive officers have no experience managing public oil and gas companies. For these reasons, our unitholders should be especially cautious when drawing conclusions about our future performance and you should not assume that it will be similar to the prior performance of other programs sponsored by the parent of our General Partner with respect to real estate or to prior oil and gas operations in which any of the executive officers of the Manager were involved. Our lack of an operating history, our General Partner’s lack of prior experience operating a public oil and gas company and our ARC sponsor’s lack of experience in connection with investments of the type to be made by us, significantly increase the risk and uncertainty our unitholders face in making an investment in our Common Units.

You should consider our prospects in light of the risks, uncertainties and difficulties frequently encountered by companies that are, like us, in their early stage of development. To be successful in this market, we must, among other things:

•identify and acquire oil and gas properties that further our investment strategies;

•attract, integrate, motivate and retain qualified personnel to manage our day-to-day operations;

•respond to competition for our targeted oil and gas properties as well as for potential investors; and

•continue to build and expand our operations structure to support our business.

We cannot guarantee that we will succeed in achieving these goals, and our failure to do so could cause you to lose all or a substantial portion of your investment.

Our distributions to our unitholders may not be sourced from our cash generated from operations but from offering proceeds or indebtedness, and this will decrease our distributions in the future.

Our General Partner intends to cause the Partnership to make distributions to unitholders commencing with the fourth whole month following the initial closing of the Offering. Because we are unlikely to have generated cash from operations or fully invested the proceeds from this Offering at that time, our distributions to unitholders early in our operations are more likely to be sourced from our offering proceeds or borrowings. Distributions to our investors will be deemed a return of capital until our unitholders have received 100% of their investment in our Common Units. Investors who acquire Common Units relatively early in our Offering, as compared with later investors, may receive a greater return of offering proceeds as part of

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the earlier distributions. If investors receive different amounts of returns of offering proceeds as distributions based on when they acquire Common Units, investors will experience different rates of return on their invested capital and some investors may have a lower tax basis in their Common Units than other investors. Furthermore, offering proceeds that are returned to investors as part of distributions to them will not be available for investments in oil and gas properties. The payment of distributions from sources other than operating cash flow will decrease the cash available to us to invest in oil and gas properties. We cannot assure you that you will receive any specific return on your investment. Furthermore, there is no limitation on the amount of distributions that can be funded from offering proceeds or financing proceeds, provided that funds may not be advanced or borrowed for purposes of distributions if the amount of such distributions 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 our revenues, investors residing in Iowa, Maryland, North Dakota, Ohio and Oklahoma will be provided disclosure that provides the percentage and dollar amount that is being funded from our revenues and the percentage and dollar amount that is being funded by offering proceeds or borrowings.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our General Partner, to enable us to make cash distributions to our unitholders under our cash distribution policy.

We may not have sufficient available cash each month to enable us to make cash distributions to our unitholders. The amount of cash we can distribute on our Common Units principally depends on the amount of cash we generate from our operations, which will fluctuate from month to month based on, among other things:


•	our strategy of acquiring oil and gas properties at attractive prices and developing those properties and the success of those properties;


•	the amount of oil, natural gas and natural gas liquids we produce;


•	the prices at which we sell our production;


•	our ability to acquire oil and natural gas properties at economically attractive prices;


•	our ability to hedge commodity prices at economically attractive prices;


•	the level of our capital expenditures;


•	the level of our operating and administrative costs including fees and reimbursements to our General Partner and the Manager; and


•	the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:


•	the amount of cash reserves established by our General Partner for the proper conduct of our business and for capital expenditures, which may be substantial;


•	the cost of acquisitions, operations, infrastructure and drilling;


•	our debt service requirements and other liabilities;


•	fluctuations in our working capital needs;


•	our ability to borrow funds;


•	the timing and collectability of receivables; and


•	prevailing economic conditions.

As a result of these and other factors, the amount of cash we distribute to our unitholders may fluctuate significantly from month to month.

If we are unable to find suitable prospects and properties, we may not be able to achieve our investment objectives or pay distributions.

Our ability to achieve our investment objectives and to pay distributions depends primarily upon our ability to acquire and develop oil and gas properties. Competition from competing entities may reduce the number of suitable investment opportunities offered to us or increase the bargaining power of property owners seeking to sell. Additionally, disruptions and dislocations in the credit markets have materially impacted the cost and availability of debt to finance oil and gas acquisitions, which is a key component of our acquisition strategy. A period in which there is a lack of available debt could result in a further reduction of suitable investment opportunities and create a competitive advantage to other entities that have greater financial resources than we do. During such times, our ability to borrow monies to finance the purchase of, or other activities related to, oil and gas assets will be negatively impacted. In addition, if we pay fees to lock in a favorable interest rate, falling interest rates or other factors could require us to forfeit these fees. If we acquire properties and other investments at higher prices or by using less-than-ideal capital structures, our returns will be lower and the value of our assets may decrease significantly below the amount we paid for the assets.

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Also, the more Common Units we sell in this offering, the greater our challenge will be to invest all of the net offering proceeds on attractive terms. We can give no assurance that we will be successful in identifying or, even if identified, acquiring suitable properties on financially attractive terms or that our objectives will be achieved. If we are unable to identify and acquire suitable properties promptly, we will hold the proceeds from this offering in an interest-bearing account or invest the proceeds in short-term assets. If we continue to be unsuccessful in identifying and acquiring suitable properties, we may ultimately decide to liquidate. In the event we are unable to timely locate suitable properties, we may be unable or limited in our ability to pay distributions and we may not be able to meet our investment objectives.

We may suffer from delays in locating suitable oil and gas properties, which could limit our ability to make distributions and lower the overall return on your investment.

We rely upon our General Partner and the oil and gas professionals affiliated with the Manager to identify suitable investments. To the extent that our General Partner and the oil and gas professionals employed by our General Partner or the Manager face competing demands on their time at times when we have capital ready for investment, we may face delays in locating suitable properties. Further, the more money we raise in this offering, the more difficult it will be to invest the net offering proceeds promptly and on attractive terms. Therefore, the large size of this offering and the continuing high demand for the types of oil and gas properties we desire to purchase increase the risk of delays in investing our net offering proceeds. Delays we encounter in the selection and acquisition or origination of income-producing properties would likely limit our ability to pay distributions to our unitholders and lower their overall returns. Further, our oil and gas development activities on a property will typically take months or longer to complete. Therefore, our unitholders could suffer delays in receiving the cash distributions attributable to those particular properties.

The Common Units are not liquid and your ability to resell your Common Units will be limited by the absence of a public trading market and substantial transfer restrictions.

If you invest in us, then you must assume the risks of an illiquid investment. The Common Units generally will not be liquid because there is not a readily available market for the sale of Common Units, and one is not expected to develop. Furthermore, although our partnership agreement contains provisions designed to permit the listing of the common units on a national securities exchange, we do not currently intend to list the common units on any exchange or in the over-the-counter market. Your inability to sell or transfer your Common Units increases the risk that you could lose some or all of your investment, because if we are unable to meet our performance goals, you may not have the ability to transfer your Common Units prior to our winding up and liquidation.

Our General Partner will have conflicts of interest with you and the other unitholders and may favor its own interests to your detriment.

Although our General Partner has a fiduciary 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 our ARC sponsor. See “Management” for additional information. Therefore, conflicts of interest may arise between our ARC sponsor 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 our ARC sponsor over our interests and the interests of our unitholders. These conflicts include the following situations, among others:


•	Neither our partnership agreement nor any other agreement requires our ARC sponsor to pursue a business strategy that favors us.


•	Our sponsors are not limited in their ability to compete with us and a sponsor may offer business opportunities to parties other than us if it has first determined that the opportunity either:


◦	cannot be pursued by us because of insufficient funds; or


◦	it is not appropriate for us under the existing circumstances.


•	Our General Partner is allowed to take into account the interests of parties other than us, such as our ARC sponsor, in resolving conflicts of interest.


•	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 and the amount of fees paid to our General Partner, the Manager and their respective affiliates.


•	Our General Partner determines which costs incurred by it are reimbursable by us.


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


•	Our General Partner controls the enforcement of the obligations that it and its affiliates owe to us and controls the enforcement of the Manager’s obligations under the Management Agreement on our behalf.

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

We may be unable to sell our properties or list the common units on a national securities exchange within our planned timeline or at all.

Beginning five to seven years after the initial closing date, we plan to either sell our properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to our partners, with the approval of the board of directors of our General Partner and the approval of the Manager, or list the common units on a national securities exchange. The decision to sell our properties will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of our assets, the projected amount of our oil and gas reserves, general economic conditions and other factors that are out of our control. In addition, the ability to list our common units on a national securities exchange will depend on a number of factors, including the state of the U.S. securities markets, our ability to meet the listing requirements of national securities exchanges, securities laws and regulations and other factors. If we are unable to either sell our properties or list the common units on a national securities exchange in accordance with our current plans, you may be unable to sell or otherwise transfer your Common Units and you may lose some or all of your investment.

Our General Partner may make decisions with respect to the cash generated from our operations that may adversely affect our results of operations and financial condition or result in lower or no distributions to you.

If we were presented with a drilling or other opportunity on our properties, and funding the opportunity would require us to use cash that we intend to reserve for distributions to our unitholders or for other purposes approved by our General Partner, our General Partner may elect to cause us to sell or farmout the opportunity or decline to participate in the opportunity, even if the General Partner determines that the opportunity could have a favorable rate of return, so long as the decision is made in good faith. Our General Partner is under no obligation to make cash distributions to you and the other unitholders, and it may decide to use cash to fund acquisitions or operations in lieu of making distributions on the Common Units. Our partnership agreement does not provide for any arrearages for months in which a distribution is not paid to unitholders. Our General Partner’s decisions with respect to our cash may adversely affect our results of operations and financial condition, and may result in lower or no distributions to you and the other unitholders.

Our partnership agreement limits our General Partner’s fiduciary duties to our unitholders including in some cases to that of a prudent operator and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our General Partner is held. For example, our partnership agreement permits our General Partner to:


•	be indemnified and held harmless as described under “Fiduciary Duty of the General Partner”;


•	devote only so much of its time as is necessary to manage our affairs;


•	conduct business with us in its capacity other than as General Partner in certain circumstances;


•	pursue business opportunities that are consistent with our investment objectives for its own account, but only after the General Partner has determined that such opportunity either cannot be pursued by us because of insufficient funds or because such opportunity is not appropriate for us under the existing circumstances;


•	manage other entities at the same time as it manages us; and


•	with respect to farmouts to the General Partner, the Manager, their respective affiliates or unaffiliated third parties, the General Partner will be subject to the lesser standard of prudent operator.

By purchasing a Common Unit, you and the other unitholders are bound by the provisions of the partnership agreement, including the provisions discussed above.

Compensation and fees paid to our General Partner and its affiliates and to the Manager under the Management Agreement regardless of success of our activities will reduce the cash we have available for distribution.

The General Partner and its affiliates will receive fees and reimbursement of administrative expenses and direct costs as described in “Compensation,” regardless of our success in acquiring, developing and operating properties. In addition, under the Management Agreement, the Manager will receive fees for providing the management, operating and other services that it is obligated to provide to us under that agreement. See “Compensation.” The fees and reimbursements to be paid to the General Partner and the fees to be paid to the Manager will reduce the amount of cash we have available to make distributions to investors. With respect to direct costs, the General Partner has sole discretion on behalf of us to select the provider of the services or goods and the provider’s compensation. These substantial fees and other payments also increase the risk that our unitholders will not be able to resell their Common Units at a profit.

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The ability to spread the risks of property acquisitions among a number of properties will be reduced if less than the maximum offering proceeds are received and fewer acquisitions are consummated.

We have received minimum offering proceeds of $2,000,000 to break escrow, and our offering proceeds may not exceed $2,000,000,000. There are no other requirements regarding the amount of offering proceeds to be received by us. Generally, the less offering proceeds received, the fewer properties we would acquire with the proceeds of this Offering, which would decrease our ability to spread the risks of acquisition and development of our properties.

Our expected credit facility will likely have restrictions and financial covenants that restrict our business and financing activities and our ability to pay distributions to our unitholders.

In connection with the initial closing of this offering, we expect to enter into a revolving credit facility. Currently, we have no commitment from any lender to provide us with any financing arrangement. Also, we anticipate that our credit facility will likely restrict, among other things, our ability to incur debt and pay distributions, and require us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not timely cured or waived, a significant portion of our indebtedness may become immediately due and payable and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are likely to be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

The borrowing base under the credit facility will likely be primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

Your Common Units may be diluted.

The equity interests of our investors may be diluted. Our investors will indirectly benefit from our production revenues from all of our wells in proportion to their respective number of Common Units, based on the original purchase price of Common Units issued in the Offering regardless of:


•	the actual price you paid for your Common Units; or


•	which properties are acquired with your subscription proceeds.

Also, some classes of investors, including our General Partner and its executive officers and directors and others as described in our prospectus may buy Common Units at discounted prices because sales commissions and dealer manager fees will not be paid for those sales. Thus, investors who pay discounted prices for their Common Units may receive higher returns on their investments as compared to investors who pay the entire $20.00 per Common Unit.

Holders of our Common Units have limited voting rights and are not entitled to elect or remove the board of directors and officers of our General Partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our General Partner’s officers or the members of its board of directors, and will have no right to remove its officers or board of directors. The board of directors of our General Partner is chosen by the owners of our General Partner.

Control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our General Partner from transferring all or a portion of their ownership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a limited partnership generally has unlimited liability for the obligations of the limited partnership, except for those contractual obligations of the limited partnership that are expressly made without recourse to the general partner. Our Partnership is organized under Delaware law and we will conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if a court or government agency determined that:

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•	we were conducting business in a state but had not complied with that particular state’s limited partnership statute; or


•	a unitholder’s right to act with other unitholders to remove or replace the General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Our unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts that we wrongfully returned or distributed to them. Under Sections 17-607, 17-303 and 17-804 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their Partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Also, a purchaser of Common Units from a unitholder is liable for the obligations of the transferring limited partner to make contributions to us that are known to the purchaser of the Common Units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Purchases of Common Units by our General Partner and its directors and executive officers, officers and employees of our Dealer Manager, the Manager and affiliates of our General Partner and the Manager and their respective Friends in this Offering should not influence investment decisions of independent, unaffiliated investors.

Our General Partner and its directors and executive officers, and the officers and employees of our Dealer Manager, the Manager and affiliates of our General Partner and the Manager and their respective Friends may purchase our Common Units, and any such purchases will be included for purposes of determining whether the minimum of $2,000,000 of Common Units required to release funds from the escrow account has been sold. “Friends” means those individuals who have prior business and/or personal relationships with the executive officers or directors of our General Partner, the Dealer Manager, the Manager, or their respective affiliates including, without limitation, any service provider. In this regard, our General Partner and the Manager have each committed to pay, and did pay, $1,000,000 in cash to purchase Common Units on the initial closing date at a discounted price as described in greater detail in our prospectus, all of which will be applied to satisfy the required minimum subscription proceeds of $2,000,000. There are no other written or other binding commitments with respect to the acquisition of our Common Units by these parties, and there can be no assurance as to the amount, if any, of the Common Units these parties may acquire in the offering. Any Common Units purchased by our General Partner’s directors and executive officers, officers and employees of our Dealer Manager, and other affiliates or Friends of ours will be purchased for investment purposes only. However, the investment decisions made by any of our General Partner’s directors and executive officers, officers and employees of our Dealer Manager, other affiliates or Friends should not influence your decision to invest in our Common Units, and you should make your own independent investment decision concerning the risks and benefits of an investment in our Common Units.

We established the offering price of our Common Units on an arbitrary basis; as a result, the actual value of your investment may be substantially less than what you pay.

Our General Partner has arbitrarily determined the offering price of the Common Units, and the price bears no relationship to our book or asset values, or to any other established criteria for valuing issued or outstanding Common Units. Because the offering price is not based on any independent valuation, the offering price is not indicative of the proceeds that you would receive on liquidation.

Our ability to implement our investment strategy depends, in part, on the ability of our Dealer Manager to successfully conduct this offering, which makes an investment in us more speculative.

We have retained our Dealer Manager, which is owned by an entity under common control with our ARC sponsor, to conduct this offering. The success of this offering, and our ability to implement our business strategy, depends on the ability of our Dealer Manager to build and maintain a network of broker-dealers to sell our Common Units to their clients. Although our Dealer Manager has extensive experience distributing real estate investment trusts, this is the first distribution of an oil and gas investment program by our Dealer Manager. If our Dealer Manager is not successful in establishing, operating and managing this network of broker-dealers, our ability to raise proceeds through this offering will be limited and we may not have adequate capital to implement our investment strategy. If we are unsuccessful in implementing our investment strategy, you could lose all or a substantial part of your investment.

If our Dealer Manager terminates its dealer manager relationship with us, our ability to successfully complete this offering and implement our investment strategy would be significantly impaired.

Our Dealer Manager has the right to terminate its relationship with us if, among other things, any of the following occur: (1) our voluntary or involuntary bankruptcy; (2) we materially change our business, which requires the majority vote of our

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unitholders; (3) we become subject to a material action, suit, proceeding or investigation that might adversely affect us or the Common Units; (4) a material breach of the Dealer Manager agreement by us (which breach has not been cured within the required timeframe); (5) our willful misconduct or a willful or grossly negligent breach of our obligations under the Dealer Manager agreement; (6) the issuance of a stop order suspending the effectiveness of the registration statement of which this prospectus forms a part by the SEC and not rescinded within 10 business days of its issuance; or (7) the occurrence of any event materially adverse to us and our prospects or our ability to perform our obligations under the Dealer Manager agreement. If our Dealer Manager elects to terminate its relationship with us, our ability to complete this offering and implement our investment strategy would be significantly impaired and would increase the likelihood that our unitholders could lose all or a part of their investment.

If we are unable to raise substantial funds, we will be limited in the number and type of properties we may acquire and the value of your investment in us will fluctuate with the performance of the specific properties we acquire.

This offering is being made on a reasonable best efforts basis, which means the brokers participating in the offering are only required to use their reasonable best efforts to sell our Common Units and have no firm commitment or obligation to purchase any of the Common Units. As a result, the amount of proceeds we raise in this offering may be substantially less than the amount we would need to achieve a broadly diversified property portfolio. If we are unable to raise substantially more than the minimum offering amount, we will acquire fewer properties resulting in less diversification in terms of the number of properties owned, the geographic regions in which our properties are located and the types of properties that we acquire. In such event, the likelihood of our profitability being affected by the performance of any one of our properties will increase. Additionally, we are not limited in the number or size of our properties or the percentage of net proceeds we may dedicate to a single property. Your investment in our Common Units will be subject to greater risk to the extent that we lack a diversified portfolio of properties. In addition, our inability to raise substantial funds would increase our fixed operating expenses as a percentage of gross income, and our financial condition and ability to pay distributions could be adversely affected.

Because we will depend on our General Partner and its affiliates to conduct our operations on our properties, and our General Partner has engaged the Manager under the Management Agreement to assist it in performing such operations, any adverse changes in the financial health of our General Partner or the Manager or our relationship with them could hinder our operating performance and the return on our unitholders’ investments.

We will depend on our General Partner and its affiliates, and our General Partner will depend in part on the services of the Manager under the Management Agreement, and possibly other third party operators, for the day-to-day operations on our properties. In addition, our General Partner will be responsible for approving any acquisitions or sales of properties by us. In addition, the Manager and other third party operators will serve as contract operators of our oil and gas properties under operating agreements. Both our General Partner and the Manager are recently formed, our General Partner has no prior operating history and our Manager has a limited operating history. Our General Partner will depend on the fees and other compensation that it receives from us in connection with the purchase, management and sale of properties to conduct its operations. Any adverse changes in the financial condition of the General Partner, the Manager or third-party contract operators, or in our relationship with them could hinder its or their ability to successfully manage our operations and our portfolio of properties.

We are an “emerging growth company” under the federal securities laws and will be subject to reduced public company reporting requirements.

In April 2012, President Obama signed into law the JOBS Act. We are an “emerging growth company,” as defined in the JOBS Act, and are eligible to take advantage of certain exemptions from, or reduced disclosure obligations relating to, various reporting requirements that are normally applicable to public companies.

We could remain an “emerging growth company” for up to five years, or until the earliest of (1) the last day of the first fiscal year in which we have total annual gross revenue of $1 billion or more, (2) December 31 of the fiscal year that we become a “large accelerated filer” as defined in Rule 12b-2 under the Exchange Act (which would occur if the market value of our Common Units held by non-affiliates exceeds $700 million, measured as of the last business day of our most recently completed second fiscal quarter, and we have been publicly reporting for at least 12 months) or (3) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period. Under the JOBS Act, emerging growth companies are not required to (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of internal control over financial reporting, pursuant to Section 404 of the Sarbanes-Oxley Act, (2) comply with new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, which require mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor must provide additional information about the audit and the issuer’s financial statements, (3) comply with new audit rules adopted by the PCAOB after April 5, 2012 (unless the SEC determines otherwise), (4) provide certain disclosures relating to executive compensation generally required for larger public companies or (5) hold shareholder advisory votes on executive compensation. We have not yet made a decision as to

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whether to take advantage of any or all of the JOBS Act exemptions that are applicable to us. If we do take advantage of any of these exemptions, we do not know if some investors will find our Common Units less attractive as a result.

Additionally, the JOBS Act provides that an “emerging growth company” may take advantage of an extended transition period for complying with new or revised accounting standards that have different effective dates for public and private companies. This means an “emerging growth company” can delay adopting certain accounting standards until the standards are otherwise applicable to private companies. However, we are electing to “opt out” of the extended transition period, and will therefore comply with new or revised accounting standards on the applicable dates on which the adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for compliance with new or revised accounting standards is irrevocable.

Risks Related to Our Management Agreement

We depend on the Manager to provide us services necessary to operate our business. If the Manager is unable or unwilling to provide these services, it would result in disruption in our business, which could have an adverse effect on our ability to make cash distributions to unitholders and service our debt obligations.

Under the Management Agreement, the Manager has agreed to provide services to us such as land, geoscience, engineering, drilling operations, legal, IT, marketing, acquisition and divestiture, accounting, human resources, office space, and other administrative, technical and executive services. The Manager has also agreed to operate, or oversee the operation by others, of our properties for us. The Manager is not an affiliate of us or our General Partner, nor is it an affiliate of AR Capital, LLC or our ARC sponsor. Thus, if the Manager were to become unable or unwilling to provide such services, we would need to develop these services internally or arrange for the services from another service provider. Developing the capabilities internally or retaining another service provider could increase costs, which could have an adverse effect on our ability to make cash distributions to unitholders and our business, and the services, when developed or retained, may not be of the same quality as provided to us by the Manager.

The Manager, which will manage our business under the Management Agreement, is a recently formed entity with limited operating history.

The Manager is a recently formed entity with limited operating history. The Manager has not acted as a manager or a sponsor of oil and gas properties for other limited partnerships. You should consider the risks associated with reliance on a company that is in the early stages of its development. Further, the Manager is only required to devote such portion of its full productive time to our business as it determines to be necessary to perform its obligations under the Management Agreement. The failure of the Manager to successfully execute its business plan could have an adverse effect on its ability to perform under the Management Agreement, which could adversely affect our business and ability to make distributions.

Affiliates of the Manager will engage in business activities other than assisting the Manager in performing its obligations under the Management Agreement. Engaging in these activities could reduce the time that such affiliates or their employees devote to assisting our Manager on our business, which could adversely affect our business and ability to make distributions.

Although the business of the Manager will be limited to acting as manager pursuant to the Management Agreement, and the Manager does not and will not own any oil and gas properties, affiliates of the Manager plan to engage in the oil and gas business, including the acquisition, drilling, development and operation of oil and gas properties in which we and our unitholders will have no interest. These activities may be more profitable to the affiliates of the Manager than assisting the Manager in performing its obligations under the Management Agreement, and result in the Manager’s affiliates and their employees devoting less time to assisting the Manager in performing its obligations under the Management Agreement with respect to our business, which could adversely affect our business and ability to make distributions to our partners.

The Manager will not owe a fiduciary or similar duty to us, except to the safekeeping of the our funds and assets. Holders of Common Units will not have any right to enforce the Management Agreement if a holder of Common Units were to believe that the Manager was in breach of the agreement.

The Management Agreement provides that the Manager will act as a reasonably prudent operator in operating our properties under the Management Agreement. The Manager will not have a fiduciary or similar duty to us or our unitholders under the Management Agreement or applicable law when it acts under the Management Agreement, except that pursuant to the Management Agreement the Manager and any affiliate of the Manager which takes on any managerial duties to us under the Management Agreement will owe us a fiduciary responsibility for the safekeeping and care of all our funds and assets whether

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or not in the Manager’s possession or control and will apply such funds and assets for our exclusive benefit. The prudent operator standard is a standard developed in connection with oil and gas operations, and provides considerable discretion to the Manager in the operation of our properties, and limits our right of recourse for damages caused to us if the Manager acts in accordance with the prudent operator standard. The General Partner will be responsible for enforcing our rights under the Management Agreement; and holders of Common Units generally will not have the right to cause us to seek to enforce the Management Agreement if the holder of Common Units believes the Manager has breached the agreement.

We may acquire interests in oil and gas properties in which one or more affiliates of the Manager also own an interest and such affiliate(s) may make decisions with respect to their interests in these properties that are not in our best interest.

We may elect to acquire interests in properties in which one or more affiliates of the Manager also own or acquire an interest. None of the Manager’s affiliates will be under any obligation to us with respect to their interest(s) in these properties and any such affiliate could propose or consent to operations, or sell or farmout their interests in the properties, without taking into consideration our distribution policies, financial resources or whether such action is otherwise consistent with our goals or financial resources.

The Manager may be subject to conflicts of interest in managing our business under the Management Agreement.

Although the Manager’s business will be limited to serving as manager under the Management Agreement and in a similar capacity with respect to other oil and gas partnerships or entities that in the future may be formed by or affiliated with AR Capital, LLC or our ARC sponsor, the Manager may offer to sell us oil and gas properties or other assets that the Manager or an affiliate of the Manager has elected to offer for sale and in which the Manager or such affiliate owns an interest. Similarly, the Manager or an affiliate of the Manager may offer to acquire oil and gas properties or other assets from us that we elect to offer for sale. The Manager and its affiliates will not be under a fiduciary or other duty to offer to buy or sell properties or other assets to us or from us at a fair or market price, although pursuant to the Management Agreement the Manager has agreed that if we elect to acquire any properties from the Manager or an affiliate of the Manager we will not be required to pay more than the lower of the cost to the Manager or such affiliate, as applicable, of such property or fair market value and the Manager will not be entitled to an acquisition fee in respect of any such acquisition. In addition, to the extent we and the Manager or any affiliate of the Manager have joint ownership or operating interests in the same oil and gas property or prospect, we and the Manager or such affiliate may disagree about the value of those assets. Our General Partner will be required to determine whether we should acquire or sell such properties or other assets. Because our General Partner has no in-house technical resources with which to evaluate oil and gas properties and other assets, it intends, but is not required to, retain on our behalf technical, legal, land, operational and other consultants to assist it in its determination of whether we should acquire or sell properties or assets from or to the Manager or any affiliate of the Manager or other third party oil and gas operators. Further, if we acquire an interest in an oil and gas property or prospect in which the Manager or an affiliate of the Manager also owns an interest, then the Manager or such affiliate, as applicable, will not be under a fiduciary, contractual or other duty to offer to sell us its interest in such property or prospect, which could result in a conflict of interest since the Manager or such affiliate would benefit from any investment we make in such property or prospect.

Conflicts of interest may arise concerning which properties the Manager will present to us and which properties its affiliates will keep for their own account.

Under the Management Agreement, the Manager has agreed to identify onshore producing and non-producing oil and gas properties, that we may consider acquiring. In this regard, we and our General Partner do not have any right of first refusal to acquire properties in the inventory of the Manager or its affiliates or other properties that come to the attention of the Manager and it may be to the advantage of the Manager or an affiliate of the Manager to keep or acquire a property for its own account or present the property to independent third parties because of the prospective economic benefits, rather than present the property to us for acquisition. For example, because the Management Agreement limits the amount of compensation that may be received by the Manager from us with respect to the properties we acquire, it may be more advantageous for the Manager or an affiliate of the Manager to acquire and develop the property for its own account or with another third party, since doing so would not be subject to the limitations under the Management Agreement. Also, the drilling of wells on properties we acquire pursuant to the Management Agreement may provide the Manager or its affiliate(s) with offset drilling sites by allowing the Manager or such affiliate(s) of the Manager to determine, in part at our expense, the value of adjacent acreage owned by the Manager or affiliates of the Manager. In this regard, there is no restriction on the Manager or affiliates of the Manager owning developed or undeveloped acreage throughout the areas where our properties and wells will be situated. In addition, there is no restriction in the Management Agreement or elsewhere on the Manager or any affiliate of the Manager pursuing business opportunities for its own account. However, the Manager may make available to its affiliates any business opportunity that is consistent with our investment objectives only after the Manager has determined that the opportunity cannot be pursued by us because we have insufficient funds for such investment or it is not appropriate for us under then-existing circumstances. With

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respect to the determination of whether a business opportunity is appropriate for us under the then existing circumstances, the Manager will consider, among other factors, whether or not the net cash flows and anticipated valuation associated with the properties will be sufficient to:

•meet our expected monthly distributions;

•cover the anticipated expenses associated with our properties; and


•	provide our investors with a reasonable probability of an increase in the net asset value of our portfolio of properties beyond our cost basis in its properties.

If conflicts between our interests, on the one hand, and the interests of the Manager or any affiliate of the Manager for its own account, on the other hand, do arise, then, unless the Management Agreement stipulates otherwise, such conflicts may be resolved to the advantage of the Manager or such affiliate because the Manager has no fiduciary duty to us or our General Partner to resolve any such conflict in our favor.

If the Manager acts as operator of our oil and gas properties, it will be entitled to receive overhead payments under the operating agreements, which overhead payments may result in a profit to the Manager.

We expect that all or substantially all of the properties we acquire will be subject to an existing operating agreement negotiated between the operator and other owners of the property. Operating agreements for oil and gas properties generally provide that the operator is entitled to a fixed overhead charge per well operated. The Management Agreement provides that if the Manager operates our property, it will do so under the operating agreement in place when the property is acquired, if any. The Manager will be entitled to receive the overhead charges provided for in operating agreements in place at the time of the acquisition, regardless of amount, and we will not have the right to negotiate a different overhead charge.

Affiliates of the Manager will continue to own and operate other oil and gas properties and may face competing demands for their time.

Because affiliates of the Manager own and operate, and intend to continue to acquire, own and operate, oil and gas properties, the Manager will face competing demands for the time of such affiliates and their employees to assist the Manager in performing its obligations under the Management Agreement. We intend to rely on the Manager for its prospect origination and operating capabilities, and we may be unable to identify potential property acquisitions for our portfolio without the advice provided by the Manager’s oil and gas professionals, which may also serve as employees or advisors to one or more affiliates of the Manager. Additionally, the ongoing operations of our oil and gas properties may be adversely affected by the competing demands for the time of the Manager and its management and employees, who may also serve as managers or employees of an affiliate of the Manager.

Risks Related to Conflicts of Interest

Our sponsor and its affiliates, including our General Partner, and the Manager face conflicts of interest caused by their compensation arrangements with us, which could result in actions that are not in the long-term best interests of our unitholders.

Our General Partner and its affiliates and the Manager will receive substantial fees from us. These fees could influence our General Partner’s and the Manager’s advice to us as well as their respective judgment with respect to:


•	the continuation, renewal or enforcement of our agreements with affiliates of our General Partner and the Manager, including the partnership agreement, the dealer manager agreement and the management agreement between our Manager and us;

•public offerings of equity by us, which will likely entitle our General Partner to increased fees;

•sales of our properties to third parties, which will entitle our General Partner and the Manager to disposition fees;


•	acquisitions of properties from third parties, the Manager and affiliates of the Manager, which, except for any acquisition from the Manager or any affiliate of the Manager, will entitle the Manager to acquisition fees;


•	borrowings to acquire and develop properties, which borrowings will generate financing coordination fees and increase the acquisition fees and management fees payable to our General Partner and the Manager;


•	whether and when we seek to list our Common Units on a national securities exchange, which listing will require the consent of the board of directors of our General Partner and the consent of the Manager and could entitle our General Partner and an affiliate of the Manager to incentive distribution rights in excess of targeted amounts to be established in connection with such listing; and

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•	whether and when we seek to sell all or substantially all of our assets, which will require the consent of both our General Partner and a majority in interest of our unitholders, which sale could entitle our General Partner to a participation in net sales proceeds.

The fees our General Partner and the Manager will receive in connection with transactions involving the acquisition, financing and development of our properties will not be based on the quality of the services rendered to us. This may influence our General Partner and the Manager to approve riskier transactions to us and cause us to acquire properties with more debt and at higher prices.

Because other oil and gas programs sponsored by and offered through our Dealer Manager may conduct offerings concurrently with our offering, our Dealer Manager may face potential conflicts of interest arising from competition among us and these other programs for investors and investment capital, and such conflicts may not be resolved in our favor.

AR Capital, LLC, an entity under common control with our ARC sponsor, is the sponsor of several non-traded Real Estate Investment Trusts, or REITs, and business development companies, or BDCs, that are raising capital in ongoing public offerings of common stock. Our Dealer Manager, which is owned by an entity under common control with our ARC sponsor, is the Dealer Manager in a number of ongoing public offerings by non-traded REITs and BDCs, including some offerings sponsored by AR Capital, LLC or its affiliates. In addition, our ARC sponsor may decide to sponsor future oil and gas investment programs that would seek to raise capital through public offerings conducted concurrently with this Offering. As a result, our ARC sponsor and our Dealer Manager may face conflicts of interest arising from potential competition with these other programs for investors and investment capital. Our ARC sponsor generally seeks to avoid simultaneous public offerings by programs that have a substantially similar mix of investment attributes, including targeted investment types. Nevertheless, there may be periods during which one or more programs sponsored by our ARC sponsor and its affiliates will be raising capital and might compete with us for investment capital. Such conflicts may not be resolved in our favor, and you will not have the opportunity to evaluate the manner in which these conflicts of interest are resolved before or after making your investment.

Our ARC sponsor, our General Partner and the oil and gas and other professionals assembled by our General Partner and the Manager, face competing demands relating to their time, and this may cause our operations and our unitholders’ investments to suffer.

We rely on our General Partner for the day-to-day operation of our business and the selection of our oil and gas properties. Our General Partner will make major decisions affecting us, and the General Partner will rely in part on the services of the Manager to assist the General Partner in conducting such operations. Our General Partner also will rely on its affiliates to conduct our business. Certain of the principals of our ARC sponsor and our General Partner are key executives in other programs sponsored by our ARC sponsor and its affiliates and hold an indirect ownership interest in our General Partner. As a result of their interests in other programs sponsored by our ARC sponsor, their obligations to other investors and the fact that they engage in and they will continue to engage in other business activities, these individuals will continue to face conflicts of interest in allocating their time among us and other programs sponsored by our ARC sponsor and its affiliates and other business activities in which they are involved. Should our General Partner breach its fiduciary duties to us by inappropriately devoting insufficient time or resources to our business, the returns on our investments, and the value of our unitholders’ investments, may decline.

Our General Partner and the Manager and their respective affiliates face conflicts of interest relating to the incentive fee structure, which could result in actions that are not necessarily in the long-term best interests of our unitholders.

Under our partnership agreement, our General Partner will be entitled to fees, distributions and other amounts that are structured in a manner intended to provide it with incentives to perform in our best interests and in the best interests of our unitholders. In addition, pursuant to the Management Agreement, we have agreed to pay the Manager and its affiliates fees, distributions and other amounts that are structured to provide such entities with an incentive to recommend actions for approval by our General Partner that would be in our best interests. However, because they do not maintain a significant equity interest in us and are entitled to receive substantial minimum compensation regardless of performance, the interests of the General Partner and the Manager are not wholly aligned with those of our unitholders. In that regard, they could be motivated to recommend riskier or more speculative properties in order for us to generate the specified levels of performance or sales proceeds that would entitle them to fees. In addition, their entitlement to fees and distributions on the sale of our properties and to participate in sale proceeds could result in them recommending sales of our properties at the earliest possible time at which sales of properties would produce the level of return that would entitle them to compensation relating to the sales, even if continued ownership of those properties might be in our best long-term interest.

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The Manager could be subject to conflicts of interest if it serves as the manager of other oil and gas partnerships formed in the future by AR Capital, LLC.

The Manager may serve as the manager or in a similar capacity to other oil and gas partnerships or entities that in the future may be formed by or affiliated with AR Capital, LLC. The obligations required of the Manager with respect to such activities could require that the Manager and its management and employees devote significant time to the businesses and operations of such other entities, as opposed to serving as the manager under the Management Agreement. As a result, the Manager could be subject to conflicts of interest with respect to the amount of time and resources it devotes to performing services on our behalf pursuant to the Management Agreement as opposed to performing services on behalf of any such other oil and gas programs.

Activities conducted by affiliates of the Manager could conflict with our planned activities.

Affiliates of the Manager own, operate, acquire and develop, and intend to continue to own, operate, acquire and develop, oil and gas properties and prospects in onshore productive regions of the United States. Such activities by any affiliate of the Manager could conflict with our actual or planned activities which could adversely affect our financial condition or results of operations.

There is no separate counsel for us or our General Partner and its affiliates, which could result in conflicts of interest, and the conflicts may not be resolved in our favor, which could adversely affect the value of your investment.

Kunzman & Bollinger, Inc. acts as legal counsel to us and also represents our General Partner and some of its affiliates. There is a possibility in the future that the interests of the various parties may become adverse and, under the Code of Professional Responsibility of the legal profession, Kunzman & Bollinger, Inc. may be precluded from representing any one or all such parties. If any situation arises in which our interests appear to be in conflict with those of our General Partner or its affiliates, additional counsel may be retained by one or more of the parties to assure that their interests are adequately protected. Moreover, should a conflict of interest not be readily apparent, Kunzman & Bollinger, Inc. may inadvertently act in derogation of the interest of the parties which could affect our ability to meet our investment objectives.

Our Dealer Manager signed a Letter of Acceptance, Waiver and Consent with FINRA; any further action, proceeding or litigation with respect to the substance of the Letter of Acceptance, Waiver and Consent could adversely affect this offering or the pace at which we raise proceeds.

In April 2013, our Dealer Manager received notice and a proposed Letter of Acceptance, Waiver and Consent, or AWC, from FINRA, the self-regulatory organization that oversees broker dealers, that certain violations of SEC and FINRA rules, including Rule 10b-9 under the Exchange Act and FINRA Rule 2010, occurred in connection with its activities as a co-dealer manager for a public offering. Without admitting or denying the findings, our dealer manager submitted an AWC, which FINRA accepted on June 4, 2013. In connection with the AWC, our Dealer Manager consented to the imposition of a censure and a fine of $60,000. To the extent any action would be taken against our Dealer Manager in connection with the above AWC, our Dealer Manager could be adversely affected, which could adversely affect our ability to raise capital.

Because our Dealer Manager is owned by an entity under common control with our ARC sponsor, you will not have the benefit of an independent due diligence review of us, which is customarily performed in underwritten offerings; the absence of an independent due diligence review increases the risks and uncertainty you face as a Unitholder.

Our Dealer Manager is owned by an entity which is under common control with our ARC sponsor. Because of this relationship, our Dealer Manager’s due diligence review and investigation of us and the Offering cannot be considered to be "independent". Therefore, you will not have the benefit of an independent review and investigation of the Offering of the type normally performed by an unaffiliated, independent underwriter in a public securities offering.

If we are unable to obtain funding for future capital needs, cash distributions to our unitholders and the value of our properties could decline.

If we need additional capital in the future to improve or maintain our properties or for any other reason, we may have to obtain financing from sources, beyond our funds from operations, such as borrowings. These sources of funding may not be available on attractive terms or at all. If we cannot procure additional funding for capital improvements, our properties may generate lower cash flows or decline in value, or both, which would limit our ability to make distributions to our unitholders and could reduce the value of your investment.

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Risks Related to Our Business

We plan to drill development wells to fully develop the properties we acquire. If our drilling is unsuccessful, our cash available for distributions and financial condition will be adversely affected.

We plan to acquire oil and gas properties that are not fully developed and require us to engage in drilling development wells to fully exploit the oil and gas reserves attributable to the properties. A development well means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon know to be productive. Our drilling will involve numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We will incur significant expenditures to drill and complete wells, including cost overruns. These expenditures will reduce cash available for distribution to holders of our Common Units and for servicing our debt obligations. Additionally, current geoscience technology does not allow us to know conclusively, prior to drilling a well, that oil or natural gas is present or will be economically producible from the well. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on drilling and completing wells including cost overruns, and still not discover reserves in commercially viable quantities.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

•unexpected drilling conditions;

•facility or equipment failure or accidents;

•shortages or delays in the availability of drilling rigs and equipment;

•adverse weather conditions;

•compliance with environmental and governmental requirements;

•title problems;

•unusual or unexpected geological formations;

•pipeline ruptures;

•fires, blowouts, craterings and explosions; and

•uncontrollable flows of oil or natural gas or well fluids.

If oil, natural gas or other hydrocarbon prices remain depressed for a prolonged period, our cash flows from operations and the value of our assets will decline and we may have to lower our distributions or may not be able to pay distributions at all.

Our revenue, profitability and cash flow depend on the prices for oil, natural gas and other hydrocarbons. The prices we will receive for our production will be volatile and a drop in prices can significantly affect our financial results and adversely affect our ability to maintain our borrowing capacity and to repay indebtedness, all of which can affect our ability to pay distributions to you and our other unitholders. Changes in oil and gas prices will also have a significant impact on the value of our reserves and on our cash flows. Additionally, oil and natural gas prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

•the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons;

•regulations which may prevent or limit the export of oil, natural gas and other hydrocarbons;

•the amount of added production from development of unconventional oil and natural gas reserves;

•the price and quantity of foreign imports of oil, natural gas and other hydrocarbons;

•the level of consumer product demand;

•weather conditions;

•the value of the U.S dollar relative to the currencies of other countries;

•overall domestic and global economic conditions;


•	political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, China and Russia, and acts of terrorism or sabotage;


•	the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;


•	technological advances affecting energy production and consumption;


•	domestic and foreign governmental regulations and taxation;


•	the impact of energy conservation efforts;


•	the proximity and capacity of oil, natural gas and other hydrocarbon pipelines and other transportation facilities to our production; and

•the price and availability of alternative fuels, such as solar, coal, nuclear and wind energy.

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Low oil, natural gas and other hydrocarbon prices will decrease our revenues, and may also reduce the amount of oil, natural gas or other hydrocarbons that we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds, which may adversely affect our ability to make cash distributions to our unitholders and service our debt obligations.

Properties that we buy or develop may not produce as anticipated and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution.

Our property acquisitions will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices, development and operating costs, potential environmental hazards, potential tax liabilities, and other liabilities and similar factors. We expect that our review efforts and those of the Manager will be focused on the higher valued properties in our acquisitions and will be inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to make cash distributions to holders of our Common Units and service our debt obligations.

Additional potential risks related to acquisitions of oil and gas properties include, among other things:


•	incorrect assumptions regarding the future prices of oil, natural gas and other hydrocarbons or the future operating or development costs of properties acquired;

•incorrect estimates of the reserves and projected development results attributable to a property we acquire;

•drilling, completion, operating and other cost overruns;

•an inability to integrate successfully the properties we acquire;

•the assumption of liabilities;

•limitations on rights to indemnity from the seller; and

•the diversion of management’s attention to other business concerns.

We may be unable to integrate successfully the operations of our future acquisitions and we may not realize all the anticipated benefits of acquisitions that we make in the future.

Integration of our property acquisitions will be a complex, time consuming and costly process. Failure to successfully assimilate our future acquisitions could adversely affect our financial condition and results of operations.

Our acquisitions involve numerous risks, including:


•	operating a significantly larger combined organization and adding operations;


•	difficulties in the assimilation of the assets and operations of the acquired properties, especially if the assets acquired are in a new geographic area or are not contiguous to our asset base at the time of purchase;


•	the risk that reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;


•	the loss of significant key employees from the acquired properties;

•the diversion of management attention of our General Partner and the Manager to other business concerns;

•the failure to realize expected profitability or growth;

•the failure to realize expected synergies and cost savings;

•coordinating geographically disparate organizations, systems and facilities; and

•coordinating or consolidating corporate and administrative functions.

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Further, unexpected costs and challenges may arise whenever acquisitions are consummated, and we may experience unanticipated delays in realizing the benefits of an acquisition.

Our business is subject to operational risks that will not be fully insured and which, if they were to occur, could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to holders of our Common Units and service our debt obligations.

Our business activities are subject to operational risks, including:


•	damages to equipment caused by adverse weather conditions, including earthquakes, climate change, tornadoes, drought and flooding;


•	facility or equipment malfunctions;


•	pipeline ruptures or spills;


•	fires, blowouts, craterings and explosions;


•	uncontrollable flows of oil or natural gas or well fluids; and


•	surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we will maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to holders of our Common Units and service our debt obligations.

We may obtain only limited warranties when we purchase a property and would have only limited recourse if we did not identify any issues that lower the value of our property during our due diligence process, which could adversely affect our financial condition and ability to make distributions to you.

The seller of a property often sells the property in its “as is” condition on a “where is” basis and “with all faults,” without any warranties of merchantability or fitness for a particular use or purpose. In addition, purchase agreements may contain only limited warranties, representations and indemnifications that will only survive for a limited period after the closing. The purchase of properties with limited warranties increases the risk that we may lose some or all our invested capital in the property.

Our inability to sell a property when we desire to do so could adversely impact our ability to pay cash distributions to you.

The market for oil and gas properties is affected by many factors, such as general economic conditions, availability of financing, interest rates and other factors, including supply and demand, that are beyond our control. We cannot predict whether we will be able to sell any property for the price or on the terms set by us, or whether any price or other terms offered by a prospective purchaser would be acceptable to us. We cannot predict the length of time needed to find a willing purchaser and to close the sale of an oil and gas property.

We may not be able to sell our properties at an acceptable price, which may lead to a decrease in the value of our assets.

The value of an oil and gas property to a potential purchaser generally decreases over time as the oil and natural gas from the property is produced and sold, or depleted, which may restrict our ability to sell a property, or if we are able to sell such property, we may not receive a sale price acceptable to us. Many factors that are beyond our control affect the oil and gas market and could affect our ability to sell properties for the price, on the terms or within the time frame that we desire. These factors include general economic conditions, the availability of financing, interest rates, the then current prices for oil and natural gas and the outlook for the same, and other factors, including supply and demand. Because oil and gas investments are relatively illiquid, we have a limited ability to vary our portfolio in response to changes in economic or other conditions. We may be unable to sell our properties at a profit. Our inability to sell properties at the time and on the terms we want could

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reduce our cash flow and limit our ability to make distributions to our unitholders and could reduce the value of our unitholders’ investments. Moreover, in acquiring a property, we may agree to restrictions that inhibit the resale of that property or impose other restrictions. We cannot predict the length of time needed to find a willing purchaser and to close the sale of a property. Our inability to sell a property when we desire to do so may cause us to reduce our selling price for the property. Any delay in our receipt of proceeds, or diminishment of proceeds, from the sale of a property could adversely impact our ability to pay distributions to our unitholders.

We intend to incur indebtedness to acquire and develop our oil and gas properties, which may increase our business risks, could hinder our ability to pay distributions and could decrease the value of your investment.

We intend to finance a portion of the purchase price of our investments in oil and gas properties by borrowing funds through a credit facility that we expect to obtain through a financial institution following the initial closing of this offering. Currently, however, we have no commitments from any lenders to provide us any credit facility. We anticipate that the credit facility will allow borrowings up to a borrowing base that will be set by the lenders under the facility, at their discretion, based in part on their valuation of our oil and natural gas reserves. Under the partnership agreement, our overall leverage will not exceed 50% of our total capitalization as determined on an annual basis. To the extent we incur indebtedness and are required to devote a portion of our cash flows from operating activities to service the indebtedness, such cash flows will not be available for our use in pursuing our acquisition and development strategy or paying cash distributions to our unitholders. In addition, we may use borrowings under our credit facility to pay distributions, provided that funds will not be advanced or borrowed by us for the purpose of making distributions to our 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. See “Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources.”

If there is a shortfall between the cash flows from our properties and the cash flows needed to service our indebtedness, then the amount available for distributions to our unitholders may be reduced. In addition, high debt levels and the potential that the interest rates charged under our credit facility could increase over time, will increase the risk of loss since defaults on indebtedness secured by our properties may result in lenders initiating foreclosure actions. In this regard, we could lose the properties securing the loan that is in default, thus reducing the value of our unitholders' investments. For tax purposes, a foreclosure on any of our properties will be treated as a sale of the property for a purchase price equal to the outstanding balance of the debt secured by the mortgage. If the outstanding balance of the debt secured by our oil and gas properties exceeds our tax basis in those properties, we will recognize taxable income on foreclosure, but we would not receive any cash proceeds and cash distributions to our unitholders would be adversely affected. The defense of any such claims could be costly and materially impact our financial condition, even absent any adverse determination. If these claims were successful, our ability to meet our obligations to our future creditors, make distributions and finance our operations could be materially and adversely affected.

Increases in interest rates could increase the amount of our debt payments and negatively impact our operating results.

Interest we pay on our debt obligations may reduce cash available for distributions. Variable interest rates under a credit facility could mean that increases in interest rates increase our interest costs, which would reduce our cash flows and our ability to pay distributions to our unitholders. If we need to make payments under our credit facility during periods of rising interest rates, we could be required to liquidate one or more of our investments in oil and gas properties at times which may not permit realization of the maximum return on those investments.

Lenders may require us to enter into restrictive covenants relating to our operations, which could limit our ability to pay distributions to our unitholders.

When providing financing, a lender may impose restrictions on us that affect our ability to incur additional debt and affect our distribution and operating strategies. Loan documents we enter into may contain covenants that limit our ability to further finance our oil and gas properties and discontinue insurance coverage. These or other limitations may adversely affect our flexibility and our ability to achieve our investment objectives.

Higher interest rates may make it more difficult for us to finance or refinance properties, which could reduce the number of oil and gas properties we can acquire and the amount of cash distributions we can pay to our unitholders.

If a credit facility is unavailable on reasonable terms as a result of increased interest rates or other factors, we may not be able to finance the initial purchase of oil and gas properties. We may be unable to refinance or replace a credit facility at appropriate times, which may require us to sell properties on terms that are not advantageous to us, or could result in the foreclosure of the properties. If any of these events occur, our cash flows would be reduced. This, in turn, would reduce cash

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available for distribution to our unitholders and may hinder our ability to raise more capital by issuing securities or by borrowing more money.

Joint venture investments could be adversely affected by our lack of sole decision-making authority, our reliance on the financial condition of co-venturers and disputes between us and our co-venturers.

We may enter into joint ventures, partnerships and other co-ownership arrangements for the purpose of making investments in oil and gas properties. In that event, we may not be in a position to exercise sole decision-making authority regarding the operations of the joint venture. Investments in joint ventures may, under certain circumstances, involve risks not present were a third party not involved, including the possibility that partners or co-venturers might become bankrupt or fail to fund their required capital contributions. Co-venturers may have economic or other business interests or goals that are inconsistent with our business interests or goals, and may be in a position to take actions contrary to our policies or objectives. Such investments may subject us to the potential risk of impasses on decisions, such as a sale, because neither we nor the co-venturer may have full control over the joint venture. In addition, to the extent our participation represents a minority interest, a majority of the participants may be able to take actions which are not in our best interests because of our lack of full control. Disputes between us and co-venturers may result in litigation or arbitration that would increase our expenses and prevent our General Partner and the Manager from focusing their time and effort on our business. Consequently, actions by or disputes with co-venturers might result in subjecting properties owned by the joint venture to additional risk. In addition, we may in certain circumstances be liable for the actions of our co-venturers.

If we set aside insufficient capital reserves, we may be required to defer necessary capital expenditures.

If we do not have enough reserves for capital to supply needed funds for capital improvements throughout the life of the investment in a property and there is insufficient cash available from our operations, we may be required to defer necessary improvements to a property, which may cause that property to suffer from a greater risk of a decline in value, or a greater risk of decreased cash flow. If this happens, our results of operations may be negatively impacted.

Uninsured losses relating to oil and gas activities or excessively expensive premiums for insurance coverage could reduce our cash flows and the return on our unitholders’ investments.

We will attempt to adequately insure all of our oil and gas properties against casualty losses. There are types of losses, generally catastrophic in nature, such as losses due to wars, acts of terrorism, earthquakes, floods, hurricanes, pollution or environmental matters, that are uninsurable or not economically insurable, or may be insured subject to limitations, such as large deductibles or co-payments. Insurance risks associated with potential acts of terrorism could sharply increase the premiums we pay for coverage against property and casualty claims. Such insurance policies may not be available at reasonable costs, if at all, which could inhibit our ability to finance or refinance our properties. In such instances, we may be required to provide other financial support, either through financial assurances or self-insurance, to cover potential losses. We may not have adequate, or any, coverage for such losses. Changes in the cost or availability of insurance could expose us to uninsured casualty losses. If any of our properties incurs a casualty loss that is not fully insured, the value of our assets will be reduced by any such uninsured loss, which may reduce the value of our unitholders’ investments. In addition, other than any working capital reserve or other reserves we may establish, or borrowings, we have no source of funding to repair or reconstruct any uninsured property. Also, to the extent we must pay unexpectedly large amounts for insurance, we could suffer reduced earnings that would result in lower distributions to unitholders.

Competition with third parties in acquiring oil and gas properties and other investments may reduce our profitability and the return on your investment.

The oil and natural gas industry is intensely competitive, and we will compete with many other entities engaged in oil and gas activities, including individuals, corporations, bank and insurance company investment accounts, oil and gas limited partnerships, and other entities engaged in oil and gas investment activities, many of which have greater resources than we do. Our ability to acquire oil and gas properties in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only acquire properties and drill for and produce oil, natural gas and natural gas liquids, they also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas properties. We may be often outbid

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by competitors in our attempts to acquire properties. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations. In addition, the number of entities and the amount of funds competing for suitable investments may increase. Any such increase would result in increased demand for oil and gas properties and therefore increased prices paid for them. If we pay higher prices for properties and other investments, our profitability will be reduced and our unitholders may experience a lower return on their investments.

Failure to succeed in new markets may have adverse consequences on our performance.

We may from time to time make acquisitions outside of areas of our primary focus if appropriate opportunities arise. Our experience in our primary areas in owning and operating certain classes of oil and gas property does not ensure that we will be able to operate successfully in other areas, should we choose to enter them. We may be exposed to a variety of risks if we choose to enter new areas, including an inability to evaluate accurately local geological conditions or to identify appropriate acquisition opportunities, or to hire and retain key personnel, and a lack of familiarity with local governmental and permitting procedures. In addition, we may abandon opportunities to enter new areas that we have begun to explore for any reason and may, as a result, fail to recover expenses already incurred.

Our hedging transactions will expose us to counterparty credit risk.

We expect to engage in hedging transactions to reduce, but not eliminate, the effect of volatility in oil, gas and other hydrocarbon prices. Our hedging transactions will expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions.

During periods of falling commodity prices, such as those that occurred in late 2008 and 2012, our hedge receivable positions could increase, which increases our exposure to loss. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay cash distributions to holders of our Common Units.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil, natural gas and other hydrocarbons, we expect to enter into hedging arrangements for a significant portion of our estimated future production. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

Our ability to use hedging transactions to protect us from future price declines will depend on oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, which could cause our future net cash flows to be more sensitive to commodity price changes. Additionally, it may not be possible or economic to hedge all of the hydrocarbons we want to hedge because of the lack of a market for such hedges or other reasons. We may hedge certain hydrocarbons we produce by entering into swaps, collars or other contracts covering hydrocarbons we consider to be priced similarly to the hydrocarbons we produce, and we could be subject to losses if the prices for the hydrocarbons we produce do not match the hydrocarbons we contract for.

Our policy will be to hedge a portion, not to exceed 75%, of our near-term estimated production. However, our price hedging strategy and future hedging transactions will be recommended by the Manager under the Management Agreement and will be subject to the approval of our General Partner, which is not under an obligation to hedge any of our production. The prices at which we hedge our production will depend on commodity prices at the time we enter into those transactions, which may be substantially higher or lower than current oil, natural gas and other hydrocarbon prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil, natural gas and natural gas liquids revenues becoming more sensitive to commodity price changes. Neither our General Partner nor the Manager will be liable for any losses we incur as a result of our hedging policy or the implementation of that policy.

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The derivatives provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, and related rules adopted and to be adopted by federal regulators could adversely affect our ability to use derivatives to mitigate the commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, has created a new regulatory framework for derivative transactions, or generally referred to as swaps, including oil and gas hedging transactions and interest rate swaps. The Commodity Futures and Trading Commission, or the CFTC, federal banking regulators and the SEC have adopted and continue to adopt rules to implement the new law. Under the new law, parties to swaps of types designated by the CFTC for clearing on a derivatives clearing organization may have to clear those swaps and, in certain instances, execute trades in those swaps on other facilities. We would have to post collateral in connection with any swaps, including commodities swaps, that we must clear. The new law provides an exception from its clearing and trade execution requirements for swaps entered into by persons that are not “financial entities” (as defined in the new law) to hedge or mitigate their commercial risks. We intend to elect that exception for our swaps whenever possible. If we were characterized as a “financial entity,” however, we would be ineligible to elect that exception for the swaps we enter into. In that circumstance our ability to execute our hedging program efficiently could be adversely affected. Even if we are able to take advantage of the exception for persons that are not “financial entities,” the CFTC and banking regulators are in the process of adopting rules that will impose margin requirements for non-cleared swaps and that might require us to post cash or other collateral for such swaps.

Posting of cash collateral for either cleared or non-cleared swaps would reduce our liquidity, including our ability to use our cash for capital and other expenditures or distributions, and could reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect our cash flows. Even if we are not required to clear our swaps or to post cash or other collateral for all or some of our swaps, our contractual counterparties could pass their costs of complying with the new law on to their customers, including us. Moreover, a Dodd-Frank Act provision may result in one or more of our counterparties spinning-off their derivative operations into separate entities, and those entities may not be as creditworthy as our current counterparties. Current participants in the U.S. derivatives market may exit the market to avoid the new law and regulations. All of the changes in the U.S. derivative market resulting from the new law and regulations might not only increase the costs of operating our hedging program, but could also reduce the availability of some types of swaps that protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and potentially increase our exposure to less creditworthy counterparties. If, as a result of these factors, we were to reduce our use of swaps to hedge the commodity price, interest rate and other risks we encounter, our results of operations and cash flows may become more volatile and be otherwise adversely affected.

The potentially distressed financial conditions of our hydrocarbon purchasers could have an adverse impact on us in the event these purchasers are unable to pay us for our oil and gas production.

Some of our hydrocarbon purchasers may experience severe financial problems in the future that could have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed hydrocarbon purchasers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our hydrocarbon purchasers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force the purchasers to reduce or curtail their future purchase of our production and services, which could have a material adverse effect on our results of operations and financial condition.

Our financial condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:


•	The Clean Air Act, or the CAA, and comparable state laws and regulations that impose obligations related to emissions of air pollutants;


•	the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;


•	the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

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•	the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal;


•	the Safe Drinking Water Act and state or local laws and regulations related to underground injection (including hydraulic fracturing);


•	the Oil Pollution Act, or OPA, which subjects responsible parties to liability for removal costs and damages arising from an oil spill in waters of the U.S.; and


•	emergency planning and community right to know regulations under Title III of CERCLA and similar state statutes which require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Failure to comply with these laws and regulations, including laws and regulations related to climate change and greenhouse gases, may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our drilling, production and transportation operations will be subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining and maintaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding resource conservation practices and the protection of correlative rights may affect our operations by limiting the quantity of oil, natural gas and natural gas liquids we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the drilling, production and transportation of oil, natural gas and natural gas liquids. While the cost of compliance with these laws is not expected to be material to our operations, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to holders of our Common Units and service our debt obligations could be adversely affected.

Climate change legislation or regulations restricting emissions of greenhouse gases, or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids we produce.

The U.S. Environmental Protection Agency, or the EPA, has adopted its so-called “GHG” tailoring rule” regarding greenhouse gases, or GHGs, that will phase in federal requirements for GHG emissions from new sources and modifications of existing sources and federal Title V operating permit requirements for all sources, based on their potential to emit specific quantities of GHGs. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements.

In 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. In 2010, the EPA published its amendments to the GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from these facilities was required on an annual basis beginning in 2012 for emissions occurring in 2011. When we acquire producing properties, we will have to evaluate whether our operations trigger these requirements and if so submit our reports.

Congress has previously considered legislation to reduce emissions of GHGs and many states have adopted or have considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions

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or major producers of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program do not appear to be moving forward in Congress. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes, earthquakes and floods), sea levels, arability of farmland, and water availability and quality. If such effects were to occur, the operations that we plan to engage in may be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of a large volume of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We anticipate that we will routinely use hydraulic fracturing techniques in drilling and completing most of the development wells we intend to drill on our properties, depending primarily on the area where the wells are situated and the targeted geological formation. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has repeatedly been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we acquire producing properties, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of drilling, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater releasing a progress report in December 2012 with a draft report of the study expected to be released in Spring 2015. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

Moreover, the EPA released an advanced notice of proposed rulemaking under the Toxic Substances Control Act related to the chemicals used in the fracturing process. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. The Bureau of Land Management has indicated that it will continue with rulemaking to regulate hydraulic fracturing on federal lands and the EPA has announced an initiative to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operations restrictions and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we ultimately are able to produce.

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In addition to the risk that such legislation could increase the costs and delay inherent in drilling wells, a prolonged moratorium or the prohibition of hydraulic fracturing imposed by a state or county could materially adversely affect the value of any undeveloped leasehold acreage we might own in that state or county.

We expect to be subject to regulation under New Source Performance Standards, or NSPS, and National Emissions Standards for Hazardous Air Pollutants, or NESHAP programs, which could result in increased operating costs.

In 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation. On December 19, 2014, the EPA finalized updates and clarifications to these final rules. The EPA rules include standards for completions of hydraulically fractured natural gas wells. Prior to January 1, 2015, these standards required owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using “green completions” with a completion combustion device. The EPA updates to the rules identified two distinct stages of a well completion operation known as “flowback,” with specific requirements for handling gas and liquids during each stage, including clarifying when green completion equipment must be used. Beginning January 1, 2015, for wells in the second “separation flowback stage,” operators must capture the natural gas from these wells and make it available for use or sale, which can be done through the use of a separator, also known as green completion equipment. Wells not subject to the green completion requirements, such as exploratory wells, must flare the gas during separation. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the final regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. The EPA received numerous requests for reconsideration of these rules, and court challenges to the rules were also filed. The December 2014 updates responded to some of the issues raised in those requests. Additionally, in April 2013, the EPA published a proposed amendment related to certain storage vessels. The EPA has stated that it is continuing to evaluate other issues raised in the requests, and therefore further updates, clarifications or revisions may be issued. These rules and any revised rules may require the installation of equipment to control emissions on producing properties we acquire.

We may encounter obstacles to marketing our oil, natural gas and other hydrocarbons, which could adversely impact our revenues.

The marketability of our production will depend in part on the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities that we expect to be owned by third-parties. Transportation space on the gathering systems and pipelines we expect to utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil, natural gas and natural gas liquids, the value of our Common Units and our ability to pay distributions on our Common Units and service our debt obligations.

Discovery of previously undetected environmentally hazardous conditions may adversely affect our operating results.

Under various federal, state and local environmental laws, ordinances and regulations, a current or previous owner or operator of real property, including oil and gas properties, may be liable for the cost of removal or remediation of hazardous or toxic substances on, under or in the property. The costs of removal or remediation could be substantial. These laws often impose liability whether or not the owner or operator knew of, or was responsible for, the presence of hazardous or toxic substances. Environmental laws also may impose restrictions on the manner in which property may be used or businesses may be operated, and compliance with these restrictions may require substantial expenditures. Environmental laws provide for sanctions for noncompliance and may be enforced by governmental agencies or, in certain circumstances, by private parties. Certain environmental laws and common law principles could be used to impose liability for release of and exposure to hazardous substances, and third parties may seek recovery from owners or operators of real properties for personal injury or property damage associated with exposure to released hazardous substances.

The costs of defending against claims of environmental liability or of paying personal injury claims could reduce the amounts available for distribution to our unitholders.

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Costs of complying with governmental laws and regulations related to environmental protection and human health and safety may reduce our net income and the cash available for distributions to our unitholders.

Our operations are subject to federal, state and local laws and regulations relating to protection of the environment and human health. We could be subject to liability in the form of fines, penalties or damages for noncompliance with these laws and regulations. These laws and regulations generally govern wastewater discharges, air emissions, the operation and removal of underground and above-ground storage tanks, the use, storage, treatment, transportation and disposal of solid and hazardous materials, the remediation of contamination associated with the release or disposal of solid and hazardous materials, the presence of toxic building materials, and other health and safety-related concerns.

Some of these laws and regulations may impose joint and several liability on the owners or operators of oil and gas properties for the costs to investigate or remediate contaminated properties, regardless of fault, whether the contamination occurred prior to purchase, or whether the acts causing the contamination were legal. The operations of our properties, the condition of properties at the time we buy them, operations in the vicinity of our properties, such as the presence of existing or plugged wells, or activities of unrelated third parties may affect our properties.

The presence of hazardous substances, or the failure to properly manage or remediate these substances, may hinder our ability to sell or pledge a property as collateral for future borrowings. Environmental laws also may impose liens on a property or restrictions on the manner in which the property may be used or operated, and these restrictions may require substantial expenditures or prevent us or the Manager from operating the property. Some of these laws and regulations have been amended so as to require compliance with new or more stringent standards as of future dates, which may require us to incur material expenditures. Future laws, ordinances or regulations may impose material environmental liability. Any material expenditures, fines, penalties, or damages we must pay will reduce our ability to make distributions and may reduce the value of our unitholders’ investments.

The failure of any bank in which we deposit our funds could reduce the amount of cash we have available to pay distributions and make additional investments.

We intend to diversify our cash and cash equivalents among several banking institutions in an attempt to minimize exposure to any one of these entities. However, the Federal Deposit Insurance Corporation, or FDIC, only insures amounts up to $250,000 per depositor per insured bank. We expect to have cash and cash equivalents and restricted cash deposited in certain financial institutions in excess of federally insured levels. If any of the banking institutions in which we have deposited funds ultimately fails, we may lose our deposits over $250,000. The loss of our deposits could reduce the amount of cash we have available to distribute or invest and could result in a decline in the value of our unitholders’ investments.

Retirement Plan Risks

If the fiduciary of an employee pension benefit plan subject to the Employee Retirement Income Security Act of 1974, or ERISA (such as a profit-sharing, Section 401(k) or pension plan) or any other retirement plan or account fails to meet the fiduciary and other standards under ERISA, or the Internal Revenue Code, or the Code, as a result of an investment in our Common Units, the fiduciary could be subject to criminal and civil penalties.

There are special considerations that apply to employee benefit plans subject to ERISA (such as profit-sharing, Section 401(k) or pension plans) and other retirement plans or accounts subject to Section 4975 of the Code (such as an IRA) that are investing in our Common Units. Fiduciaries investing the assets of such a plan or account in our Common Units should satisfy themselves that:


•	the investment is consistent with their fiduciary obligations under ERISA and the Code;


•	the investment is made in accordance with the documents and instruments governing the plan or IRA, including the plan’s or account’s investment policy;


•	the investment satisfies the prudence and diversification requirements of Sections 404(a)(1)(B) and 404(a)(1)(C) of ERISA and other applicable provisions of ERISA and the Code;


•	the investment will not impair the liquidity of the plan or IRA;


•	the investment will not produce an unacceptable amount of “unrelated business taxable income” for the plan or IRA;


•	the value of the assets of the plan can be established annually in accordance with ERISA requirements and applicable provisions of the plan or IRA; and


•	the investment will not constitute a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code.

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With respect to the annual valuation requirements described above, we expect to provide an estimated value for our Common Units prepared by a third party valuation expert annually. From the commencement of this offering until 18 months have passed without a sale in this offering of our Common Units, we expect to use the gross offering price of a Common Unit in this offering as the per Common Unit estimated value. This estimated value is not likely to reflect the proceeds a unitholder would receive on our liquidation or on the sale of the unitholder's Common Units, if the Common Units could be sold. Accordingly, we can make no assurances that the estimated value will satisfy the applicable annual valuation requirements under ERISA and the Code. The Department of Labor or the IRS may determine that a plan fiduciary or an IRA custodian is required to take further steps to determine the value of our Common Units. In the absence of an appropriate determination of value, a plan fiduciary or an IRA custodian may be subject to damages, penalties or other sanctions.

Failure to satisfy the fiduciary standards of conduct and other applicable requirements of ERISA and the Code may result in the imposition of civil and criminal penalties and could subject the fiduciary to equitable remedies. In addition, if an investment in our Common Units constitutes a non-exempt prohibited transaction under ERISA or the Code, the fiduciary or IRA owner who authorized or directed the investment may be subject to the imposition of excise taxes with respect to the amount invested. In the case of a non-exempt prohibited transaction involving an IRA owner, the IRA may be disqualified and all of the assets of the IRA may be deemed distributed and subject to tax.

Prospective investors with investment discretion over the assets of an IRA, employee benefit plan or other retirement plan or arrangement that is covered by ERISA or Section 4975 of the Code should carefully review the information in the section of our prospectus entitled “Investment by Tax-Exempt Entities and ERISA Considerations” and consult their own legal and tax advisors on these matters.

If a unitholder invests in our Common Units through an IRA or other retirement plan, the unitholder’s ability to withdraw required minimum distributions may be limited.

If a unitholder establishes an IRA or other retirement plan through which the unitholder invests in our Common Units, federal law may require the unitholder to withdraw required minimum distributions, or RMDs, from the plan in the future. We have substantial restrictions on our unitholders’ ability to sell their Common Units. As a result, a unitholder may not be able to sell the unitholder’s Common Units at a time in which the unitholder needs liquidity to satisfy the RMD requirements under the unitholder’s IRA or other retirement plan. Even if a unitholder is able to sell the unitholder’s Common Units, the sale may be at a price less than the price at which the Common Units were initially purchased. If the unitholder fails to withdraw RMDs from the unitholder’s IRA or other retirement plan, the unitholder may be subject to certain tax penalties.

Federal Income Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If we were to become subject to entity-level taxation for federal or state income tax purposes, taxes paid would reduce the amount of cash available for distribution.

Although the anticipated tax benefits of an investment in us depend largely on our treatment as a partnership for federal income tax purposes, we have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us. In this regard, current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. Also, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation.

If we were treated as a corporation for federal income tax purposes, distributions to you and the other investors would generally be taxed as corporate distributions, and in addition to U.S. federal income tax, we would likely also pay state income tax at varying rates. Accordingly, if an income tax or other entity-level tax is imposed on us, our cash available for distribution to our unitholders could be reduced. Also, in that event, no income, gain, loss, deduction or credit would flow from us to our other unitholders.

Changes in the law may reduce our unitholders' tax benefits from an investment in us.

Our unitholders' tax benefits from an investment in us may be affected by changes in the tax laws. For example, President Obama’s administration has previously proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, repeal of the election to expense intangible drilling costs in the year incurred (including the option to amortize intangible drilling costs over a 60 month period), repeal of the passive activity exception for working interests, repeal of the domestic manufacturing tax deduction for oil and gas companies; and an increase

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in the amortization period for geological and geophysical costs of independent producers. These proposals may or may not be enacted into law. Also, other changes in the tax laws could be made that would reduce our unitholders' tax benefits from an investment in us.

Our unitholders' deduction for intangible drilling costs may be limited for purposes of the Alternative Minimum Tax.

Under current tax law, our unitholders' alternative minimum taxable income in the year in which they invest in our Common Units cannot be reduced by more than 40% by their respective share of our deduction for intangible drilling costs.

Limited partners need passive income to use our deductions.

If a unitholder invests as an individual, the unitholder’s share of our deduction for intangible drilling costs will be a passive deduction that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, those unitholders may not have enough passive income from us or net passive income from their other passive activities, if any, in a taxable year to offset a portion or all of their passive deductions from their investments in our Common Units. However, any unused passive loss, including the deduction for intangible drilling costs, may be carried forward indefinitely by our unitholders to offset their passive income in subsequent taxable years.

Our unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Because holders of our Common Units will be treated as partners to whom we will allocate taxable income, which could

be different in amount than the amount of cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income even if they do not receive any cash distributions from us. Also, in any taxable year our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to their tax liability that results from that income.

Tax gain or loss on disposition of our Common Units could be more or less than expected.

If a unitholder sells the unitholder’s Common Units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Common Units. Prior distributions to a unitholder in excess of the total net taxable income the unitholder was allocated for a Common Unit, which decreased the unitholder’s tax basis in that Common Unit, will, in effect, become taxable income to the unitholder if the Common Unit is sold at a price greater than the unitholder’s tax basis in that Common Unit, even if the price is less than the unitholder’s original cost. Also, a substantial portion of the amount realized may be ordinary income. In addition, if a unitholder sells the unitholder’s Common Units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

Tax exempt entities and foreign persons face unique tax issues from owning Common Units that may result in adverse tax consequences to them.

Investment in Common Units by tax-exempt entities, such as IRAs, other retirement plans and non-U.S. persons raises issues unique to them. For example, most, if not substantially all, of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Similarly, most, if not substantially all, of our income allocable to non-U.S. persons will constitute effectively connected U.S. trade or business income, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in our termination for U.S. federal income tax purposes.

We will be considered to have terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our Common Units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all our unitholders and could result in a deferral of certain deductions allowable in computing our taxable income.

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Holders of Common Units may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in our Common Units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our executive offices are located in leased space at 405 Park Avenue, New York, New York 10022 and our telephone number is 212-415-6500.

We currently do not hold any oil and gas properties.

Item 3. Legal Proceedings.

We are not a party to, and none of our properties are subject to, any material pending legal proceedings.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

No public market currently exists for our Common Units, and a public market for our Common Units may never exist. As a result, our Common Units are, and may continue to be, illiquid. The Common Units have not been approved for quotation or trading on a national securities exchange. However, the General Partner will have the right upon the approval of its board of directors and the approval of the Manager to list the Common Units on a national securities exchange following the final closing date. In order to be approved for listing, the Common Units and the Partnership will be required to meet the listing standards of a national securities exchange. No assurances can be made that the Common Units will be approved for quotation or trading on a national securities exchange.

Pursuant to our Offering, we are selling up to 100.0 million Common Units at a per unit price of $20.00 (subject to certain discounts described in the prospectus).

Holders

As of February 28, 2015, we had 339,386 Common Units outstanding held by a total of 127 unitholders.

Distributions

Although the partnership agreement does not require that we make regular monthly or quarterly distributions, our General Partner intends to distribute on a monthly basis, commencing with the fourth whole month following the initial closing date, to the holders of Common Units cash equal to a non-compounded 6.0% annual rate, which begins to accrue on the initial closing date, or, if later, begins to accrue on the applicable closing date on which we accepted the subscription proceeds from the holders of Common Units, on the $20.00 original purchase price per Common Unit, which is a targeted annual distribution of $1.20 per Common Unit. All or a portion of the distributions made to holders of Common Units may be deemed a return of capital for U.S. Federal income tax.

There is no limitation on the amount of distributions that can be funded from offering proceeds or financing proceeds, except that we may not borrow funds for purposes of distributions, if the amount of those distributions would exceed our accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to those revenues. The determination of such revenues and costs shall be made in accordance with U.S. GAAP, consistently applied.

On September 19, 2014, our General Partner approved and authorized the distribution rate equal to $1.20 per annum based on the price of our Common Units. This distribution rate corresponds to a 6.0% annualized rate based on the unit price of $20.00 to be calculated based on unitholders of record each day during the applicable period at a rate of $0.00328767123 per day. The distributions will be deemed to accrue with respect to each unit commencing on the applicable closing date on which such unit was issued. As of December 31, 2014, we had a distribution payable of $29,598 for dividends accrued during the month of December 2014.



	Year Ended
	December 31, 2014
Distributions:
Distribution paid in cash	$	86,678
Total distributions	$	86,678
Source of distribution coverage:
Proceeds from issuance of Common Units	$	86,678		100	%
Cash flows used in operations	—			—
Total sources of distributions	$	86,678		100	%
Cash flows used in operations (GAAP)	$	(758,578	)
Net loss (GAAP)	$	(703,328	)

Recent Sale of Unregistered Equity Securities

We did not sell any equity securities that were not registered under the Securities Act.

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Use of Proceeds from Sales of Registered Securities

On May 8, 2014, the SEC declared effective our Registration Statement on Form S-1 (File No. 333-192852) filed under the Securities Act and we commenced our initial public offering, on a "reasonable best efforts" basis, of up to 100.0 million Common Units at a price per unit of up to $20.00. As of December 31, 2014, we had issued 290,414 Common Units for $5.5 million.

The following table reflects the offering costs associated with the issuance of Common Units:



	December 31, 2014
Selling commissions and dealer manager fees	$	306,764
Other offering costs	2,850,421
Total offering costs	$	3,157,185

The Dealer Manager may reallow the selling commissions and a portion of the dealer manager fees to participating broker-dealers.

We are responsible for organizational and offering costs from the ongoing Offering, excluding selling commissions and dealer manager fees, up to a maximum of 1.5% of gross proceeds received from our ongoing Offering of Common Units, measured at the end of the Offering. Organizational and offering costs in excess of the 1.5% cap as of the end of the Offering are the responsibility of our General Partner and the Manager. The General Partner will be allocated two-thirds of this 1.5% reimbursement cap and the Manager will be allocated one-third of such reimbursement cap. As of December 31, 2014, organizational and offering costs exceeded 1.5% of gross proceeds received from the Offering by approximately $2.9 million, due to the ongoing nature of the Offering and the fact that many expenses were paid before the Offering commenced.

As of December 31, 2014, our net offering proceeds, after deducting total organizational and offering costs, were approximately $2.3 million.

Item 6. Selected Financial Data.

The following selected financial data for the years ended December 31, 2014 and 2013 should be read in conjunction with the accompanying consolidated financial statements and related notes thereto and "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations" below:



	December 31,
Balance sheet data	2014		2013
Cash	$	2,643,155	$	209,469
Total current assets	$	3,574,012	$	771,421
Total current liabilities	$	2,120,129	$	873,942
Partners' equity (deficit)	$	1,453,883	$	(102,521	)



Cash Flow data	Year Ended December 31, 2014			For the period from October 30, 2013 (Inception) to December 31, 2013
Net cash provided by (used in) operating activities	$	(758,578	)	$	148,596
Net cash provided by financing activities	$	3,192,264		$	60,873

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Operating data	Year Ended December 31, 2014			Period from October 30, 2013 (Inception) to December 31, 2013
Total expenses	$	703,328		$	103,521
Net loss	$	(703,328	)	$	(103,521	)

Net loss per common unit (basic and diluted)*	$	(3.99	)	$	—
Weighted average common units outstanding (basic and diluted)	176,385			—

___________________________________________________

* Net loss per Common Unit is only calculated for the period subsequent to the initial closing date as no Common Units were outstanding prior to June 16, 2014.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this Form 10-K. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, actual results may differ materially from those expressed or implied by the forward-looking statements. Please see "Forward-Looking Statements" elsewhere in this report for a description of these risks and uncertainties.

Overview

We are a Delaware limited partnership formed on October 30, 2013. Our General Partner was formed in Delaware on October 30, 2013 and is wholly owned by the ARC Sponsor. The ARC Sponsor is under common control with AR Capital, LLC. In connection with the formation of the Partnership, the General Partner made an initial capital contribution in the amount of $20 for its general partner interest.

On May 8, 2014, the SEC declared effective our Registration Statement filed under the Securities Act and we commenced our Offering, on a "reasonable best efforts" basis, of up to 100.0 million Common Units at a per unit price of up to $20.00. The Offering is expected to end on May 8, 2016, or two years from the effectiveness of the Registration Statement (the "final termination date"). On June 16, 2014, we commenced business operations after raising $2.0 million of gross proceeds (the "initial closing"), the amount required for us to release equity proceeds from escrow, and began the Partnership's business activities, including the acquisition and development of producing and non-producing oil and gas properties, including drilling activities.

We have no officers, directors or employees. Instead, our General Partner manages our day-to-day affairs. All decisions regarding our management are made by the board of directors of the General Partner and its officers. We entered into a Management Agreement with the Manager. The General Partner will have full authority to direct the activities of the Manager under the Management Agreement. The Manager will provide us with management and operating services regarding substantially all aspects of operations. RCS serves as the Dealer Manager of the Offering.

Since our Registration Statement was declared effective by the SEC in May 2014, energy markets have experienced a rapid and severe decline in oil and natural gas prices. Oil prices have fallen from over $107 per barrel on June 20, 2014 to $44.96 on March 18, 2015. During the same period, natural gas prices have fallen from almost $5 per mmbtu to under $3 per mmbtu. The magnitude of these drops is striking and has likely set the stage for a recovery in 2016 or later, as supply and demand fundamentals react to the severe price drops and markets are rebalanced. One indication of investor sentiment is Standard & Poor’s index of eighty onshore oil and natural gas companies’ stock prices, which declined by over 30% in 2014 and recovered by 2.7% from January 1 through March 18, 2015. In January 2015, the Partnership was renamed to American Energy Capital Partners - Energy Recovery Program, LP in order to reflect the industry environment.

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Significant Accounting Estimates and Critical Accounting Policies

The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.

Organizational Costs

Organizational costs may include accounting, legal and regulatory fees incurred related to our formation. Organizational costs are expensed as incurred.

Offering and Related Costs

Offering and related costs include all expenses incurred in connection with our Offering. Our offering costs (other than selling commissions and the dealer manager fee) may be paid by the General Partner, its affiliates and the Manager on behalf of us. On May 8, 2014, the day we commenced our Offering, accumulated offering costs were reclassified from deferred costs to Partners' deficit. Offering costs may represent professional fees, fees paid to various regulatory agencies, and other costs incurred in connection with the registration and sale of our Common Units. We will reimburse the General Partner and the Manager in a combined amount of up to 1.5% of the aggregate proceeds of the Offering, payable two-thirds to the General Partner and one-third to the Manager. Neither the General Partner nor the Manager will be entitled to reimbursement for offering and organization expenses to the extent such combined expenses exceed 1.5% of the aggregate offering proceeds. (See Note 6 of the financial statements included elsewhere in this Form 10-K).

Net Loss Per Common Unit

Net loss per Common Unit is computed by dividing net loss applicable to Common Unit holders by the weighted average number of Common Units outstanding during the period. Net loss per Common Unit is only calculated for the period subsequent to the initial closing date as no Common Units were outstanding prior to June 16, 2014. Diluted net loss per Common Unit is the same as basic net loss per Common Unit as there were no potentially dilutive common or subordinated units outstanding as of December 31, 2014.

Taxes

We are a disregarded entity for tax purposes. We will generally pay no taxes but rather our activities will pass through to and be reflected on the tax returns of the partners.

The Partnership is subject to certain provisions of accounting standards related to uncertain tax positions. The Partnership has reviewed its pass-through status and determined no uncertain tax positions exist. There were no income taxes or penalty items for either period presented.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers ("ASU 2014-09")", which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. This ASU is effective for reporting periods beginning after December 15, 2016, and for interim and annual reporting periods thereafter. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures.

In August 2014, FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40), Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern," which requires management to evaluate whether there is substantial doubt about our ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, and for interim and annual reporting periods thereafter. Early application is permitted. We are currently evaluating the adoption of this ASU and its impact on the consolidated financial statements.

Results of Operations

We were formed to enable investors to invest, indirectly through us, in oil and gas properties located onshore in the United States. Our primary objectives are:


•	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;


•	to make distributions to the holders of our Common Units and, although our partnership agreement does not require us to make regular monthly or quarterly distributions, the General Partner intends to distribute on a monthly basis, commencing with the fourth whole month following the initial closing date, to the holders of

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Common Units cash equal to a non-compounded 6.0% annual rate, which begins to accrue on the initial closing date, or, if later, begins to accrue on the applicable closing date on which we accepted the subscription proceeds from the holder of Common Units, on the $20.00 original purchase price per Common Unit, or a targeted annual rate of $1.20 per unit, which we refer to as the targeted distribution;


•	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


•	to enable the holders of Common Units to invest in oil and gas properties in a tax efficient manner.

On June 16, 2014, we commenced business operations after raising $2.0 million of gross proceeds, the amount required for us to release equity proceeds from escrow. Because we have not acquired any assets, our management is not aware of any material trends or uncertainties, favorable or unfavorable, other than national economic conditions affecting our targeted portfolio generally, which may be reasonably anticipated to have a material impact on the capital resources and the revenue or income to be derived from the operation of our assets.

During the year ended December 31, 2014, we incurred total operating expenses of $703,328, primarily related to investment banking fees, directors and officers insurance expenses, management fees and other professional expenses. During the period from October 30, 2013 (inception) through December 31, 2013, we incurred total operating expenses of $103,521, primarily related to organizational costs.

Liquidity and Capital Resources

The General Partner plans to satisfy our liquidity requirements from the following:


•	subscription proceeds of the Offering;


•	cash flow from future operations; and


•	our borrowings, including the credit facility we intend to enter into the future.

If we require additional funds for cost overruns or additional development or remedial work after a well begins producing, then these funds may be provided by:


•	subscription proceeds, if available, which may result in us either acquiring fewer properties or drilling fewer wells, or both, or we may acquire a lesser ownership interest in one or more properties and wells;


•	additional borrowings under the credit facility we intend to obtain, which borrowings will not exceed at any given time an amount equal to 50% of our total capitalization as determined on an annual basis; or


•	retaining our revenues from operations or the proceeds from sales of our properties.

All borrowed amounts must be without recourse to investors. Also, we may enter into agreements and financial instruments relating to hedging up to 75% of our oil and natural gas production and pledging up to 100% of our assets and reserves in connection therewith. Our repayment of any borrowings would be from our production revenues or the sale of our properties and other assets and would reduce or delay our cash distributions to holders of Common Units.

Distributions

Although the partnership agreement does not require that we make regular monthly or quarterly distributions, the General Partner intends to distribute on a monthly basis, commencing with the fourth whole month following the initial closing date, to the holders of Common Units cash equal to a non-compounded 6.0% annual rate, which begins to accrue on the initial closing date, or, if later, begins to accrue on the date on which the subscription proceeds from the holders of Common Units, on the $20.00 original purchase price per Common Unit are accepted by us, or the targeted distribution at an annual rate of $1.20 per Common Unit. All or a portion of the distributions made to holders of Common Units may be deemed a return of capital for U.S. Federal income tax.

On September 19, 2014, the General Partner approved and authorized the distribution rate equal to $1.20 per annum based on the price of our Common Units. This distribution rate corresponds to a 6.0% annualized rate based on the unit price of $20.00 to be calculated based on unitholders of record each day during the applicable period at a rate of $0.00328767123 per day. The distributions will be deemed to accrue with respect to each unit commencing on the applicable closing date on which we accepted subscription proceeds for the unit and the unit was issued. As of December 31, 2014, we had a distribution payable of $29,598 for dividends accrued during the month of December 2014.

Manager and the Management Agreement

We entered into the Management Agreement with the Manager to provide us with management and operating services regarding substantially all aspects of operations. All services provided by the Manager will be under and subject to the supervision of the General Partner.

Under the Management Agreement, the Manager will provide management and other services to us, including the following:


•	identifying onshore producing and non-producing oil and gas properties that we may consider acquiring, and assisting us in evaluating, contracting for and acquiring these properties and managing the development of these properties;


•	investigating and evaluating financing alternatives for any property acquisition and the ownership, development and operations of assets, and any refinancing;


•	operating, or causing one of its affiliates to operate, on our behalf, any properties in which our interest in the property is sufficient to appoint the operator;


•	overseeing the operations on properties operated by persons other than the Manager, including recommending whether we should participate in the development of such properties by the operators of the properties;


•	arranging for the marketing, transportation, storage and sale of all natural gas, natural gas liquids and oil produced from properties and procuring all supplies, materials and equipment needed in order to perform lease operations;


•	taking any actions requested by us to prepare and arrange for all or any portion of our assets to be sold or otherwise disposed of or liquidated; and


•	establishing cash management and risk management, including hedging, programs for us, receiving the revenues from the sale of production from properties and paying operating expenses and approved capital expenses with respect to properties.

The Management Agreement provides that we, through the supervision of the General Partner, will direct the services provided under the Management Agreement, and that the Manager will determine the means or method by which those directions are carried out. The Management Agreement further provides that the Manager will conduct the day-to-day operations of the business as provided in draft budgets that the Manager will prepare and we, through the supervision of the General Partner, will have the right to approve and review on a quarterly basis. The Management Agreement also contains a list of activities in which the Manager will not engage without our and/or the General Partner's prior approval.

Commencing with a payment for the month of the initial closing, and for each month thereafter through the final termination date of the Offering, we will pay the Manager a monthly management fee equal to an annual rate of 3.5% of the sum of: (i) the capital contributions made by the holders of Common Units to us from the initial closing through the final termination date; and (ii) our average outstanding indebtedness during the preceding month.

For each month beginning with the first month following the final termination date of the Offering, we will pay a monthly management fee equal to an annual rate of 5.0%, which will be paid four-fifths to the Manager and one-fifth to the General Partner, of the sum of: (i) the capital contributions made by the holders of Common Units to us; and (ii) the average outstanding indebtedness during the preceding month.

The management fee includes the Manager’s general and administrative overhead expenses and the Manager will not receive a separate reimbursement of its general and administrative expenses from any source other than the monthly management fee. However, the Manager will receive reimbursement of its direct expenses paid to third-parties.

In conjunction with the acquisition cost of producing and non-producing oil and gas properties (excluding any properties we may elect to acquire from the Manager or an affiliate of the Manager), the Manager will be entitled to receive an acquisition fee equal to 2% of the contract price for each property acquired. The Manager will also be entitled to reimbursements of acquisition expenses for each property acquired, with the aggregate amount of the acquisition fee and reimbursement of acquisition expenses not to exceed 3% of the contract price for each property acquired.

When the Manager operates our properties pursuant to a model form operating agreement, it will receive reimbursement at actual cost for all direct expenses incurred by it on behalf us, including expenses to gather, transport, process, treat and market our oil and natural gas production; and well supervisory fees at competitive rates for maintaining and operating the wells during drilling and producing operations.

In conjunction with the disposition of our producing and non-producing oil and gas properties and in consideration for the services to be performed by the Manager and the General Partner in connection with the disposition of our properties from time to time, the Manager and the General Partner will receive reimbursement for their respective costs incurred in connection with such activities, plus a fee equal to 1.0% of the contract sales price of the properties (excluding any properties acquired from us

by the General Partner, the Manager, or their respective affiliates), (including when paid any deferred payment or "earn out" amounts), which will be paid one-half (0.5%) to each of the Manager and the General Partner. (See Note 6 of the financial statements included elsewhere in this Form 10-K).

In conjunction with the financing of our producing and non-producing oil and gas properties and operations (other than the Offering described in the Registration Statement, but including our initial revolving credit facility) and in consideration for the services to be performed by the General Partner and the Manager in connection therewith, the General Partner and the Manager will receive a financing coordination fee equal to 0.75% of the principal amount of any financing (as we draw it down if it is not 100% funded in a single closing), which will be paid two-thirds (0.5%) to the Manager and one-third (0.25%) to the General Partner. (See Note 6 of the financial statements included elsewhere in this Form 10-K).

During the year ended December 31, 2014, $49,600 had been incurred by the Manager for monthly management fee services under the Management Agreement. During the period from October 30, 2013 (inception) through December 31, 2013, no fees were incurred by the Manager for services under the Management Agreement.

On February 17, 2015 Chesapeake Energy Corporation (“CHK”) filed suit in the District Court of Oklahoma County, Oklahoma against American Energy Partners, LP (“AELP”), and certain other affiliates of the Manager. CHK alleged that Aubrey K. McClendon misappropriated confidential information and trade secrets from CHK, which he subsequently used for the benefit of AELP and the named AELP affiliates. CHK’s claims against AELP and the AELP affiliates include violation of the Oklahoma Uniform Trade Secrets Act, aiding and abetting in Mr. McClendon’s breach of fiduciary duty and usurpation of corporate opportunities, and tortious interference with CHK’s prospective business relationships and CHK seeks an unspecified dollar amount of damages, punitive damages, and a permanent injunction from using CHK’s trade secret information and other relief. Mr. McClendon, AELP, the named AELP affiliates and The Energy and Minerals Group, a primary equity sponsor of AELP affiliates, immediately countered the CHK filing with separate statements asserting that CHK’s claims are baseless and without merit and that they intend to defend themselves vigorously against CHK’s lawsuit and the claims therein. There are no claims asserted against the Manager and we do not believe that this matter will have a material adverse effect on our operations, financial condition or prospects.

Cash Flows

Net cash used in operating activities for the year ended December 31, 2014 was $758,578. During the year ended December 31, 2014, cash inflows from operating activities included an increase in due to affiliate of $924,485 and management fee payable of $23,860. These cash inflows were offset by cash outflows that consisted of a net loss of $703,328 and an increase in accounts payable and accrued expenses of $72,738, prepaid expenses and other assets of $112,328 and deferred affiliated costs of $818,529.

Net cash provided by financing activities for the year ended December 31, 2014 was $3,192,264. The level of cash provided by or used in financing activities will mainly be driven by sales of our Common Units during the Offering. Cash inflows for the year ended December 31, 2014 primarily included $5,534,173 from the issuance of Common Units, which was partially offset by the payment of $1,632,426 of offering costs.

Related Party Arrangements

Fees Paid in Connection with the Offering

Realty Capital Securities, LLC, an entity which is under common control with the ARC sponsor, is the Dealer Manager. The Dealer Manager will receive fees and compensation in connection with the sale of the Common Units. The Dealer Manager will receive a selling commission of up to 7.0% of the gross proceeds of the Offering. In addition, the Dealer Manager will receive up to 3.0% of the gross proceeds of the Offering as a dealer manager fee. During the year ended December 31, 2014, $306,764 of commissions and fees were incurred from the Dealer Manager. During the period from October 30, 2013 (inception) to December 31, 2013, no commissions and fees were incurred from the Dealer Manager.

The General Partner, its affiliates and the Manager receive compensation and reimbursement for services relating to the Offering, including transfer agency services provided by an affiliate of the Dealer Manager.

We are responsible for organizational and offering costs from the ongoing Offering, excluding selling commissions and dealer manager fees, up to a maximum of 1.5% of gross proceeds received from our ongoing Offering of Common Units, measured at the end of the Offering. Organizational and offering costs in excess of the 1.5% cap as of the end of the Offering are the responsibility of the General Partner and the Manager. The General Partner will be allocated two-thirds of this 1.5% reimbursement cap and the Manager will be allocated one-third of such reimbursement cap. As of December 31, 2014, organizational and offering costs exceeded 1.5% of gross proceeds received from the Offering by $2,870,873, due to the ongoing nature of the Offering and the fact that many expenses were paid before the Offering commenced.

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Partner or the Manager for costs incurred by us. During the period from October 30, 2013 (inception) to December 31, 2013, $6,137 of related party costs were incurred by the Partnership and due to affiliates in connection with the Offering. As of December 31, 2013, we had a payable of $621,825 to the General Partner for costs incurred by the Partnership.

Fees paid in Connection with Operations of the Partnership

We will reimburse the General Partner on a monthly basis for its allocable portion of administrative costs and third-party expenses it incurs or payments it makes on our behalf. Administrative costs include all customary and routine expenses incurred by the General Partner for the conduct of our administration, including legal, finance, accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative costs do not include any organization and offering expenses incurred by the General Partner and its affiliates. Administrative costs and other charges for goods and services must be fully supportable as to the necessity thereof and the reasonableness of the amount charged. During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) through December 31, 2013, no administrative costs of the General Partner were reimbursed in connection with our operations.

In conjunction with the disposition of our producing and non-producing oil and gas properties and in consideration for the services to be performed by the General Partner in connection with the disposition of our properties from time to time, the General Partner will receive reimbursement for its costs incurred in connection with such activities, plus a fee equal to 0.5% of the contract sales price (excluding any properties acquired from the us by the General Partner, the Manager, or their respective affiliates), (including when paid any deferred payment or “earn out” amounts), payable in cash concurrently with the Manager's 0.5% disposition fee for a total of 1.0%. (See Note 3 of the financial statements included elsewhere in this Form 10-K). During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) through December 31, 2013, no disposition fees were reimbursed to the General Partner in connection with our operations.

In conjunction with the financing of our producing and non-producing oil and gas properties and operations (other than the Offering described in the prospectus, but including our initial revolving credit facility) and in consideration for the services to be performed by the General Partner in connection therewith, the General Partner will receive a financing coordination fee equal to 0.25% of the principal amount of any financing (as we draw it down if it is not 100% funded in a single closing), payable in cash concurrently with the Manager's 0.5% financing coordination fee for a total of 0.75%. (See Note 3 of the financial statements included elsewhere in this Form 10-K). During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) through December 31, 2013, no financing fees were paid to the General Partner in connection with our operations.

During the year ended December 31, 2014, $105,956 of related party costs were incurred and payable by us in connection with our operations. Of this amount, $101,471 was incurred related to the strategic advisory services and investment banking services in connection with the advisory agreement with our Dealer Manager as defined below.

Advisory Fee

Effective November 12, 2014, we entered into an agreement with the Dealer Manager to provide strategic advisory services and investment banking services required in the ordinary course of our business, such as performing financial analysis, evaluating publicly traded comparable companies and assisting in developing a portfolio composition strategy, a capitalization structure to optimize future liquidity options and structuring operations. We have accrued and will amortize the cost of $920,000 associated with this agreement over the estimated life of the Offering into "Other expense" on our consolidated statements of operations. During the year ended December 31, 2014, $101,471 was incurred for the above services. As of December 31, 2014, the $920,000 payable to the Dealer Manager is included in due to affiliates on our consolidated balance sheets.

Incentive Distribution Rights

On the initial closing date, we issued incentive distribution rights to the General Partner and AECP Holdings, LLC ("Holdings"). The incentive distribution rights were issued 50% to the General Partner and 50% to Holdings.

Upon a sale of all or substantially all of the our properties, the General Partner and Holdings will each be entitled to receive a one-time incentive performance payment in cash equal to 12.5% each of the aggregate sale price of the properties net of expenses and of the payment of all our debts and obligations, minus the excess, if any, of $20.00 per Common Unit (the original purchase price per Common Unit) of all outstanding Common Units, less the aggregate amounts previously distributed after the final termination date of the Offering on the outstanding Common Units.

Upon a listing of the Common Units on a national securities exchange, the General Partner and Holdings will each be entitled to receive either newly issued Common Units or newly issued subordinated units. In either case, the amount received will be equal to 12.5% of the aggregate listing performance distribution amount for all units outstanding divided by the current market price. In addition, the incentive distribution rights held by the General Partner and Holdings will entitle them to receive increasing percentages of distributions made on the Common Units above the targeted minimum quarterly distributions, which will be determined and established upon a listing of the Common Units.

Off-Balance Sheet Arrangements

As of December 31, 2014, we had no off-balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

On June 16, 2014, we commenced business operations. However, because we had not acquired any assets, borrowed any funds or purchased or sold any derivative, as of December 31, 2014, we are currently not exposed to interest rate or foreign currency market risks.

Item 8. Financial Statements and Supplementary Data.

The information required by this Item 8 is hereby incorporated by reference to our Consolidated Financial Statements beginning on page F-1 of this Form 10-K.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-K and determined that our disclosure controls and procedures are effective as of the end of the period covered by the Form 10-K. During the most recently completed fiscal quarter, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

This Form 10-K does not include a report of management's assessment regarding internal control over financial reporting due to a transition period established by the rules of the SEC for newly public companies. This Form 10-K does not include an attestation report of the Partnership's registered public accounting firm regarding internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Directors and Executive Officers of the General Partner

The general partner has a board of directors composed of two individuals and three executive officers as listed in the table below.



Name	Age	Position
William M. Kahane	66	Chief Executive Officer, President and Director
Nicholas Radesca	49	Chief Financial Officer and Treasurer
Peter M. Budko	55	Executive Vice President and Secretary
Nicholas S. Schorsch	54	Director

Nicholas S. Schorsch has served as a director of our general partner since its formation in October 2013. Mr. Schorsch has also served as chairman of the board of directors of AR Capital Acquisition Corp. since August 2014. Mr. Schorsch served as chairman of the board of directors of American Realty Capital Trust V, Inc. ("ARCT V") from its formation in January 2013 until February 2015 and served as chief executive officer of ARCT V from its formation until December 2014. Mr. Schorsch served as the chairman of American Realty Capital Global Trust, Inc. ("ARC Global") from its formation in July 2011 until February 2015 and served as its chief executive officer of ARC Global from its formation until October 2014. Mr. Schorsch served as chief executive officer of American Realty Capital Properties, Inc. (“ARCP”) from its inception in December 2010 until October 2014 and served as the chairman of the Board of Directors of ARCP from its inception until December 2014. Mr. Schorsch served as executive chairman of the board of directors of RCS Capital Corp. ("RCAP") from February 2013 until December 2014. Mr. Schorsch served as chairman of the board of directors of American Realty Capital Trust, Inc. (“ARCT”) from August 2007 until January 2013, when ARCT closed its merger with Realty Income Corporation (NYSE: O); and as the chief executive officer of ARCT from its formation in August 2007 until March 2012. Mr. Schorsch served as chairman and chief executive officer of New York REIT, Inc., (“NYRT”) from its formation in October 2009 until December 2014. Mr. Schorsch served as the chairman and the chief executive officer of American Realty Capital - Retail Centers of America, Inc. (“ARC RCA”) from its formation in July 2010 until December 2014. Mr. Schorsch served as the executive chairman of the board of American Realty Capital Healthcare Trust, Inc. (“ARC HT”) from March 2014 until January 2015 when HCT closed its merger with Ventas, Inc. (NYSE: VTR) and served as the chairman and the chief executive officer of ARC HT from its formation in August 2010 until March 2014. Mr. Schorsch served as chairman and the chief executive officer of Business Development Corporation of America (“BDCA”) from its formation in May 2010 until December 2014 and Business Development Corporation of America II (“BDCA II”) from April 2014 until December 2014. Mr. Schorsch served as the chairman and chief executive officer of American Realty Capital Daily Net Asset Value Trust, Inc. (“ARC DNAV”) from its formation in September 2010 until December 2014. Mr. Schorsch served as chairman and chief executive officer of American Realty Capital Trust III, Inc. (“ARCT III”) from its formation in October 2010 until the close of ARCT III’s merger with ARCP in February 2013. Mr. Schorsch also served as the chief executive officer and chairman of the board of directors of American Realty Capital Trust IV, Inc. (“ARCT IV”), beginning with its formation in February 2012 until the closing of the merger of ARCT IV with ARCP in January 2014. Mr. Schorsch served as the executive chairman of the board of directors of American Realty Capital Healthcare Trust II, Inc. (“ARC HT II”) from March 2014 until December 2014 and previously served as chairman of the board of ARC HT II from its formation in October 2012 until March 2014. Mr. Schorsch served as the chairman of the board of directors of ARC Realty Finance Trust, Inc. (“ARC RFT”) from November 2012 until November 2014. Mr. Schorsch served as chief executive officer of the advisor to Phillips Edison Grocery Center REIT II, Inc. (“PE-ARC II”) from July 2013 until December 2014. Mr. Schorsch served as the chairman of the board of directors of American Realty Capital Hospitality Trust, Inc. (“ARC HOST”) from its formation in July 2013 until December 2014. Mr. Schorsch has served as chief executive officer of the advisor to United Development Funding Income Fund V (“UDF V”) since September 2013. Mr. Schorsch served as chief executive officer of American Realty Capital New York City REIT, Inc. (“ARC NYCR”) from its formation in December 2013 until November 2014 and as chairman of the board of directors of ARC NYCR from its formation until December 2014. Mr. Schorsch served as chairman of Cole Credit Property Trust, Inc., Cole Credit Property Trust IV, Inc., Cole Credit Property Trust V, Inc., Cole Real Estate Income Strategy (Daily NAV), Inc., Cole Corporate Income Trust, Inc. and Cole Office & Industrial REIT (CCIT II), Inc. from the close of ARCP’s acquisition of Cole Real Estate Investments, Inc. (“Cole”) in February 2014 until December 2014. From September 2006 to July 2007, Mr. Schorsch was chief executive officer of American Realty Capital, a real estate investment firm. Mr. Schorsch founded and formerly served as president, chief executive officer and vice chairman of American Financial Realty Trust (“AFRT”) from its inception as a REIT in September 2002 until August 2006. AFRT was a publicly traded REIT (which was listed on the NYSE within one year of its inception) that invested exclusively in offices, operation centers, bank branches, and other operating real estate assets that were net leased to tenants in the financial services industry, such as banks and insurance companies. Through American Financial Resource

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Group (“AFRG”) and its successor corporation, AFRT, Mr. Schorsch executed in excess of 1,000 acquisitions, both in acquiring businesses and real estate property with transactional value of approximately $5.0 billion, while also operating offices in Europe that focused on sale and leaseback and other property transactions in Spain, France, Germany, Finland, Norway and the United Kingdom. In 2003, Mr. Schorsch received an Entrepreneur of the Year award from Ernst & Young. From 1995 to September 2002, Mr. Schorsch served as chief executive officer and president of AFRG, AFRT’s predecessor, a private equity firm founded for the purpose of acquiring operating companies and other assets in a number of industries. Prior to AFRG, Mr. Schorsch served as president of a non-ferrous metal product manufacturing business, Thermal Reduction Corporation. He successfully built the business through mergers and acquisitions and ultimately sold his interests to Corrpro (NYSE) in 1994. Mr. Schorsch attended Drexel University.

William M. Kahane has served as the chief executive officer and president of our general partner since November 2014. Mr. Kahane has served as a director of ARC NYCR since its formation in December 2013 and was appointed as executive chairman in December 2014. Mr. Kahane has served as the chief executive officer and president of ARC DNAV since November 2014 and was appointed as a director and as chairman of the board of directors of ARC DNAV in December 2014. Mr. Kahane also previously served as a director of ARC DNAV from September 2010 until March 2012 and as chief operating officer and secretary of ARC DNAV from November 2014 until December 2014. Mr. Kahane has served as an executive officer of ARCT V since November 2014 and in December 2014 was appointed as chief executive officer. Mr. Kahane has served as chairman of ARCT V since February 2015. Mr. Kahane served as chief operating officer, treasurer and secretary of ARC Global from October 2014 until February 2015. Mr. Kahane was appointed as executive chairman of ARC Global in February 2015. Mr. Kahane has served as the executive chairman of the board of directors of American Realty Capital Global Trust II, Inc. (“ARC Global II”) since December 2014. Mr. Kahane previously served as the chief operating officer, treasurer and secretary of ARC Global II from October 2014 until December 2014. Mr. Kahane was appointed a director of ARC HOST in February 2014 and was appointed as executive chairman in December 2014. Mr. Kahane previously served as the chief executive officer and president of ARC HOST from August 2013 to November 2014. Mr. Kahane has served as a director of ARC RFT since November 2014 and was appointed as chairman in December 2014. Mr. Kahane has served as a director of ARC RCA since its formation in July 2010 and also served as an executive officer of ARC RCA from its formation in July 2010 until March 2012 and from November 2014 to December 2014, Mr. Kahane served as chief operating officer and secretary of ARC RCA. Mr. Kahane has served as the president of ARC RCA since November 2014 and was appointed as the chairman of the board of directors of ARC RCA and the chief executive officer of ARC RCA in December 2014. Mr. Kahane was appointed as a director and as the chairman of the board of directors of American Realty Capital - Retail Centers of America II, Inc. (“ARC RCA II”) in December 2014 and has served as chief executive officer of ARC RCA II since November 2014. Mr. Kahane has served as the president of ARC RCA II since October 2014. Mr. Kahane previously served as chief operating officer and secretary of ARC RCA II from October 2014 to December 2014. Mr. Kahane was appointed as a director and executive chairman of the board of directors of American Realty Capital Healthcare Trust III, Inc. (“ARC HT III”) in December 2014. Mr. Kahane has served as chief executive officer and director of AR Capital Acquisition Corp. since August 1, 2014. Mr. Kahane served as a director of ARCP from February 2013 to June 2014. He also served as a director and executive officer of ARCP from December 2010 until March 2012. Mr. Kahane served as an executive officer of ARCT from its formation in August 2007 until the close of ARCT’s merger with Realty Income Corporation in January 2013. He also served as a director of ARCT from August 2007 until January 2013. Mr. Kahane has also served as a director of NYRT since its formation in October 2009 and was appointed as executive chairman in December 2014. Mr. Kahane also previously served as president and treasurer of NYRT from its formation in October 2009 until March 2012. Mr. Kahane served as a director of ARC HT from its formation in August 2010 until the completion of its merger with Ventas, Inc. in January 2015. Mr. Kahane previously served as an executive officer of ARC HT from its formation until March 2012. Mr. Kahane served as an executive officer of ARCT III from its formation in October 2010 until April 2012. Mr. Kahane has served as a director of ARC HT II since March 2013 and was appointed as executive chairman in December 2014. Mr. Kahane served as a director of PECO II from August 2013 until January 2015. Mr. Kahane also has been the interested director of BDCA since its formation in May 2010 and BDCA II since April 2014. Until March 2012, Mr. Kahane was also chief operating officer of BDCA. Mr. Kahane served as a director of RCAP from February 2013 until December 2014, and served as chief executive officer of RCAP from February 2013 until September 2014. Mr. Kahane has served as a director of Cole Real Estate Income Strategy (Daily NAV), Inc. from February 2014 until December 2014, and served as a director of Cole Credit Property Trust, Inc. from May 2014 until February 2014. Mr. Kahane has served as a member of the investment committee of Aetos Capital Asia Advisors, a $3 billion series of opportunistic funds focusing on assets primarily in Japan and China, since 2008. Mr. Kahane began his career as a real estate lawyer practicing in the public and private sectors from 1974 to 1979 where he worked on the development of hotel properties in Hawaii and California. From 1981 to 1992, Mr. Kahane worked at Morgan Stanley & Co., or Morgan Stanley, specializing in real estate, including the lodging sector becoming a managing director in 1989. In 1992, Mr. Kahane left Morgan Stanley to establish a real estate advisory and asset sales business known as Milestone Partners which continues to operate and of which Mr. Kahane is currently the chairman. Mr. Kahane worked very closely with Mr. Schorsch while a trustee at American Financial Realty Trust, or AFRT, from April 2003 to August 2006, during which time Mr. Kahane served as chairman of the finance committee of AFRT’s board of trustees. Mr. Kahane served as a managing director of GF Capital Management &

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Advisors LLC, or GF Capital, a New York-based merchant banking firm, where he directed the firm’s real estate investments, from 2001 to 2003. GF Capital offers comprehensive wealth management services through its subsidiary TAG Associates LLC, a leading multi-client family office and portfolio management services company with approximately $5 billion of assets under management. Mr. Kahane also was on the board of directors of Catellus Development Corp., a NYSE growth-oriented real estate development company, where he served as chairman. Mr. Kahane received a B.A. from Occidental College, a J.D. from the University of California, Los Angeles Law School and an MBA from Stanford University’s Graduate School of Business.

Nicholas Radesca has served as chief financial officer and treasurer of our general partner since October 2013. Mr. Radesca has also served as the chief financial officer of ARC DNAV since January 2014, as chief financial officer of ARCT V since January 2014, as chief financial officer and treasurer of ARC RFT since January 2013, as chief financial officer and treasurer of BDCA since February 2013 and chief financial officer, treasurer and secretary of AR Capital Acquisition Corp since August 1, 2014. Mr. Radesca served as the chief financial officer of ARC RCA from May 2014 until December 2014, as the chief financial officer of ARC RCA II from its formation until December 2014, as the interim chief financial officer, treasurer and secretary of ARC HOST from May 2014 until December 2014. Prior to joining American Realty Capital in December 2012, Mr. Radesca was employed by Solar Capital Management, LLC, from March 2008 to May 2012, where he served as the chief financial officer and corporate secretary for Solar Capital Ltd. and its predecessor company, and Solar Senior Capital Ltd., both of which are publicly traded business development companies. From 2006 to February 2008, Mr. Radesca served as the chief accounting officer at iStar Financial Inc. (“iStar”), a publicly traded commercial REIT, where his responsibilities included overseeing accounting, tax and SEC reporting. Prior to iStar, Mr. Radesca served in various senior accounting and financial reporting roles at Fannie Mae, Del Monte Foods Company, Providian Financial Corporation and Bank of America. Mr. Radesca has more than 20 years of experience in financial reporting and accounting and is a licensed certified public accountant in New York and Virginia. Mr. Radesca holds a B.S. in accounting from the New York Institute of Technology and an M.B.A. from the California State University, East Bay.

Peter M. Budko has served as executive vice president and secretary of our general partner since its formation in October 2013. He has also served as director and chairman of Business Development Corporation of America (“BDCA”) since December 2014, and as an executive officer of BDCA since May 2010. Mr. Budko has served as president of Business Development Corporation of America II (“BDCA II”) since its formation in April 2014, its chief executive officer since November 2014, as director and chairman of the board of directors of BDCA II since December 2014 and was its chief operating officer from April 2014 until December 2014. Mr. Budko has also served as an executive officer of Realty Finance Trust, Inc. (“RFT”) and RFT’s advisor since their respective formations in November 2012, and as chief investment officer and a director of RCS Capital Corporation (“RCS Capital”) since February 2013. Mr. Budko has been a principal and a member of the investment committee of BDCA Venture Adviser, LLC (“BDCV Adviser”), the adviser to BDCA Venture, Inc. (NASDAQ: BDCV), since July 2014. Mr. Budko was a founding partner of AR Capital, LLC (“Sponsor”) and serves or has served in various executive capacities among other public, non-listed investment programs currently or formerly sponsored by our Sponsor. Mr. Budko founded and formerly served as managing director and group head of the Structured Asset Finance Group, a division of Wachovia Capital Markets from 1997 to 2006. As head of this group, Mr. Budko had responsibility for a diverse platform of structured financial and credit products, including commercial asset securitization; net lease credit financing and acquisitions; structured tax free asset exchange solutions and qualified intermediary services for real estate exchange investors. While at Wachovia, Mr. Budko acquired over $5 billion of assets. From 1987 to 1997, Mr. Budko worked in the Private Placement and Corporate Real Estate Finance Groups at NationsBank Capital Markets (predecessor to Bank of America Securities), becoming head of the Corporate Real Estate Finance group in 1990. Within the Private Placement group, Mr. Budko was responsible for the origination, structuring and placement of highly structured debt offerings by corporate issuers within NationsBank. Mr. Budko received a B.A. in Physics from the University of North Carolina.

Code of Business Conduct and Ethics

Because we do not employ any persons, our General Partner has determined that we will rely on a Code of Business Conduct and Ethics adopted by the General Partner that applies to the executive officers, employees and other persons performing services for the General Partner generally. You may obtain a copy of this Code of Business Conduct and Ethics without charge by a request to our General Partner at 405 Park Avenue, New York, New York 10022.

Item 11. Executive Compensation.

We do not directly employ any of the persons responsible for managing our business. Instead, our General Partner will manage our day to day affairs and, subject to the General Partner's oversight, the Manager will provide us with management and operating services pursuant to the Management Agreement regarding substantially all aspects of our oil and gas operations.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

As of December 31, 2014, the following table sets forth the beneficial ownership of our Common Units that are owned by:


•	beneficial owners of more than 5% of our Common Units


•	each executive officer of our General Partner; and


•	all directors, director nominees and executive officer of our General Partner as a group.



Name of Beneficial Owner	Common Units to be Beneficially Owned	Percentage of Common Units to be Beneficially Owned
American Energy Capital Partners GP, LLC (the General Partner) (1)	55,556	19.1	%
AECP Management, LLC (the Manager)(2)	55,556	19.1	%
Elizabeth Colvin (3)	25,000	8.6	%

_______________________________________

(1) Has a principal business address of 106 York Rd, Jenkintown, PA 19046-3233.

(2) Has a principal business address of P.O. Box 18756, Oklahoma City, OK 73154-0756.

(3) Has a principal business address of 201 E.12th Street, Apt. 308, New York, NY 10003-9135.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Related Party Arrangements

Fees Paid in Connection with the Offering

We are responsible for organizational and offering costs from the ongoing Offering, excluding selling commissions and dealer manager fees, up to a maximum of 1.5% of gross proceeds received from our ongoing Offering of Common Units, measured at the end of the Offering. Organizational and offering costs in excess of the 1.5% cap as of the end of the Offering are the responsibility of the General Partner and the Manager. The General Partner will be allocated two-thirds of this 1.5% reimbursement cap and the Manager will be allocated one-third of such reimbursement cap. As of December 31, 2014, organizational and offering costs exceeded 1.5% of gross proceeds received from the Offering by $2,870,873, due to the ongoing nature of the Offering and the fact that many expenses were paid before the Offering commenced.

During the year ended December 31, 2014, $1,168,399 of related party costs were incurred by us in connection with the Offering. As of December 31, 2014, we had amounts due to affiliate, comprised of $748,710 to affiliates of the General Partner or the Manager for costs incurred by us. During the period from October 30, 2013 (inception) to December 31, 2013, $6,137 of related party costs were incurred by us in connection with the Offering. As of December 31, 2013, we had a payable of $621,825 to the General Partner for costs incurred by the Partnership.

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Fees paid in Connection with Operations of the Partnership

We will reimburse the General Partner on a monthly basis for its allocable portion of administrative costs and third-party expenses it incurs or payments it makes on our behalf. Administrative costs include all customary and routine expenses incurred by the General Partner for the conduct of our administration, including legal, finance, accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative costs do not include any organization and offering expenses incurred by the General Partner and its affiliates. Administrative costs and other charges for goods and services must be fully supportable as to the necessity thereof and the reasonableness of the amount charged. During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) to December 31, 2013, no administrative costs of the General Partner were reimbursed in connection with our operations.

In conjunction with the disposition of our producing and non-producing oil and gas properties and in consideration for the services to be performed by the General Partner in connection with the disposition of our properties from time to time, the General Partner will receive reimbursement for its costs incurred in connection with such activities, plus a fee equal to 0.5% of the contract sales price (excluding any properties acquired from the us by the General Partner, the Manager, or their respective affiliates), (including when paid any deferred payment or “earn out” amounts), payable in cash concurrently with the Manager's 0.5% disposition fee for a total of 1.0%. (See Note 3 of the financial statements included elsewhere in this Form 10-K). During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) to December 31, 2013, no disposition fees were reimbursed to the General Partner in connection with our operations.

In conjunction with the financing of our producing and non-producing oil and gas properties and operations (other than the Offering described in the prospectus, but including our initial revolving credit facility) and in consideration for the services to be performed by the General Partner in connection therewith, the General Partner will receive a financing coordination fee equal to 0.25% of the principal amount of any financing (as we draw it down if it is not 100% funded in a single closing), payable in cash concurrently with the Manager's 0.5% financing coordination fee for a total of 0.75%. (See Note 3 - Manager and the Management Agreement). During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) to December 31, 2013, no financing fees were paid to the General Partner in connection with our operations.

Advisory Fee

Effective November 12, 2014, we entered into an agreement with the Dealer Manager to provide strategic advisory services and investment banking services required in the ordinary course of our business, such as performing financial analysis, evaluating publicly traded comparable companies and assisting in developing a portfolio composition strategy, a capitalization structure to optimize future liquidity options and structuring operations. We have accrued and amortize the cost of $920,000 associated with this agreement over the estimated life of the Offering into "Other expense" on our consolidated statements of operations. During the year ended December 31, 2014, $101,471 was incurred for the above services. As of December 31, 2014, the $920,000 payable to the Dealer Manager is included in due to affiliates on our consolidated balance sheets.

Incentive Distribution Rights

On the initial closing date, we issued incentive distribution rights to the General Partner and Holdings. The incentive distribution rights were issued 50% to the General Partner and 50% to Holdings.

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Item 14. Principal Accounting Fees and Services.

Independent Registered Accounting Firm

We have selected and appointed Hein & Associates, LLP (“Hein”) as our independent registered public accounting firm to audit our consolidated financial statements for the fiscal year ending 2014. Hein has audited our consolidated financial statements for the most recent fiscal year ended December 31, 2014. Hein was selected and appointed as our independent registered public accounting firm on February 5, 2015.

For the period from October 30, 2013 (inception) to January 22, 2015, Grant Thornton LLP (“Grant Thornton”) had served as our independent registered public accounting firm.

For the fiscal years ended December 31, 2014 and 2013, fees paid or payable to Hein and Grant Thornton for services it performed in connection with the audit of the 2014 financial statements, the audit of the 2013 financial statements, reviews of the amended S-1s, SEC comment letters, issuance of consents and 2014 interim reviews are as follows:



	Year Ended December 31, 2014		For the period from October 30, 2013 (inception) to December 31, 2013
Audit fees	$	30,000	$	10,500
Audit-related	$	—	$	—
Tax fees	$	—	$	—
All other fees	$	82,573	$	—
Total	$	112,573	$	10,500

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) Financial Statement Schedules

See the Index to Consolidated Financial Statements on page F-1 of this report.

(b) Exhibits

The following exhibits are included, or incorporated by reference, in this Annual Report on Form 10-K, for the year ended December 31, 2014 (and are numbered in accordance with Item 601 of Regulation S-K).



Exhibit No.		Description
1.1⁽³⁾		Exclusive Dealer Manager Agreement, dated as of May 8, 2014, among the Partnership, the General Partner and the Dealer Manager
3.1⁽¹⁾		Certificate of Limited Partnership of the Partnership
3.2⁽³⁾		First Amended and Restated Agreement of Limited Partnership, dated as of May 8, 2014
3.3⁽¹⁾		Certificate of Formation of the General Partner
3.4⁽¹⁾		Certificate of Formation of AECP Operating Company, LLC
10.1⁽³⁾		Amended and Restated Subscription Escrow Agreement, dated as of June 16, 2014, among the Dealer Manager, the Partnership and UMB Bank, N.A.
10.2⁽³⁾		Management Services Agreement, dated as of June 16, 2014 and effective as of June 16, 2014, by and among the Manager, the Partnership, and AECP Operating Company, LLC
10.3⁽⁴⁾		Exhibit D to Management Services Agreement - Form of Joint Operating Agreement
16.1⁽⁵⁾		Letter from Grant Thornton LLP to the Securities and Exchange Commission dated January 28, 2015.
24⁽²⁾		Power of Attorney
31.1*		Certification of the Principal Executive Officer of the General Partner pursuant to Securities Exchange Act Rule 13a-14(a) or 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certification of the Principal Financial Officer of the General Partner pursuant to Securities Exchange Act Rule 13a-14(a) or 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32*		Written statements of the Principal Executive Officer and Principal Financial Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101 *		XBRL (eXtensible Business Reporting Language). The following materials from the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014, formatted in XBRL: (i) the Consolidated Balance Sheets; (ii) the Consolidated Statements of Operations; (iii) the Consolidated Statement of Partners' Equity (Deficit); (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements. As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purpose of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934

_________________________



*	Filed herewith
⁽¹⁾	Previously filed with the SEC with Pre-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 on February 13, 2014.
⁽²⁾	Previously filed with the SEC with the Partnership’s Registration Statement on Form S-1 on December 13, 2013, and the Partnership's Post-Effective Amendment No. 2 on January 20, 2015.
⁽³⁾	Filed as an exhibit to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 filed with the SEC on June 20, 2014.
⁽⁴⁾	Previously filed with the SEC with the Post-Effective Amendment No. 1 to the Partnership's Registration Statement on Form S-1 on September 19, 2014.
⁽⁵⁾	Filed as an exhibit to the Partnership's Current Report on Form 8-K filed with the SEC on January 28, 2015 and herein incorporated by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 20th day of March, 2015.



	American Energy Capital Partners, LP
	By:	American Energy Capital Partners GP, LLC, the Registrant's General Partner

	By	/s/ WILLIAM M. KAHANE
		WILLIAM M. KAHANE
		CHIEF EXECUTIVE OFFICER, PRESIDENT AND DIRECTOR

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this annual report on Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Name	Capacity	Date

/s/ William M. Kahane	Chief Executive Officer, President and Director	March 20, 2015
William M. Kahane	Chief Executive Officer, President and Director

/s/ Nicholas Radesca	Chief Financial Officer and Treasurer (Principal Financial Officer, Principal Accounting Officer)	March 20, 2015
Nicholas Radesca

/s/ Peter M. Budko	Executive Vice President and Secretary	March 20, 2015
Peter M. Budko

/s/ Nicholas S. Schorsch	Director	March 20, 2015
Nicholas S. Schorsch

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page
Reports of Independent Registered Public Accounting Firms	F-2

Consolidated Balance Sheets as of December 31, 2014 and 2013	F-4

Consolidated Statements of Operations for the Year Ended December 31, 2014 and for the Period from October 30, 2013 (Inception) to December 31, 2013	F-5

Consolidated Statements of Changes in Partners' Equity (Deficit) for the Year Ended December 31, 2014 and for the Period from October 30, 2013 (Inception) to December 31, 2013	F-6

Consolidated Statements of Cash Flows for the Year Ended December 31, 2014 and for the Period from October 30, 2013 (Inception) to December 31, 2013	F-7

Notes to Consolidated Financial Statements	F-8

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

American Energy Capital Partners GP, LLC

We have audited the accompanying consolidated balance sheet of American Energy Capital Partners - Energy Recovery Program, LP and subsidiary (collectively, the “Partnership”) as of December 31, 2014, and the related statements of operations, partners’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the 2014 consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Energy Capital Partners - Energy Recovery Program, LP and subsidiary as of December 31, 2014, and the results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles

/s/HEIN & ASSOCIATES LLP

Dallas, Texas

March 20, 2015

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

American Energy Capital Partners GP, LLC

We have audited the accompanying consolidated balance sheet of American Energy Capital Partners, LP (a Delaware limited partnership) and subsidiary (the “Partnership”) as of December 31, 2013, and the related consolidated statements of operations, partners’ equity (deficit), and cash flows for the period from October 30, 2013 (inception) to December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Energy Capital Partners, LP and subsidiary as of December 31, 2013, and the results of their operations and their cash flows for the period from October 30, 2013 (inception) to December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 12, 2014

F-3

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED BALANCE SHEETS



	December 31, 2014			December 31, 2013

ASSETS
CURRENT ASSETS:
Cash	$	2,643,155		$	209,469
Prepaid expenses and other assets	112,328			—
Deferred affiliated costs	818,529			—
Deferred offering costs	—			561,952
Total current assets	$	3,574,012		$	771,421

LIABILITIES AND PARTNERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	393,476		$	252,117
Due to affiliate	1,673,195			621,825
Distributions payable	29,598			—
Management fee payable	23,860			—
Total current liabilities	2,120,129			873,942
Commitments and contingencies (Note 5)
General Partner Interest	(103,501		)	—
Limited Partners, 290,414 and 0 Common Units issued and outstanding as of December 31, 2014 and December 31, 2013, respectively	1,557,384			—
Accumulated deficit	—			(102,521		)
Partners' equity (deficit)	1,453,883			(102,521		)
Total liabilities and partners' equity (deficit)	$	3,574,012		$	771,421

The accompanying notes are an integral part of these statements.

F-4

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED STATEMENTS OF OPERATIONS



	Year Ended December 31, 2014			Period from October 30, 2013 (Inception) to December 31, 2013

Income	$	—		$	—
Expenses
Organizational costs	—			103,465
Insurance expense	302,167			—
Professional fees	198,769			—
Advisory fee	101,471
Management fee expense	49,600			—
Interest expense	3,297			—
Bank fees	184			56
Other expenses	47,840			—
Total expenses	703,328			103,521
Net loss	(703,328		)	(103,521		)
Less: General partner interest in net loss	—			(103,521		)
Limited partners' interest in net loss	$	(703,328	)	$	—

Net loss per common unit (basic and diluted)*	$	(3.99	)	$	—
Weighted average Common Units outstanding (basic and diluted)	176,385			—

___________________________________________________

* Net loss per Common Unit is only calculated for the period subsequent to the initial closing date as no Common Units were outstanding prior to June 16, 2014.

The accompanying notes are an integral part of these statements.

F-5

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY (DEFICIT)



	General Partner			Limited Partner
	Amount			Number of Common Units	Amount			Accumulated Deficit			Total
October 30, 2013 (Inception)	$	—		—	$	—		$	—		$	—
Investment from parent	—				—			1,000			1,000
Net loss	—							(103,521		)	(103,521		)
December 31, 2013	—			—	—			(102,521		)	(102,521		)
Reclassification of accumulated deficit	(103,501		)	—	980			102,521			—
Redemptions - Organizational Limited Partner	—			—	(980		)	—			(980		)
Issuance of Common Units	—			290,414	5,534,173			—			5,534,173
Offering costs	—			—	(3,157,185		)	—			(3,157,185		)
Net loss	—			—	(703,328		)	—			(703,328		)
Distributions	—			—	(116,276		)	—			(116,276		)
December 31, 2014	$	(103,501	)	290,414	$	1,557,384		$	—		$	1,453,883

The accompanying notes are an integral part of these statements.

F-6

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31, 2014			Period from October 30, 2013 (Inception) to December 31, 2013
Cash flows from operating activities:
Net loss	$	(703,328	)	$	(103,521	)
Change in assets and liabilities:
Prepaid expenses and other assets	(112,328		)	—
Deferred affiliated costs	(818,529		)
Accounts payable and accrued expenses	(72,738		)	252,117
Due to affiliate	924,485
Management fee payable	23,860			—
Net cash provided by (used in) operating activities	(758,578		)	148,596

Cash flows from financing activities:
Proceeds from issuance of common units	5,534,173			1,000
Payment of equity offering costs	(1,632,426		)	(561,952		)
Repayment to affiliates	(621,825		)	—
Distributions paid	(86,678		)	—
Redemptions - Organizational limited partner	(980		)	—
Advances from affiliate	—			621,825
Net cash provided by financing activities	3,192,264			60,873

Net change in cash	2,433,686			209,469
Cash and cash equivalents, beginning of period	209,469			—
Cash and cash equivalents, end of period	$	2,643,155		$	209,469

Supplemental disclosures of cash flow information:
Interest Paid	$	3,314		$	—
Supplemental disclosures on non-cash financing activities:
Reclassification of deferred offering costs to additional paid-in capital	$	1,034,795		$	—
Distributions payable	$	29,598		$	—

The accompanying notes are an integral part of these statements.

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December 31, 2014

Note 1 — Organization and Business Operations

American Energy Capital Partners - Energy Recovery Program, LP (formerly, American Energy Capital Partners, LP) and its consolidated subsidiary, AECP Operating Company, LLC (together, the "Partnership"), were both formed in Delaware on October 30, 2013. The general partner is American Energy Capital Partners GP, LLC (the "General Partner"), which was formed in Delaware on October 30, 2013 and is wholly owned by AR Capital Energy Holdings, LLC (the "ARC Sponsor"). The ARC Sponsor is under common control with AR Capital, LLC. In connection with the formation of the Partnership, the General Partner made an initial capital contribution in the amount of $20 for its general partner interest.

On May 8, 2014, the U.S. Securities and Exchange Commission (the "SEC") declared effective the Partnership's registration statement on Form S-1 (File No. 333-192852) (the "Registration Statement") filed under the Securities Act of 1933, as amended (the "Securities Act") and the Partnership commenced its initial public offering (the "Offering"), on a "reasonable best efforts" basis, of up to 100.0 million Common Units representing limited partnership interests ("Common Units") at a per unit price of up to $20.00. The Offering is expected to end on May 8, 2016, or two years from the effectiveness of the Registration Statement (the "final termination date"). On June 16, 2014, the Partnership commenced business operations after raising $2.0 million of gross proceeds (the "initial closing"), the amount required for the Partnership to release equity proceeds from escrow, and began the Partnership's business activities, including the acquisition and development of producing and non-producing oil and gas properties, including drilling activities.

The Partnership has no officers, directors or employees. Instead, the General Partner manages the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership are made by the board of directors of the General Partner and its officers. The Partnership entered into a management services agreement (the "Management Agreement") with AECP Management, LLC (the "Manager" or the "AECP Sponsor"). The General Partner will have full authority to direct the activities of the Manager under the Management Agreement. The Manager will provide the Partnership with management and operating services regarding substantially all aspects of operations. Realty Capital Securities, LLC (the "Dealer Manager")serves as the dealer manager of the Offering.

The Partnership was formed to acquire, develop, operate, produce and sell working and other interests in producing and non-producing oil and gas properties located onshore in the United States. The Partnership will seek to acquire working interests, leasehold interests, royalty interests, overriding royalty interests, production payments and other interests in producing and non-producing oil and gas properties. As of December 31, 2014, the Partnership had not identified any oil and gas properties. As we have not yet acquired oil and gas properties, our principal source of cash is the proceeds from our Offering, which we rely on to finance operations, distributions and capital investments.

Note 2 — Summary of Significant Accounting Policies

Basis of Accounting and Presentation

The accompanying consolidated financial statements of the Partnership included herein were prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").

Use of Estimates

Cash

Cash includes cash in bank accounts. The Partnership deposits cash with high quality financial institutions. These deposits are guaranteed by the Federal Deposit Insurance Company up to an insurance limit.

Fair Value of Financial Instruments

The Partnership's financial instruments, such as cash, prepaid expenses and payables are reflected in the balance sheet at carrying value, which approximates fair value due to their short-term nature.

Organizational Costs

Organizational costs may include accounting, legal and regulatory fees incurred related to the formation of the Partnership. Organizational costs are expensed as incurred.

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December 31, 2014

Offering and Related Costs

Offering and related costs include all expenses incurred in connection with the Partnership’s Offering. Offering costs (other than selling commissions and the dealer manager fee) of the Partnership may be paid by the General Partner, its affiliates and the Manager on behalf of the Partnership. On May 8, 2014, the day the Partnership commenced its Offering, accumulated offering costs were reclassified from deferred costs to Partners' deficit. Offering costs may represent professional fees, fees paid to various regulatory agencies, and other costs incurred in connection with the registration and sale of the Partnership's Common Units. The Partnership will reimburse the General Partner and the Manager in a combined amount of up to 1.5% of the aggregate proceeds of the Offering, payable two-thirds to the General Partner and one-third to the Manager. Neither the General Partner nor the Manager will be entitled to reimbursement for offering and organization expenses to the extent such combined expenses exceed 1.5% of the aggregate offering proceeds. (See Note 6 - Related Party Transactions and Arrangements)

Net Loss Per Common Unit

Net loss per Common Unit is computed by dividing net loss applicable to Common Unit holders by the weighted average number of Common Units outstanding during the period. Net loss per Common Unit is only calculated for the period subsequent to the initial closing date as no Common Units were outstanding prior to June 16, 2014. Diluted net loss per Common Unit is the same as basic net loss per limited partner unit as there were no potentially dilutive common or subordinated units outstanding as of December 31, 2014.

Taxes

The Partnership is a disregarded entity for tax purposes. The Partnership will generally pay no taxes but rather the activities of the Partnership will pass through to and be reflected on the tax returns of the partners.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers ("ASU 2014-09")", which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. This ASU is effective for reporting periods beginning after December 15, 2016, and for interim and annual reporting periods thereafter. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures.

In August 2014, FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40), Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern," which requires management to evaluate whether there is substantial doubt about the Partnership's ability to continue as a going concern. This ASU is effective for the annual reporting period ending after December 15, 2016, and for interim and annual reporting periods thereafter. Early application is permitted. The Partnership is currently evaluating the adoption of this ASU and its impact on the consolidated financial statements.

Note 3 — Manager and the Management Agreement

The Partnership entered into the Management Agreement with the Manager to provide the Partnership with management and operating services regarding substantially all aspects of operations. All services provided by the Manager will be under and subject to the supervision of the General Partner.

Under the Management Agreement, the Manager will provide management and other services to the Partnership, including the following:


•	identifying onshore producing and non-producing oil and gas properties that the Partnership may consider acquiring, and assisting the Partnership in evaluating, contracting for and acquiring these properties and managing the development of these properties;


•	investigating and evaluating financing alternatives for any property acquisition and the ownership, development and operations of assets, and any refinancing;

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December 31, 2014


•	operating, or causing one of its affiliates to operate, on the Partnership’s behalf, any properties in which the Partnership’s interest in the property is sufficient to appoint the operator;


•	overseeing the operations on properties operated by persons other than the Manager, including recommending whether the Partnership should participate in the development of such properties by the operators of the properties;


•	arranging for the marketing, transportation, storage and sale of all natural gas, natural gas liquids and oil produced from properties and procuring all supplies, materials and equipment needed in order to perform lease operations;


•	taking any actions requested by the Partnership to prepare and arrange for all or any portion of the Partnership’s assets to be sold or otherwise disposed of or liquidated; and


•	establishing cash management and risk management, including hedging, programs for the Partnership, receiving the revenues from the sale of production from properties and paying operating expenses and approved capital expenses with respect to properties.

The Management Agreement provides that the Partnership, through the supervision of the General Partner, will direct the services provided under the Management Agreement, and that the Manager will determine the means or method by which those directions are carried out. The Management Agreement further provides that the Manager will conduct the day-to-day operations of the business as provided in draft budgets that the Manager will prepare and the Partnership, through the supervision of the General Partner, will have the right to approve and review on a quarterly basis. The Management Agreement also contains a list of activities in which the Manager will not engage without prior approval of the Partnership and/or the General Partner.

Commencing with a payment for the month of the initial closing, and for each month thereafter through the final termination date of the Offering, the Partnership will pay the Manager a monthly management fee equal to an annual rate of 3.5% of the sum of: (i) the capital contributions made by the holders of Common Units to the Partnership from the initial closing through the final termination date; and (ii) the average outstanding indebtedness of the Partnership during the preceding month.

For each month beginning with the first month following the final termination date of the Offering, the Partnership will pay a monthly management fee equal to an annual rate of 5.0%, which will be paid four-fifths to the Manager and one-fifth to the General Partner, of the sum of: (i) the capital contributions made by the holders of Common Units to the Partnership; and (ii) the average outstanding indebtedness during the preceding month.

In conjunction with the acquisition cost of producing and non-producing oil and gas properties (excluding any properties the Partnership may elect to acquire from the Manager or an affiliate of the Manager), the Manager will be entitled to receive an acquisition fee equal to 2% of the contract price for each property acquired. The Manager will also be entitled to reimbursements of acquisition expenses for each property acquired, with the aggregate amount of the acquisition fee and reimbursement of acquisition expenses not to exceed 3% of the contract price for each property acquired.

When the Manager operates the Partnership’s properties pursuant to a model form operating agreement, it will receive reimbursement at actual cost for all direct expenses incurred by it on behalf of the Partnership, including expenses to gather, transport, process, treat and market the Partnership’s oil and natural gas production; and well supervisory fees at competitive rates for maintaining and operating the wells during drilling and producing operations.

In conjunction with the disposition by the Partnership of its producing and non-producing oil and gas properties and in consideration for the services to be performed by the Manager and the General Partner in connection with the disposition of Partnership properties from time to time, the Manager and the General Partner will receive reimbursement for their respective costs incurred in connection with such activities, plus a fee equal to 1.0% of the contract sales price of the properties (excluding any properties acquired from the Partnership by the General Partner, the Manager, or their respective affiliates), (including when paid any deferred payment or "earn out" amounts), which will be paid one-half (0.5%) to each of the Manager and the General Partner. (See Note 6 - Related Party Transactions and Arrangements).

In conjunction with the financing by the Partnership of its producing and non-producing oil and gas properties and operations (other than the Offering described in the Registration Statement, but including the Partnership’s initial revolving credit facility) and in consideration for the services to be performed by the General Partner and the Manager in connection therewith, the General Partner and the Manager will receive a financing coordination fee equal to 0.75% of the principal

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014

amount of any financing (as the Partnership draws it down if it is not 100% funded in a single closing), which will be paid two-thirds (0.5%) to the Manager and one-third (0.25%) to the General Partner. (See Note 6 - Related Party Transactions and Arrangements).

Note 4 — Common Units

As of December 31, 2014, the Partnership had 290,414 Common Units outstanding.

On September 19, 2014, the General Partner approved and authorized the distribution rate equal to $1.20 per annum based on the price of the Partnership's Common Units. This distribution rate corresponds to a 6.0% annualized rate based on the unit price of $20.00 to be calculated based on unitholders of record each day during the applicable period at a rate of $0.00328767123 per day. The distributions will be deemed to accrue with respect to each unit commencing on the applicable closing date on which such unit was issued.

The below table shows the distributions paid on shares outstanding during the year ended December 31, 2014.



Date Paid	Period Covered	Total Distribution
October 1, 2014	June 16, 2014 - September 30, 2014	$	42,933
November 1, 2014	October 1, 2014 - October 30, 2014	20,021
December 1, 2014	November 1, 2014 - November 30, 2014	23,724
Total		$	86,678

For the year ended December 31, 2014, the Partnership paid cash dividends of $86,678 and had a net loss of $703,328. As of December 31, 2014, the Partnership had a distribution payable of $29,598 for dividends accrued in the month of December 2014.

Note 5 — Commitments and Contingencies

Litigation

In the ordinary course of business, the Partnership may become subject to litigation or claims. There are no material legal proceedings pending or known to be contemplated against the Partnership.

Note 6 — Related Party Transactions and Arrangements

Fees Paid in Connection with the Offering

The Partnership is responsible for organizational and offering costs from the ongoing Offering, excluding selling commissions and dealer manager fees, up to a maximum of 1.5% of gross proceeds received from its ongoing Offering of Common Units, measured at the end of the Offering. Organizational and offering costs in excess of the 1.5% cap as of the end of the Offering are the responsibility of the General Partner and the Manager. The General Partner will be allocated two-thirds of this 1.5% reimbursement cap and the Manager will be allocated one-third of such reimbursement cap. As of December 31, 2014, organizational and offering costs exceeded 1.5% of gross proceeds received from the Offering by $2,870,873, due to the ongoing nature of the Offering and the fact that many expenses were paid before the Offering commenced.

During the year ended December 31, 2014, $1,168,399 of related party costs were incurred by the Partnership in connection with the Offering. As of December 31, 2014, the Partnership had amounts due to affiliate, comprised of $748,710

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014

to affiliates of the General Partner or the Manager for costs incurred by the Partnership. During the period from October 30, 2013 (inception) to December 31, 2013, $6,137 of related party costs were incurred by the Partnership and due to affiliates in connection with the Offering. As of December 31, 2013, the Partnership had a payable of $621,825 to the General Partner for costs incurred by the Partnership.

Fees paid in Connection with Operations of the Partnership

The Partnership will reimburse the General Partner on a monthly basis for its allocable portion of administrative costs and third-party expenses it incurs or payments it makes on behalf of the Partnership. Administrative costs include all customary and routine expenses incurred by the General Partner for the conduct of Partnership administration, including legal, finance, accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative costs do not include any organization and offering expenses incurred by the General Partner and its affiliates. Administrative costs and other charges for goods and services must be fully supportable as to the necessity thereof and the reasonableness of the amount charged. During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) to December 31, 2013, no administrative costs of the General Partner were reimbursed in connection with the operations of the Partnership.

In conjunction with the disposition by the Partnership of its producing and non-producing oil and gas properties and in consideration for the services to be performed by the General Partner in connection with the disposition of Partnership properties from time to time, the General Partner will receive reimbursement of its respective costs incurred in connection with such activities, plus a fee equal to 0.5% of the contract sales price (excluding any properties acquired from the Partnership by the General Partner, the Manager, or their respective affiliates), (including when paid any deferred payment or "earn out" amounts), payable in cash concurrently with the Manager's 0.5% disposition fee for a total of 1.0%. (See Note 3 - Manager and the Management Agreement). During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) to December 31, 2013, no disposition fees were reimbursed to the General Partner in connection with the operations of the Partnership.

In conjunction with the financing by the Partnership of its producing and non-producing oil and gas properties and operations (other than the Offering described in the prospectus, but including the Partnership’s initial revolving credit facility) and in consideration for the services to be performed by the General Partner in connection therewith, the General Partner will receive a financing coordination fee equal to 0.25% of the principal amount of any financing (as the Partnership draws it down if it is not 100% funded in a single closing), payable in cash concurrently with the Manager's 0.5% financing coordination fee for a total of 0.75%. (See Note 3 - Manager and the Management Agreement). During the year ended December 31, 2014 and for the period from October 30, 2013 (inception) to December 31, 2013, no financing fees were paid to the General Partner in connection with the operations of the Partnership.

During the year ended December 31, 2014, $105,956 of related party costs were incurred and payable by the Partnership in connection with the Partnership's operations. Of this amount, $101,471 was incurred related to the strategic advisory services and investment banking services in connection with the advisory agreement with our Dealer Manager as defined below.

Advisory Fee

Effective November 12, 2014, the Partnership entered into an agreement with the Dealer Manager to provide strategic advisory services and investment banking services required in the ordinary course of the Partnership's business, such as performing financial analysis, evaluating publicly traded comparable companies and assisting in developing a portfolio composition strategy, a capitalization structure to optimize future liquidity options and structuring operations. The Partnership has accrued and amortizes the cost of $920,000 associated with this agreement over the estimated life of the Offering into "Other expense" on our consolidated statements of operations. During the year ended December 31, 2014, $101,471 was incurred for the above services. As of December 31, 2014, the $920,000 payable to the Dealer Manager is included in due to affiliates on our consolidated balance sheets.

Incentive Distribution Rights

On the initial closing date, the Partnership issued incentive distribution rights to the General Partner and AECP Holdings, LLC ("Holdings"), an affiliate of the Manager. The incentive distribution rights were issued 50% to the General Partner and 50% to Holdings.

Upon a sale of all or substantially all of the Partnership's properties, the General Partner and Holdings will each be entitled to receive a one-time incentive performance payment in cash equal to 12.5% of the aggregate sale price of the Partnership's properties net of expenses and of the payment of all Partnership debts and obligations, minus the excess, if any, of $20.00 per Common Unit (the original purchase price per Common Unit) of all outstanding Common Units, less the aggregate amounts

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December 31, 2014

previously distributed after the final termination date of the Offering on the outstanding Common Units.

The Manager will also be entitled to other fees per the Management Agreement. See Note 3 - Manager and the Management Agreement.

Note 7 — Subsequent Events

The Company has evaluated subsequent events through the filing of this Annual Report on Form 10-K, and determined that there have not been any events that have occurred that would require adjustments to disclosures in the consolidated financial statements except for the following transactions:

Distributions Paid

On January 2, 2015, the Partnership paid a cash distribution of $29,598 to holders of Common Units for the month of December 2014.

Sale of Common Units

As of February 28, 2015, the Partnership had 339,386 Common Units outstanding and has raised total gross proceeds of $6,502,173. Subsequent to December 31, 2014, the Partnership issued 48,972 Common Units for total gross proceeds of $968,000 based on a per unit value of up to $20.00.

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP - FORM 10-K - March 20, 2015

Attached files

AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP Reports