UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~March~~June 3130, 2015



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

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, New York		10022
(Address of Principal Executive Office)		(Zip Code)

(212) 415-6500

(Registrant’s Telephone Number, Including Area Code)

Not applicable

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x The registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, but is currently not required to file such reports under such sections.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes o

No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one):



Large accelerated filer o	Accelerated filer o
Non-accelerated filer o	Smaller reporting company x

(Do not check if a smaller reporting company)

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

As of ~~April~~August 3031, 2015, the Partnership had ~~435~~562,~~584~~287 Common Units outstanding.

TABLE OF CONTENTS

	Page
PART I
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	1
Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	1
Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014	2
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014	2
Consolidated Statement of Partners' Equity for the Three Months Ended March 31, 2015	3
Consolidated Statement of Partners' Equity for the Six Months Ended June 30, 2015	3
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014	4
Notes to Consolidated Financial Statements	5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	1112
Item 3. Quantitative and Qualitative Disclosures about Market Risk	1718
Item 4. Controls and Procedures	1718
PART II
Item 1. Legal Proceedings	1819
Item 1A. Risk Factors	1819
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	1819
Item 3. Defaults upon Senior Securities	1819
Item 4. Mine Safety Disclosures	1819
Item 5. Other Information	1819
Item 6. Exhibits	1920
Signatures	2021

Table of Contents

PART I

Item 1. Financial Statements.

AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2015			December 31, 2014
	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash	$	34,~~609~~463,~~293~~890		$	2,643,155
Prepaid expenses and other assets	86,333			112,328
Deferred affiliated costs	514,118			818,529
Deferred affiliated costs	666,324			818,529
Prepaid expenses and other assets	56,833			112,328
Total current assets	$	4,361,950		$	3,574,012
Subscription Receivable	5,000			—
Total current assets	$	5,039,841		$	3,574,012
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	483,120		$	393,476
Due to affiliates	$	1,109,447		$	1,673,195
Due to affiliate	882,971			1,673,195
Accounts payable and accrued expenses	425,664			393,476
Management fee payable	76112,~~120~~170			23,860
Distributions payable	4250,~~436~~183			29,598
Total current liabilities	1,~~484~~697,~~647~~464			2,120,129
Commitments and contingencies (Note 6)
General Partner Interest	(103,501		)	(103,501		)
Limited Partners, 418,919 and 290,414 Common Units issued and outstanding as of March 31, 2015 and December 31, 2014, respectively	2,980,804			1,557,384
Limited Partners, 511,170 and 290,414 Common Units issued and outstanding as of June 30, 2015 and December 31, 2014, respectively	3,445,878			1,557,384
Partners' equity	23,~~877~~342,~~303~~377			1,453,883
Total liabilities and partners' equity	$	45,~~361~~039,~~950~~841		$	3,574,012

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

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Income	$	—		$	—		$	—		$	—
Expenses
Advisory fees	152,206			—			304,412			—
Insurance expense	129,500			—43,167			259,000			43,167
Management fee expense	5276,~~260~~050			—			128,310			—
Professional fees	4229,~~567~~075			—30,000			71,642			30,000
Interest expense	947			—
Other expenses	17,046			—			22,549			184
Other expenses	5,503			—
Interest expense	—			473			947			473
Bank fees	—			184
Total expenses	403,877			73,640			786,860			73,824
Total expenses	382,983			184
Net income (loss)	(403,877		)	(73,640		)	(786,860		)	(73,824		)
Net loss	(382,983		)	(184		)
Less: General partner interest in net loss	—			—			—			(184		)
Less: General partner interest in net loss	—			(184		)
Limited partners' interest in net loss	$	(403,877	)	$	(73,640	)	$	(786,860	)	$	(73,640	)
Limited partners' interest in net loss	$	(382,983	)	$	—
Net loss per common unit (basic and diluted)*	$	(0.85	)	$	(0.66	)	$	(1.90	)	$	(0.66	)
Net loss per common unit (basic and diluted)*	$	(1.08	)	$	—
Weighted average common units outstanding (basic and diluted)	473,470			111,111			414,345			111,111
Weighted average common units outstanding (basic and diluted)	354,563			—

* 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 unaudited consolidated financial statements.

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED STATEMENT OF PARTNERS' EQUITY

For the ~~three~~six months ended ~~March~~June 3130, 2015

(Unaudited)

	General Partner			Limited Partner
	Amount			Number of Common Units	Amount			Total
Balance, December 31, 2014	$	(103,501	)	290,414	$	1,557,384		$	1,453,883
Issuance of Common Units	—			~~128~~220,~~505~~756	24,~~539~~377,~~828~~413			24,~~539~~377,~~828~~413
Offering costs	—			—	(~~628~~1,~~982~~455,773		)	(~~628~~1,~~982~~455,773		)
Net loss	—			—	(~~382~~786,~~983~~860		)	(~~382~~786,~~983~~860		)
Distributions	—			—	(~~104~~246,~~443~~286		)	(~~104~~246,~~443~~286		)
Balance, March 31, 2015	$	(103,501	)	418,919	$	2,980,804		$	2,877,303
Balance, June 30, 2015	$	(103,501	)	511,170	$	3,445,878		$	3,342,377

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

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities:
Net loss	$	(~~382~~786,~~983~~860	)	$	(~~184~~73,824	)
Change in assets and liabilities:
Prepaid expenses and other assets	2555,~~995~~495			—(60,812		)
Deferred affiliated costs	~~152~~304,~~205~~411			—
Accounts payable and accrued expenses	378,~~609~~313			—30,000
Due to affiliate	(~~261~~4,~~234~~463		)	—
Management fee payable	5288,~~260~~310			—
Net cash used in operating activities	(~~376~~334,~~148~~794		)	(~~184~~104,636		)
Cash flows from financing activities:
Proceeds from issuance of common units	24,~~539~~372,~~828~~413			—2,000,000
Payment of equity offering costs	(1,105,937		)	(105,365		)
Payment of offering costs	(1,991,183		)	(1,370,166		)
Distributions paid	(91225,~~605~~701		)	—
Net cash provided by (used in) financing activities	1,342,286			(105,365		)
Net cash provided by financing activities	2,155,529			629,834
Net change in cash	~~966~~1,~~138~~820,735			~~(105~~525,~~549~~198		)
Cash and cash equivalents, beginning of period	2,643,155			209,469
Cash and cash equivalents, end of period	$	34,~~609~~463,~~293~~890		$	~~103~~734,~~920~~667
Supplemental information:
Interest Paid	$	947		$	—473
Supplemental non-cash information:
Offering costs in accounts payable and accrued expenses	$	266,132		$	126,622
Reclassification of deferred offering costs to additional paid-in capital	$	—		$	1,034,795
Offering costs in due to affiliate	$	219,720		$	235,356
Offering costs in accounts payable and accrued expenses	$	237,972		$	251,768
Distributions payable	$	42,436		$	—
Offering costs in due to affiliate	$	189,425		$	307,569
Distributions payable	$	50,183		$	—

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

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015

(Unaudited)

Note 1 — Organization and Business Operations

American Energy Capital Partners - Energy Recovery Program, 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~~Final ~~termination~~Termination ~~date~~Date"). On June 16, 2014, the Partnership commenced business operations after raising $2.0 million of gross proceeds (the "~~initial~~Initial ~~closing~~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 ~~March 31~~June 30, 2015, the Partnership had not identified any oil and gas properties. As the Partnership has not yet acquired oil and gas properties, its principal source of cash is the proceeds from the Offering, which the Partnership relies on to finance operations, distributions and capital investments.

On September 11, 2015, the Partnership suspended the acceptance of subscriptions pursuant to its initial public offering in anticipation of formally terminating the Offering in the near future. The Partnership has since terminated the Offering and intends to present a proposal for the Partnership’s dissolution and liquidation to its unitholders at a special meeting. In connection with its dissolution and liquidation, the Partnership intends to propose a plan to its unitholders that will include a distribution to unitholders in an amount equal to 100% of their capital contribution to the Partnership exclusive of any distributions already received.

Also on September 11, 2015, in anticipation of the termination of the Offering, the Partnership and the Manager mutually terminated the Management Agreement dated June 16, 2014, pursuant to which the Manager was engaged to provide management and operating services regarding substantially all aspects of the Partnership’s oil and gas operations. As a result, no amounts previously accrued for or outstanding as of June 30, 2015 will be paid to the Manager related to the monthly management fees pursuant to the Management Agreement (See Note 7 — Subsequent Events).

Note 2 — Summary of Significant Accounting Policies

Basis of Accounting and Presentation

The accompanying interim 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") and include the accounts of the Partnership and its wholly owned subsidiary. The information furnished includes all adjustments and accruals of a normal recurring nature, which, in the opinion of management, are necessary for a fair presentation of results for the interim periods. All intercompany accounts and transactions have been eliminated in consolidation. The results of operations for the three and six months ended ~~March~~June 3130, 2015 and 2014 are not necessarily indicative of the results for the entire year or any subsequent interim period.

These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto as of and for the year ended December 31, 2014, which are included in the Annual Report on Form 10-K filed with the SEC on March 20, 2015.

Use of Estimates

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.

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015

(Unaudited)

As noted above, on September 11, 2015, the Partnership suspended the acceptance of subscriptions pursuant to the Offering in anticipation of formally terminating the Offering in the near future. Following the termination of the Offering, the General Partner intends to commence the dissolution and liquidation of the Partnership, which will be subject to approval by the Partnership's unitholders. Assuming the plan of liquidation is approved by the Partnership's unitholders and the Partnership is required to file a Quarterly Report on Form 10-Q as of September 30, 2015, the Partnership will apply liquidation accounting. (See Note 7 - Subsequent Events).

Use of Estimates

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~~fees) 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, 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 5 -— 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~~Initial ~~closing~~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 ~~March~~June 3130, 2015.

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. In July 2015, the FASB approved a deferral of the effective date for ASU 2014-09 for reporting periods beginning after December 15, 2017, and for interim and annual reporting periods thereafter. Early application is permitted, but not before the original effective date. 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.

In April 2015, FASB issued an accounting standards update for “Interest - Imputation of Interest,” which simplifies the presentation of debt issuance costs. This accounting standard update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015 (and interim periods within those fiscal years), with early adoption permitted and retrospective application required. The Partnership is evaluating the impact of this new guidance and does not expect it to have a significant 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

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015

(Unaudited)

with debt discounts. This new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015 (and ~~operations~~interim ofperiods ~~assets~~within those fiscal years), with early adoption permitted and ~~any~~retrospective ~~refinancing;~~application required. The Partnership is evaluating the impact of this new guidance and does not expect it to have a significant impact on the consolidated financial statements.

Note 3 — Manager and the Management Agreement

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;


•	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~~Initial ~~closing~~Closing, and for each month thereafter through the ~~final~~Final ~~termination~~Termination ~~date~~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~~Initial ~~closing~~Closing through the last day of the preceding month; and (ii) the average outstanding indebtedness of the Partnership during the preceding month.

For each month beginning with the first month following the ~~final~~Final ~~termination~~Termination ~~date~~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 from the ~~initial~~Initial ~~closing~~Closing through the ~~final~~Final ~~termination~~Termination ~~date~~Date; 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 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 5 - Related Party Transactions and Arrangements).

In conjunction with the financing by the Partnership of its producing and non-producing oil and gas properties and

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015

(Unaudited)

~~operations~~acquisition ~~(other~~fee ~~than~~equal ~~the~~to ~~Offering~~2% ~~described~~of in the ~~Registration~~contract ~~Statement)~~price ~~and in consideration~~ for ~~the~~each ~~services~~property toacquired. beThe ~~performed by the General Partner and the~~ Manager inwill ~~connection~~also ~~therewith,~~be ~~the~~entitled ~~General~~to ~~Partner~~reimbursements ~~and~~of ~~the~~acquisition ~~Manager~~expenses ~~will~~for ~~receive~~each aproperty ~~financing~~acquired, ~~coordination~~with ~~fee equal to 0.75% of~~ the ~~principal~~aggregate amount of ~~any financing (as~~ the ~~Partnership~~acquisition ~~draws~~fee itand ~~down~~reimbursement ifof itacquisition isexpenses not ~~100% funded in a single closing), which will be paid two-thirds (0.5%)~~ to ~~the~~exceed ~~Manager and one-third (0.25~~3%) toof the ~~General~~contract ~~Partner. (See~~price ~~Note~~for 5each -property ~~Related Party Transactions and Arrangements)~~acquired.

~~During~~When the ~~three~~Manager ~~months~~operates ~~ended~~the ~~March 31,~~Partnership’s ~~2015,~~properties ~~$52~~pursuant to a model form operating agreement,~~260~~ ~~had~~it ~~been~~will ~~incurred~~receive byreimbursement ~~the~~at ~~Manager~~actual cost for ~~monthly~~all ~~management~~direct ~~fee~~expenses ~~services~~incurred ~~under~~by it on behalf of the ~~Management~~Partnership, ~~Agreement. No~~including ~~fees~~expenses ~~were~~to ~~incurred~~gather, ~~during~~transport, process, treat and market the ~~three~~Partnership’s ~~months~~oil ~~ended~~and ~~March~~natural ~~31,~~gas ~~2014. The~~production; ~~management~~and ~~fee~~well ~~payable~~supervisory asfees ofat ~~March~~competitive ~~31,~~rates ~~2015~~for maintaining and ~~December~~operating ~~31,~~the ~~2014~~wells ~~was~~during ~~$76,120~~drilling and ~~$23,860,~~producing ~~respectively~~operations.

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) 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 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 5 — Related Party Transactions and Arrangements).

During the three and six months ended June 30, 2015, $76,050 and $128,310, respectively, had been incurred by the Manager for monthly management fee services under the Management Agreement. No fees were incurred during the three and six months ended June 30, 2014. The management fee payable as of June 30, 2015 and December 31, 2014 was $112,170 and $23,860, respectively.

On September 11, 2015, the Partnership suspended the acceptance of subscriptions pursuant to the Offering in anticipation of formally terminating the Offering in the near future. Also on September 11, 2015, in anticipation of the termination of the Offering, the Partnership and the Manager mutually terminated the Management Agreement dated June 16, 2014, pursuant to which the Manager was engaged to provide management and operating services regarding substantially all aspects of the Partnership’s oil and gas operations. As a result, no amounts previously accrued for or outstanding as of June 30, 2015 will be paid to the Manager related to the monthly management fees pursuant to the Management Agreement (See Note 7 — Subsequent Events).

Note 4 — Common Units

As of ~~March~~June 3130, 2015, the Partnership had ~~418~~511,~~919~~170 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.

Date Paid	Period Covered	Total Distribution
January 2, 2015	December 1, 2014-December 31, 2014	$	29,598
February 2, 2015	January 1, 2015-January 31, 2015	30,824
March 2, 2015	February 1, 2015-February 28, 2015	31,183
Total		$	91,605

For the three months ended March 31, 2015, the Partnership paid cash dividends of $91,605 and had a net loss of $382,983. As of March 31, 2015, the Partnership had a distribution payable of $42,436 for dividends accrued in the month of March 2015, which was paid on April 1, 2015. There were no distributions accrued or paid during the three months ended March 31, 2014.

Note 5 — Related Party Transactions and 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, it is expected that the Dealer Manager will receive up to 3.0% of the gross proceeds of the Offering as a dealer manager fee. During the three months ended March 31, 2015, $226,751 of commissions and fees were incurred from the Dealer Manager. No commissions and fees were incurred from the Dealer Manager during the three months ended March 31, 2014.

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

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 March 31, 2015, organizational and offering costs exceeded 1.5% of gross proceeds received from the Offering by $3.2 million, due to the ongoing nature of the Offering and the fact that many expenses were paid before the Offering commenced.

During the three months ended March 31, 2015 and 2014, $194,293 and $28,081 of related party costs were incurred, respectively, by the Partnership in connection with the Offering. As of March 31, 2015, the Partnership had amounts due to affiliate, which included $219,720 to affiliates of the General Partner or the Manager for costs incurred by the Partnership. As of December 31, 2014, the Partnership had amounts due to affiliates, which included $748,710 to the General Partner for costs

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015

(Unaudited)

The below table shows the distributions paid on shares outstanding during the six months ended June 30, 2015.

incurred by the Partnership.



Date Paid	Period Covered	Total Distribution
January 2, 2015	December 1, 2014 - December 31, 2014	$	29,598
February 2, 2015	January 1, 2015 - January 31, 2015	30,824
March 2, 2015	February 1, 2015 - February 28, 2015	31,183
April 1, 2015	March 1, 2015 - March 31, 2015	42,435
May 1, 2015	April 1, 2015 - April 30, 2015	42,962
June 1, 2015	May 1, 2015- May 31, 2015	48,699
Total		$	225,701

For the six months ended June 30, 2015, the Partnership paid cash dividends of $225,701 and had a net loss of $786,860. As of June 30, 2015, the Partnership had a distribution payable of $50,183 for dividends accrued in the month of June 2015, which was paid on July 1, 2015. There were no distributions accrued or paid during the six months ended June 30, 2014.

Note 5 — Related Party Transactions and Arrangements

Fees Paid in Connection with the Offering

The Dealer Manager is an entity which is under common control with the ARC Sponsor. 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, it is expected that the Dealer Manager will receive up to 3.0% of the gross proceeds of the Offering as a dealer manager fee. During the three and six months ended June 30, 2015, $177,052 and $403,803, respectively, of commissions and fees were incurred from the Dealer Manager. No commissions and fees were incurred from the Dealer Manager during the three and six months ended June 30, 2014.

During the three and six months ended June 30, 2015, $304,785 and $499,078, respectively, of related party costs were incurred by the Partnership in connection with the Offering. As of June 30, 2015, the Partnership had amounts due to affiliate of $1,109,447 of which $189,425 related to costs incurred in connection with the Offering. As of December 31, 2014, the Partnership had amounts due to affiliates of $1,673,195 of which $748,710 related to costs incurred in connection with the Offering.

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 three and six months ended ~~March~~June 3130, 2015 and 2014, 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 disposition fee for a total of 1.0%. (See Note 3 - Manager and the Management Agreement). During the three months ended March 31, 2015 and 2014, 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) 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 financing coordination fee for a total of 0.75%. (See Note 3 - Manager and the Management Agreement). During the three months ended March 31, 2015 and 2014, no financing fees were paid to the General Partner in connection with the operations of the Partnership.

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 "Advisory Fees" on our consolidated statements of operations.

During the three months ended March 31, 2015, $158,121 was incurred in connection with the operations of the Partnership and for the above strategic advisory services. No fees were incurred in connection with the operations of the Partnership during the three months ended March 31, 2014. As of March 31, 2015, the Partnership had amounts due to affiliates, net of receivables of $663,251 for costs incurred by the Partnership. As of December 31, 2014, the $920,000 payable to the Dealer Manager is included in due to affiliates on the Partnership's 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 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

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015

(Unaudited)

~~increasing~~the ~~percentages~~General ofPartner, ~~distributions~~the ~~made~~Manager, onor ~~the~~their ~~Common~~respective ~~Units~~affiliates), ~~above~~(including ~~the~~when ~~targeted~~paid ~~minimum~~any ~~quarterly~~deferred ~~distributions~~payment or "earn out" amounts), ~~which~~payable ~~will~~in becash ~~determined~~concurrently ~~and~~with ~~established~~the ~~upon~~Manager's disposition fee for a ~~listing~~total of 1.0%. (See Note 3 — Manager and the ~~Common~~Management ~~Units~~Agreement). During the three and six months ended June 30, 2015 and 2014, no disposition fees were reimbursed to the General Partner in connection with the operations of the Partnership.

~~The~~In ~~Manager~~conjunction ~~will~~with ~~also~~the befinancing ~~entitled~~by tothe Partnership of its producing and non-producing oil and gas properties and operations (other ~~fees~~than ~~per~~the Offering described in the ~~Management~~prospectus) ~~Agreement~~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 financing coordination fee for a total of 0.75%. (See Note 3 -— Manager and the Management Agreement). During the three and six months ended June 30, 2015 and 2014, no financing fees were paid to the General Partner in connection with the operations of the Partnership.

During the three and six months ended June 30, 2015, $152,570 and $310,691, respectively, was incurred in connection with the operations of the Partnership and for the above strategic advisory services. No fees were incurred in connection with the operations of the Partnership during the three and six months ended June 30, 2014. As of June 30, 2015, the Partnership had amounts due to affiliates of $1,109,447 of which $920,023 related to costs incurred in connection with the operations of the Partnership. As of December 31, 2014, the Partnership had amounts due to affiliate of $1,673,195 of which $920,000 related to costs incurred in connection with the operations of the Partnership.

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 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.

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

Note 6 — Commitments and Contingencies

Litigation

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

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

Note 7 — Subsequent Events

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

Suspension of Offering and Termination of Management Agreement

If approved by the Partnership's unitholders, the Partnership intends to file a certificate of dissolution, pay, satisfy, resolve or make reasonable provisions for claims and obligations as well anticipated costs associated with the Partnership's dissolution and liquidation. The Partnership estimates legal fees, ongoing insurance costs and other professional fees to be approximately $600,000 to $700,000 through the dissolution and liquidation. The Partnership expects to recognize the majority of these expenses during the third and fourth quarters of 2015, and no expenses associated with the termination of the Offering have been recognized in the current period financial statements.

In order to make distributions to unitholders in an amount equal to 100% of their capital contributions and cover all outstanding expenses of the Partnership, the Partnership intends on distributing all available cash and expects to have a receivable from the General Partner.

Distributions paid

On ~~April~~July 1, 2015, the Partnership paid a cash distribution of $4250,~~436~~183 to holders of Common Units for the month of ~~March~~June 2015. On August, 1, 2015, the Partnership paid a cash distribution of $54,618 to holders of Common Units for the month of July 2015. On September 1, 2015, the Partnership paid a cash distribution of $56,116 to holders of Common Units for the month of August 2015.

On September 25, 2015, the Partnership suspended its monthly distributions effective as of September 30, 2015. The final payment of distributions will occur on or about October 1, 2015 in connection with the Partnership’s September 2015 dividend.

Sale of Common Units

As of ~~April~~August 3031, 2015, the Partnership had ~~435~~562,~~584~~287 Common Units outstanding and ~~has~~had raised total gross proceeds of $810,~~404~~933,~~001~~920. Subsequent to ~~March~~June 3130, 2015, the Partnership issued 1651,~~665~~117 Common Units for total gross proceeds of $~~330~~1,~~000~~022,334 based on a per unit value of up to $20.00.

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

The following discussion should be read in conjunction with the accompanying unaudited financial statements of American Energy Capital Partners - Energy Recovery Program, LP and its consolidated subsidiary, AECP Operating Company, LLC (together, the "Partnership") and the notes thereto, and other financial information included elsewhere in this Quarterly Report on Form 10-Q. As used herein, the terms "we," "our" and "us" refer to the Partnership.

The forward-looking statements contained in this Quarterly Report on Form 10-Q may include statements as to:


•	our use of the proceeds of the Offering (as defined below);


•	our business and investment strategy;


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


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


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


•	the degree and nature of our competition;


•	the availability of qualified personnel;


•	other factors set forth under the caption "Risk Factors" in our Annual Report on Form 10-K

In addition, words such as "anticipate," "believe," "expect" and "intend" indicate a forward-looking statement, although not all forward-looking statements include these words. The forward-looking statements contained in this Quarterly Report on Form 10-Q involve risks and uncertainties. Our actual results could differ materially from those implied or expressed in the forward-looking statements for any reason.

You should not place undue reliance on these forward-looking statements. The forward-looking statements made in this Quarterly Report on Form 10-Q relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances occurring after the date of this Quarterly Report on Form 10-Q.

Overview

We are a Delaware limited partnership formed on October 30, 2013. Our 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~~our formation ~~of the Partnership~~, ~~the~~our 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 and we commenced ~~our~~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 ~~final~~Offering ~~termination~~is ~~date~~expected isto 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~~Initial ~~closing~~Closing"), the amount required for us to release equity proceeds from escrow, and began our 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~~our General Partner and its officers. We entered into a management services agreement (the "Management Agreement") with AECP Management, LLC (the "Manager"). ~~The~~Our 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 (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 ~~March 31~~June 30, 2015, we had not identified or acquired any oil and gas properties. As we have not yet acquired oil and gas properties, its principal source of cash is the proceeds from the Offering, which ~~the~~we ~~Partnership~~rely ~~relies~~ on to finance operations, distributions and capital investments.

Since May 2014 there has been a rapid and severe decline in oil and natural gas prices. Oil prices have fallen from approximately $108 per barrel on June 1, 2014 to approximately $4559 per barrel on ~~March~~June 1830, 2015; during the same period, natural gas prices have fallen from almost $5 per mcf to under $3 per mcf. The magnitude of these declines has likely set the stage for a later recovery as supply and demand fundamentals react to the severe price drops and markets are rebalanced.

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natural gas prices have fallen from almost $5 per mcf to under $3 per mcf. The magnitude of these declines has likely set the stage for a later recovery as supply and demand fundamentals react to the severe price drops and markets are rebalanced.

Additionally, in response to these market changes:

• oil and gas companies have significantly decreased their capital spending;

• the number of rigs drilling for oil and gas in the U.S. has decreased;

• oilfield service costs have decreased; and

• some distressed oil and gas companies are actively seeking to sell their oil and gas wells.

The severe decline in oil and natural gas prices that occurred late in 2014, which has continued into ~~early~~ 2015, has increased the volatility and amplitude of the other risks facing us and may have an impact on our business and financial condition. If oil and natural gas prices remain low for an extended period of time, drilling projects may become uneconomic, which could affect future drilling plans and growth rates. Low commodity prices could impact our revenue, which we intend to partially mitigate with our hedging program. Continued low commodity prices make it more challenging to hedge production at higher price levels. Lower sustained commodity prices or additional commodity price declines may lead to property impairment in future periods, which could have a material adverse effect on our results of operations in the period taken. In February 2015, ~~the~~we ~~Partnership~~were ~~was~~ renamed to American Energy Capital Partners - Energy Recovery Program, LP in order to reflect the industry environment.

On September 11, 2015, we suspended the acceptance of subscriptions pursuant to our initial public offering in anticipation of formally terminating the Offering in the near future. We have since terminated the Offering and intend to present a proposal for our dissolution and liquidation to our unitholders at a special meeting. In connection with our dissolution and liquidation, we intend to propose a plan to our unitholders that will include a distribution to unitholders in an amount equal to 100% of their capital contribution to us exclusive of any distributions already received.

Also on September 11, 2015, in anticipation of the termination of the Offering, we and the Manager mutually terminated the Management Agreement dated June 16, 2014, pursuant to which the Manager was engaged to provide management and operating services regarding substantially all aspects of our oil and gas operations. As a result, no amounts previously accrued for or outstanding as of June 30, 2015 will be paid to the Manager related to the monthly management fees pursuant to the Management Agreement.

Significant Accounting Estimates and Critical Accounting Policies

A summary of our accounting policies is set forth in Note 2 of the Notes to the Consolidated Financial Statements

and its Annual Report on Form 10-K for the year ended December 31, 2014 under “Item 7 – Management's Discussion and

Analysis of Financial Condition and Results of Operations – Significant Accounting Estimates and Critical Accounting

Policies.”

Results of Operations

We were formed to enable investors to invest, indirectly through ~~the Partnership~~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 it 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 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 its properties and distribute the net sales proceeds to our partners or list its 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, its 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 three months ended March 31, 2015, we incurred total operating expenses of $382,983, primarily related to investment banking fees, directors and officers insurance expenses, management fees and other professional expenses. During the three months ended March 31, 2014, we incurred total operating expenses of $184, primarily related to bank fees.13

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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 three and six months ended June 30, 2015, we incurred total operating expenses of $403,877 and $786,860, respectively, primarily related to investment banking fees, directors and officers insurance expenses, management fees and other professional expenses. During the three and six months ended June 30, 2014, we incurred total operating expenses of $73,640 and $73,824, respectively, related to investment banking fees, directors and officers insurance expenses and other professional expenses.

Liquidity and Capital Resources

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


•	subscription proceeds of the Offering;


•	cash flow from future operations; and


•	our borrowings.

12On September 11, 2015, we suspended the acceptance of subscriptions pursuant to our initial public offering in anticipation of formally terminating the Offering in the near future. We have since terminated the Offering and intend to present a proposal for our dissolution and liquidation to our unitholders of record at a special meeting. In connection with our dissolution and liquidation, we intend to propose a plan to our unitholders that will include a distribution to unitholders in an amount equal to 100% of their capital contribution to us exclusive of any distributions already received.

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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~~our partnership agreement does not require that we make regular monthly or quarterly distributions, our General Partner distributes 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 we accepted the subscription proceeds from the holders of Common Units, on the $20.00 original purchase price per Common Unit, 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.

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 escrow break date on which such unit was issued. As of ~~March~~June 3130, 2015, we had a distribution payable of $4250,~~436~~183 for dividends accrued during the month of ~~March~~June 2015.

	Three Months Ended
	March 31, 2015
Distributions:
Distribution paid in cash	$	91,605
Total distributions	$	91,605
Source of distribution coverage:
Proceeds from issuance of Common Units	$	91,605		100	%
Cash flows used in operations	—			—
Total sources of distributions	$	91,605		100	%
Cash flows used in operations	$	(376,148	)
Net loss	$	(382,983	)

On September 25, 2015, we suspended our monthly distributions effective as of September 30, 2015. The final payment of distributions will occur on or about October 1, 2015 in connection with our September 2015 dividend.

Common Unit Repurchase Program



	Three Months Ended					Six Months Ended
	June 30, 2015					June 30, 2015
Distributions:
Distribution paid in cash	$	134,096				$	225,701
Total distributions	$	134,096				$	225,701
Source of distribution coverage:
Proceeds from issuance of Common Units	$	92,742		69	%	$	184,347		82	%
Cash flows provided by operations	41,354			31	%	41,354			18	%
Total sources of distributions	$	134,096		100	%	$	225,701		100	%
Cash flows provided by (used in) operations	$	41,354				$	(334,794	)
Net income (loss)	$	(403,877	)			$	(786,860	)

We offer a common unit repurchase program which may provide eligible unitholders with limited, interim liquidity prior to a liquidity event by enabling them to sell common units back to us, subject to restrictions and applicable law, if such repurchases do not impair our capital or operations as determined by our general partner. Subject to limited exceptions, a unitholder must have beneficially held the common units for at least one year prior to offering them for sale to us through our common unit repurchase program, and only those unitholders who purchased their Common Units from us or received their Common Units from us (directly or indirectly) through one or more non-cash transactions may be able to participate in the common unit repurchase program. In other words, once our Common Units are transferred for value by a unitholder, the 14

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~~transferee and all subsequent holders of the~~ Common ~~Units~~Unit ~~are~~Repurchase ~~not eligible to participate in the common unit repurchase program.~~ Program

We offer a common unit repurchase program which may provide eligible unitholders with limited, interim liquidity prior to a liquidity event by enabling them to sell common units back to us, subject to restrictions and applicable law, if such repurchases do not impair our capital or operations as determined by our General Partner. Subject to limited exceptions, a unitholder must have beneficially held the common units for at least one year prior to offering them for sale to us through our common unit repurchase program, and only those unitholders who purchased their Common Units from us or received their Common Units from us (directly or indirectly) through one or more non-cash transactions may be able to participate in the common unit repurchase program. In other words, once our Common Units are transferred for value by a unitholder, the transferee and all subsequent holders of the Common Units are not eligible to participate in the common unit repurchase program.

Pursuant to the terms of our common unit repurchase program, we intend to make repurchases, if requested, at least once quarterly. We will repurchase common units on the last business day prior to the filing of each quarterly financial filing (and in all events on a date other than a distribution payment date). Each unitholder whose repurchase request is granted will receive the repurchase amount within 30 days after the fiscal quarter in which we grant its repurchase request. Subject to the limitations described in our Registration Statement, we also will repurchase Common Units upon the request of the estate, heir or beneficiary, as applicable, of a deceased unitholder. We will limit the number of Common Units repurchased pursuant to our common unit repurchase program in any calendar year to 5% of the weighted average number of Common Units outstanding on December 31st of the previous calendar year.

Funding for the common unit repurchase program will be derived from proceeds we maintain from the sale of Common Units, borrowings and other operation funds, if any, as our General Partner, in its sole discretion, may reserve for this purpose. We cannot guarantee that the funds set aside for the common unit repurchase program will be sufficient to accommodate all requests made each year.

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~~our 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 our 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~~our 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~~our 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~~our General Partner's prior approval.

Commencing with a payment for the month of the initial closing, and for each month thereafter through the ~~final~~Final ~~termination~~Termination ~~date~~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 last day of the preceding month; 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, 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 from the initial closing through the final termination date; and (ii) the average outstanding indebtedness during the preceding month.15

The management fee includes the Manager’s general and administrative overhead expenses and the Manager will not

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~~receive~~sum aof: ~~separate~~(i) ~~reimbursement~~the ofcapital ~~its~~contributions ~~general~~made ~~and~~by ~~administrative~~the ~~expenses~~holders ~~from~~of ~~any~~Common ~~source~~Units ~~other~~to ~~than~~us from the ~~monthly~~initial ~~management~~closing ~~fee.~~through ~~However,~~the last day of the ~~Manager~~preceding ~~will~~month; ~~receive~~and ~~reimbursement~~(ii) ofour ~~its~~average ~~direct~~outstanding ~~expenses~~indebtedness ~~paid~~during tothe ~~third-parties~~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 our General Partner, 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) 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 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 our behalf, 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~~our General Partner in connection with the disposition of our properties from time to time, the Manager and ~~the~~our 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~~our 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~~our General Partner.

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) and in consideration for the services to be performed by ~~the~~our General Partner and the Manager in connection therewith, ~~the~~our 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~~our General Partner.

During the three and six months ended ~~March~~June 3130, 2015, $5276,~~260~~050 and $128,310, respectively had been incurred by the Manager for monthly management fee services under the Management Agreement. No fees were incurred during the three and six months ended ~~March~~June 3130, 2014. The management fee payable as of ~~March 31~~June 30, 2015 and December 31, 2014 was $76112,~~120~~170 and $23,860, respectively.

On ~~February~~September 1711, 2015, ~~Chesapeake~~we ~~Energy~~suspended ~~Corporation (“CHK”) filed suit in~~ the ~~District~~acceptance ~~Court~~ of ~~Oklahoma~~subscriptions ~~County,~~pursuant ~~Oklahoma~~to ~~against~~the ~~American~~Offering ~~Energy~~in ~~Partners,~~anticipation ~~LP (“AELP”), and certain other affiliates~~ of ~~the~~formally ~~Manager.~~terminating ~~CHK alleged that Aubrey K. McClendon misappropriated confidential information and trade secrets from CHK, which he subsequently used for~~ the ~~benefit~~Offering ofin ~~AELP and~~ the ~~named~~near ~~AELP affiliates~~future. ~~CHK’s~~Also ~~claims~~on ~~against~~September ~~AELP~~11, ~~and the AELP affiliates include violations of the Oklahoma Uniform Trade Secrets Act~~2015, ~~aiding and abetting~~ in ~~Mr.~~anticipation ~~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~~termination ~~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. On April 14Offering, ~~2015~~we ~~American Energy - Utica (“AEU”)~~ and the ~~Energy~~Manager &mutually ~~Minerals~~terminated ~~Group announced that Chesapeake had dismissed AEU and John Doe Defendants 1-20 from~~ the ~~lawsuit~~Management ~~filed~~Agreement bydated ~~Chesapeake.~~June On16, ~~April 30~~2014, ~~2015~~pursuant ~~AELP~~to ~~announced~~which ~~that~~ the ~~Oklahoma~~Manager ~~District~~was ~~Court~~engaged ~~granted a motion~~ to ~~compel~~provide ~~arbitration~~management ~~that had been filed by AELP~~ and ~~other~~operating ~~AELP~~services ~~affiliates, holding~~regarding ~~that~~substantially ~~CHK’s~~all ~~claims~~aspects ~~against~~of ~~AELP~~our ~~and~~oil ~~the other defendants must be pursued in arbitration accordance with the agreements between CHK~~ and ~~Mr.~~gas ~~McClendon~~operations. As a result ~~of the decision and CHK’s earlier dismissal of AEU and the John Doe Defendants~~, ~~the~~no ~~proceeding~~amounts ~~frilled~~previously byaccrued ~~CHK in the District Court~~ for ~~Oklahoma~~or ~~County~~outstanding isas ~~ended~~of ~~and~~June ~~CHK~~30, ~~must~~2015 ~~pursue~~will ~~its~~be ~~claims~~paid into ~~arbitration. There are no claims asserted against~~ the Manager ~~and~~related weto ~~do not believe that this matter will have a material adverse effect on our operations, financial condition or prospects. Further, in connection with~~ the ~~formal~~monthly ~~investigation~~management offees ~~Chesapeake~~pursuant ~~commenced in 2012 by the U.S. Department of Justice into potential antitrust violations relating~~ to the ~~acquisition~~Management ~~by Chesapeake of certain oil and gas leases, Mr~~Agreement. ~~McClendon is also being investigated.~~

Related Party Arrangements

Fees Paid in Connection with the Offering

~~Realty~~The ~~Capital~~Dealer ~~Securities,~~Manager ~~LLC,~~is an entity which is under common control with the ARC ~~sponsor, is the Dealer Manager~~Sponsor. 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, it is expected that the Dealer Manager will receive up to 3.0% of the gross proceeds of the Offering as a dealer manager fee. During the three and six months ended ~~March~~June 3130, 2015, $~~226~~177,~~751~~052 and $403,803, respectively, of commissions and fees were incurred from the Dealer Manager. No commissions and fees were incurred from the Dealer Manager during the three and six months ended ~~March~~June 3130, 2014.

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

15We 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 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 our General Partner and the Manager. As of June 30, 2015, organizational and offering costs exceeded

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~~Offering,~~1.5% ~~including~~of ~~transfer~~gross ~~agency~~proceeds ~~services~~received ~~provided~~from bythe anOffering ~~affiliate~~by of$3.9 ~~the Dealer Manager~~million.

WeDuring ~~are~~the ~~responsible~~three ~~for organizational~~ and ~~offering~~six ~~costs~~months ~~from~~ended ~~the ongoing Offering~~June 30, ~~excluding~~2015 ~~selling commissions~~ and ~~dealer~~2014, ~~manager fees~~$304,785 upand to$499,078, ~~a maximum of 1.5% of gross proceeds received from its ongoing Offering of Common Units~~respectively, ~~measured at the end~~ of ~~the~~related ~~Offering.~~party ~~Organizational and offering~~ costs inwere ~~excess~~incurred ofby ~~the~~us ~~1.5%~~in ~~cap~~connection aswith of the ~~end of the~~ Offering. As ~~are the responsibility~~ of ~~the~~June 30, ~~General~~2015, ~~Partner~~we ~~and~~had ~~the~~amounts ~~Manager.~~due ~~The~~to ~~General~~affiliate ~~Partner will be allocated two-thirds~~ of ~~this~~ $1~~.5%~~,109,447 ~~reimbursement~~of ~~cap~~which ~~and~~$189,425 ~~the~~related ~~Manager~~to ~~will~~costs beincurred ~~allocated~~in ~~one-third~~connection ofwith ~~such~~the ~~reimbursement cap~~Offering. As of ~~March~~December 31, ~~2015~~2014, ~~organizational~~we ~~and~~had ~~offering~~amounts ~~costs~~due ~~exceeded~~to ~~1.5%~~affiliates of ~~gross~~$1,673,195 ~~proceeds~~of ~~received~~which ~~from the Offering by~~ $~~3.2 million~~748,710 ~~due~~related to ~~the~~costs ~~ongoing~~incurred ~~nature~~in ofconnection ~~the~~with ~~Offering and~~ the ~~fact that many expenses were paid before the~~ Offering ~~commenced~~.

~~During~~Fees ~~the~~paid ~~three months ended March 31, 2015 and 2014, $194,293 and $28,081 of related party costs were incurred, respectively, by us~~ in ~~connection~~Connection with the Offering. As of March 31, 2015, we had amounts due to affiliate, which included $219,720 to affiliates of the General Partner or the Manager for costs incurred by us. As of December 31, 2014, we had amounts due to affiliates, which included $748,710 to the General Partner for costs incurred by us.Operations

~~Fees~~We ~~paid~~will inreimburse ~~Connection~~our ~~with~~General ~~Operations~~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 our General Partner for the ~~Partnership~~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 our 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 three and six months ended June 30, 2015 and 2014, no administrative costs of our General Partner were reimbursed in connection with our operations.

WeIn ~~will~~conjunction ~~reimburse~~with the ~~General~~disposition ~~Partner~~of onour aproducing ~~monthly~~and ~~basis~~non-producing ~~for~~oil ~~its~~and ~~allocable~~gas ~~portion~~properties ofand ~~administrative~~in ~~costs~~consideration ~~and~~for ~~third-party~~the ~~expenses~~services itto ~~incurs~~be orperformed ~~payments~~by itour ~~makes~~General onPartner ~~our~~in ~~behalf.~~connection ~~Administrative~~with ~~costs~~the ~~include~~disposition ~~all~~of ~~customary~~our ~~and~~properties ~~routine~~from ~~expenses~~time ~~incurred~~to bytime, ~~the~~our General Partner ~~for~~will ~~the~~receive ~~conduct~~reimbursement of ~~our~~its ~~administration,~~respective ~~including~~costs ~~legal,~~incurred ~~finance,~~in ~~accounting,~~connection ~~secretarial,~~with ~~travel,~~such ~~office rent~~activities, ~~telephone,~~plus ~~data~~a ~~processing~~fee ~~and~~equal ~~other~~to ~~items~~0.5% of athe ~~similar~~contract ~~nature.~~sales ~~Administrative~~price ~~costs~~(excluding ~~do not include~~ any ~~organization~~properties ~~and~~acquired ~~offering~~from ~~expenses~~us ~~incurred~~ by ~~the~~our General Partner, ~~and~~the ~~its~~Manager, or their respective affiliates.), ~~Administrative~~(including ~~costs~~when ~~and~~paid ~~other~~any ~~charges~~deferred ~~for~~payment ~~goods~~or ~~and~~"earn ~~services~~out" ~~must~~amounts), bepayable ~~fully~~in ~~supportable~~cash asconcurrently towith the ~~necessity~~Manager's ~~thereof~~disposition ~~and~~fee ~~the~~for ~~reasonableness~~a total of ~~the amount charged~~1. 0%. During the three and six months ended ~~March~~June 3130, 2015 and 2014, no ~~administrative~~disposition ~~costs~~fees ofwere ~~the~~reimbursed to our General Partner ~~were reimbursed~~ in connection with our operations.

In conjunction with the ~~disposition~~financing of our producing and non-producing oil and gas properties and operations (other than the Offering described in the prospectus) and in consideration for the services to be performed by ~~the~~our General Partner in connection ~~with~~therewith, ~~the disposition of~~ our ~~properties from time to time, the~~ General Partner will receive ~~reimbursement~~a offinancing ~~its~~coordination ~~respective costs incurred in connection with such activities, plus a~~ fee equal to 0.525% of the ~~contract~~principal ~~sales~~amount ~~price~~of ~~(excluding~~ any ~~properties~~financing ~~acquired~~(as ~~from~~we usdraw byit ~~the~~down ~~General~~if ~~Partner,~~it ~~the~~is ~~Manager,~~not or100% ~~their~~funded ~~respective~~in ~~affiliates),~~a ~~(including~~single ~~when paid any deferred payment or "earn out" amounts~~closing), payable in cash concurrently with the Manager's ~~disposition~~financing coordination fee for a total of 1.0.75%. ~~(See~~ ~~Note 3 - Manager and the Management Agreement).~~ During the three and six months ended ~~March~~June 3130, 2015 and 2014, no ~~disposition~~financing fees were ~~reimbursed~~paid to ~~the~~our 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) 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 financing coordination fee for a total of 0.75%. (See Note 3 - Manager and the Management Agreement). During the three months ended March 31, 2015 and 2014, no financing fees were paid to the General Partner in connection with our operations.

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 "Advisory Fees" on our consolidated statements of operations.

During the three and six months ended ~~March~~June 3130, 2015, $~~158~~152,~~121~~570 and $310,691, respectively, was incurred in connection with ~~the~~our operations ~~of the Partnership~~ and for the above strategic advisory services. No fees were incurred in connection with ~~the~~our operations ~~of the Partnership~~ during the three and six months ended ~~March~~June 3130, 2014. As of ~~March~~June 3130, 2015, ~~the~~we ~~Partnership~~ had amounts due to affiliates, ~~net~~ of $1,109,447 ~~receivables~~ of which $~~663~~920,~~251~~023 ~~for~~related to costs incurred byin ~~the~~connection ~~Partnership~~with our operations. As of December 31, 2014, ~~the~~we ~~$920,000~~had ~~payable~~amounts due to ~~the~~affiliate ~~Dealer~~of ~~Manager~~$1,673,195 isof ~~included~~which in$920,000 ~~due~~related to ~~affiliates~~costs onincurred ~~the~~in ~~Partnership's~~connection ~~consolidated~~with ~~balance~~our ~~sheets~~operations.

Incentive Distribution Rights

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

Upon a sale of all or substantially all of our properties, ~~the~~our 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 our properties net of expenses and of the payment of all 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.

16Upon a listing of the Common Units on a national securities exchange, our 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 our 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.

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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.

The Manager will also be entitled to other fees per the Management Agreement.

Recent Developments

If approved by our unitholders, we intend to file a certificate of dissolution, pay, satisfy, resolve or make reasonable provisions for claims and obligations as well anticipated costs associated with our dissolution and liquidation. We estimate legal fees, ongoing insurance costs and other professional fees to be approximately $600,000 to $700,000 through the dissolution and liquidation. We expect to recognize the majority of these expenses during the third and fourth quarters of 2015, and no expenses associated with the termination of the Offering have been recognized in the current period financial statements.

In order to make distributions to unitholders in an amount equal to 100% of their capital contributions and cover all our outstanding expenses, we intend on distributing all available cash and expect to have a receivable from the General Partner.

Item 3. 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 ~~March 31~~June 30, 2015, we are currently not exposed to interest rate or foreign currency market risks.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

InDisclosure ~~accordance~~controls ~~with~~and ~~Rules~~procedures ~~13a-15(b)~~are controls and ~~15d-15(b)~~other ofprocedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, weprocessed, ~~under~~summarized ~~the supervision~~ and ~~with~~reported within the ~~participation~~time ofperiods ~~the~~specified ~~General~~in ~~Partner'~~the SEC’s ~~Chief~~rules ~~Executive Officer~~ and ~~Chief~~forms. ~~Financial~~Disclosure ~~Officer,~~controls ~~carried~~and ~~out~~procedures aninclude, ~~evaluation~~without oflimitation, ~~the effectiveness of our disclosure~~ controls and procedures ~~(as~~designed ~~defined~~to inensure ~~Rule~~that ~~13a-15(e)~~information ~~and~~required ~~Rule~~to ~~15d-15(e)~~be ofdisclosed ~~the~~in ~~Exchange~~our ~~Act)~~reports asfiled ofor ~~the~~submitted ~~end~~under of the ~~period~~Exchange ~~covered~~Act byis ~~this~~accumulated ~~Quarterly~~and ~~Report~~communicated onto ~~Form~~management, ~~10-Q~~including ~~and determined that~~ our ~~disclosure~~Chief ~~controls~~Executive Officer and ~~procedures~~Chief ~~are~~Financial ~~effective~~Officer, asto ofallow ~~the~~timely ~~end~~decisions ofregarding ~~the~~required ~~period covered by this Quarterly Report on Form 10-Q~~disclosure.

NoIn ~~change~~accordance ~~occurred~~with inRules 13a-15(b) and 15d-15(b) of the Exchange Act, we, under the supervision and with the participation of our ~~internal~~General ~~controls~~Partner's ~~over~~Chief ~~financial~~Executive ~~reporting~~Officer and Chief Financial Officer, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(fe) and ~~15(d)~~Rule 15d-15(fe) of the Exchange Act) ~~during~~as of the ~~three~~end ~~months~~of ~~ended~~the ~~March~~period ~~31,~~covered ~~2015~~by this Quarterly Report on Form 10-Q and determined that ~~has~~our ~~materially~~disclosure ~~affected,~~controls orand isprocedures ~~reasonably~~are ~~likely~~effective toas ~~materially~~of ~~affect,~~the ~~our~~end ~~internal~~of ~~controls~~the ~~over~~period ~~financial~~covered ~~reporting~~by this Quarterly Report on Form 10-Q.

17No change occurred in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15(d)-15(f) of the Exchange Act) during the six months ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART II

Item 1. Legal Proceedings.

At the end of the period covered by this Quarterly Report on Form 10-Q, we were not a party to any material, pending legal proceedings.

Item 1A. Risk Factors.

There have been no material changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K.

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

We did not sell any equity securities that were not registered under the Securities Act during the ~~three~~six months ended ~~March~~June 3130, 2015.

On May 8, 2014, the SEC declared effective ~~the~~our ~~Partnership's~~ Registration Statement on Form S-1 (File No. 333-192852) filed under the Securities Act and we commenced its initial public offering, on a "reasonable best efforts" basis, of up to 100.0 million Common Units at a price per unit of $20.00. As of ~~March~~June 3130, 2015, ~~the~~we ~~Partnership~~ had issued ~~418~~511,~~919~~170 Common Units for $89.19 million.

As of ~~March~~June 3130, 2015, offering costs of approximately $34.86 million were associated with the issuance of Common Units.

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 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~~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 ~~March~~June 3130, 2015, organizational and offering costs exceeded 1.5% of gross proceeds received from the Offering by $3.29 million~~, due to the ongoing nature of the Offering and the fact that many expenses were paid before the Offering commenced~~.

As of ~~March~~June 3130, 2015, our net offering proceeds, after deducting total organizational and offering costs, were approximately $45.2 million.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

~~Not~~On ~~applicable~~September 11, 2015, we suspended the acceptance of subscriptions pursuant to our initial public offering in anticipation of formally terminating the Offering in the near future. We have since terminated the Offering and intend to present a proposal for our dissolution and liquidation to our unitholders at a special meeting. In connection with our dissolution and liquidation, we intend to propose a plan to our unitholders that will include a distribution to unitholders in an amount equal to 100% of their capital contribution to us exclusive of any distributions already received.

18If approved by our unitholders, we intend to file a certificate of dissolution, pay, satisfy, resolve or make reasonable provisions for claims and obligations as well anticipated costs associated with our dissolution and liquidation. We estimate legal fees, ongoing insurance costs and other professional fees to be approximately $600,000 to $700,000 through the dissolution and liquidation. We expect to recognize the majority of these expenses during the third and fourth quarters of 2015, and no expenses associated with the termination of the Offering have been recognized in the current period financial statements.

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Item 6. Exhibits.

EXHIBITS INDEX

The following exhibits are included in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (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(5)		Amended and Restated Certificate of Limited Partnership of the Partnership
3.2(6)		Second Amended and Restated Agreement of Limited Partnership, dated as of April 29, 2015
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
10.4(7)		Investment Opportunity Allocation Agreement dated effective as of October 24, 2014, among the Partnership, the Manager and American Energy Management Services, LLC
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 Quarterly Report on Form 10-Q for the ~~three~~six months ended ~~March~~June 3130, 2015, formatted in XBRL: (i) the Consolidated Balance Sheets; (ii) the Consolidated Statements of Operations; (iii) the Consolidated Statement of Partners' Equity; (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 in Post-Effective Amendment No. 2 to the Partnership’s Registration Statement on Form S-1 on January 30, 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)	Previously filed with the SEC in Post-Effective Amendment No. 3 to the Partnership's Registration Statement on Form S-1 on February 17, 2015.
(6)	Previously filed with the SEC in Post-Effective Amendment No. 1 to Post-Effective Amendment No. 4 to the Partnership's Registration Statement on Form S-1 on April 29, 2015, which constitutes Post-Effective Amendment No. 5 to the Partnership's Registration Statement.
(7)	Previously filed with the SEC in Post-Effective Amendment No. 6 to the Partnership's Registration Statement on Form S-1 on May 1, 2015.

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AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP

SIGNATURES

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

	AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP
	By: American Energy Capital Partners GP, LLC, the Registrant's General Partner
Dated: May 14, 2015	By: /s/ William M. KahaneName: William M. KahaneTitle: Chief Executive Officer and President(Principal Executive Officer)
Dated: September 29, 2015	By: /s/ William M. KahaneName: William M. KahaneTitle: Chief Executive Officer and President(Principal Executive Officer)
Dated: May 14, 2015	By: /s/ Nicholas RadescaName: Nicholas RadescaTitle: Chief Financial Officer and Treasurer(Principal Financial Officer and Principal Accounting Officer)
Dated: September 29, 2015	By: /s/ Nicholas RadescaName: Nicholas RadescaTitle: Chief Financial Officer and Treasurer(Principal Financial Officer and Principal Accounting Officer)

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Filing Compare · AMERICAN ENERGY CAPITAL PARTNERS - ENERGY RECOVERY PROGRAM, LP