Energy 11 POS AM 2015 FY Prospectus update (post-effective amendment)

As filed with the Securities and Exchange Commission on May 6, 2016

Registration No. 333-197476 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Post-Effective Amendment No. 4

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

ENERGY 11, L.P.

(Exact Name of Registrant as Specified in its Charter)

Delaware	1311	46-3070515
(State or other jurisdiction of incorporation or organization)	(Primary standard industrial classification code number)	(I.R.S. Employer Identification No.)

120 W 3rd Street

Suite 220

Fort Worth, Texas 76102

(817) 882-9192

(Address, including zip code, and telephone number, including area code, of registrants’ principal executive offices)

David S. McKenney

Chief Financial Officer

Energy 11 GP, LLC

814 East Main Street

Richmond, VA 23219

(804) 344-8121

 (Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

William B. Nelson

Haynes and Boone, LLP

1221 McKinney Street, Suite 2100

Houston, Texas 77010

Telephone: (713) 547-2084

Telecopy: (713) 236-5557

Approximate date of commencement of proposed sale of the securities to the public: From time to time after the Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. þ

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 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	(Do not check if a smaller reporting company)	Smaller reporting company þ

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

EXPLANATORY NOTE

This Post-Effective Amendment No. 4, or Amendment, to the Registration Statement on Form S-1 (File No. 333-197476), or the Registration Statement, of Energy 11, L.P., referred to herein as “we,” “us,” “our,” or the “Partnership”, is being filed pursuant to the undertakings in the Registration Statement to update and supplement the information contained in the Registration Statement, which was previously declared effective by the Securities and Exchange Commission, or the SEC, on April 27, 2016, the Prospectus.

This Amendment is being filed to amend and restate the Prospectus in its entirety and to (i) disclose the termination of the Management Services Agreement (the “Management Agreement”) between us, our wholly owned subsidiary Energy 11 Operating Company, LLC, E11 Management, LLC, (the “Former Manager”), and E11 Incentive Holdings, LLC, an affiliate of the Former Manager (“Incentive Holdings”), (ii) incorporate certain information from the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 that was filed with the SEC on March 28, 2016 (iii) provide additional information regarding the purchase of oil and gas properties, and (iv) update certain other information contained in the Registration Statement.  

No additional securities are being registered under this Amendment.  All applicable registration fees were paid at the time of the original filing of the Registration Statement. Accordingly, we hereby amend the Registration Statement by filing this Amendment, which relates to the registration of up to 100,263,158 common units of limited partner interest.

Prospective investors should carefully review the Prospectus

ENERGY 11, L.P.

An Offering of Common Units of Limited Partnership Interest

Minimum Offering: 1,315,790 Common Units

Maximum Offering: 100,263,158 Common Units

We plan to acquire working and other interests in producing and non-producing oil and natural gas properties in the United States.  Our primary purposes are to enhance the value of the properties we acquire through drilling and other exploration and development activities, generate revenue from the production and sale of oil and gas, and distribute cash to our partners.  We do not intend to apply to list the common units for trading on any securities exchange or on the over-the-counter market.

We are offering up to 100,263,158 common units of limited partner interest in this offering. Of the 100,263,158 common units, the first 5,263,158 common units were offered at $19.00 per common unit and we are now are offering the remaining 95,000,000 common units at $20.00 per common unit.  Each investor must purchase a minimum of $5,000 of common units.

The common units are being offered on a best efforts, minimum offering basis through David Lerner Associates, Inc., an unaffiliated broker-dealer. As of April 28, 2016, we had completed the sale of a total of 5,863,622 common units for total gross proceeds of $112.0 million and proceeds net of selling commissions and marketing expenses of $105.3 million.

We expect to terminate the offering when all of the common units offered by this prospectus have been sold or January 23, 2017 (whichever occurs sooner). We may extend the offering until no later than April 24, 2017, in order to achieve the maximum offering of 100,263,158 common units. 

We are an emerging growth company as that term is used in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, and are subject to reduced public company reporting requirements.  See “Prospectus Summary” and “Risk Factors.”

Investing in our common units involves a high degree of risk.  Before subscribing for common units you should carefully read the discussion of material risks of investing in our common units in “Suitability Standards” beginning on page 1 and in “Risk Factors” beginning on page 17.  These risks include the following:

·  We are a new entity with limited operating history ·  We have not selected all of our properties for acquisition so this is a “blind pool” offering ·  An investment in our common units is not a liquid investment ·  Our general partner is subject to conflicts of interest ·  The offering price of units was determined arbitrarily and, except as specified in this prospectus will not be adjusted during the term of the offering · Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income     ·  Cash distributions may be made out of offering proceeds or indebtedness we may incur ·  We cannot guarantee any return on the amount or timing of distributions ·  Our Partnership Agreement limits the fiduciary duty of our general partner ·  The general partner, the Former Manager and David Lerner Associates, Inc. (referred to herein as the dealer manager), will receive fees and compensation from the offering of common units and the operation of the Partnership ·  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution would be substantially reduced.

	Price To Public		Commissions & Marketing Expenses (2)		Proceeds To Energy 11, L.P. (3)
Per Common unit(1)	$	20.00	$	1.20	$	18.80
Total Maximum Offering	$	2,000,000,000	$	120,000,000	$	1,880,000,000

(1)           The initial 5,263,158 common units were sold at $19.00 per common unit, with the commissions and marketing expenses of $1.14 per common unit and proceeds to Energy 11, L.P. of $17.86 per common unit. See “Plan of Distribution”

(2)           We will pay the dealer manager a contingent, incentive fee based on the amount of distributions made by the Partnership after the holders of common units receive a specified amount of distributions per unit.  The contingent, incentive fee will be payable solely in cash and will not exceed 4% of the gross proceeds of the offering of common units.  If the maximum offering is achieved, the fee will not exceed $80,000,000.

(3)           Does not include the fees and expenses of the organization of the Partnership and the offering of common units which will be paid by the Partnership, which are estimated to be $8.0 million for the maximum offering.

We will comply with the provisions of Securities and Exchange Commission Rule 10b-9 under the Securities Exchange Act of 1934, as amended.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 Offered exclusively by David Lerner Associates, Inc.

The date of this prospectus is May 6, 2016.

TABLE OF CONTENTS

	Page
Suitability Standards	1
In General	1
Restrictions on Sales in Certain States	1
General Suitability Requirements for Purchasers of Common Units representing Limited Partner Interests	1
New Jersey Residents	1
Suitability Requirements for IRAs	1
Fiduciary Accounts	2
Additional Considerations for IRAs and Tax-Exempt Organizations	2
Qualified Plans	2
Restrictions Imposed by the USA PATRIOT Act and Related Acts	2
Forward Looking Statements	3
Prospectus Summary	4
Our Proposed Business	4
Our Investment Objectives	4
The Properties We Intend to Acquire and Develop	4
Oil and Gas Properties Acquired	5
Our General Partner	5
Management Agreement	6
Risk Factors	7
Financing	7
Borrowing Policy	8
Hedging Policy	8
Distributions	8
Sale of Properties, Merger or Listing of the Common Units	10
Summary Tax Consequences	11
The Offering	12
Emerging Growth Company	15
Ownership Chart	16
Risk Factors	17
Risks Related to an Investment in the Partnership	23
Risks Related to Our Business	23
Risks Related to the JOBS Act	35
Tax Risks to Common Unitholders	36
Conflicts of Interest	40
In General	40
Conflicts Regarding Transactions with the General Partner and its Members and Affiliates	40
Conflicts Regarding Other Activities of Affiliates of the General Partner	40
Conflicts Involving the Acquisition and Sale of Properties	41
Conflicts of Interest Relating to the Incentive Distribution Rights	42
Conflicts of Interest; Standard of Conduct	42
Source of Funds and Estimated Use of Offering Proceeds	43
Source of Funds	43
Estimated Use of Offering Proceeds	43
Compensation	45
Compensation Related to the Organization of the Partnership and Offering of Common Units	45
Compensation Related to the Operation of the Partnership	46
Compensation related to the Dissolution and Liquidation of the Partnership	47
Terms of the Offering	48
Subscription to the Partnership	48
Partnership Closings	48
Acceptance of Subscriptions	48
Status of the Offering	48
Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Overview	49
Oil and Gas Properties Acquired	49

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Financing	50
Management Agreement	50
Results of Operations	50
Oil, Natural Gas and NGL Sales	50
Operating Costs and Expenses	51
Management Fees	51
Acquisition Costs	51
General and Administrative Costs	51
Related Parties	52
Partners Equity	52
Distributions	52
Liquidity and Capital Resources	53
Critical Accounting Policies	53
Oil and Natural Gas Properties	53
Impairment	54
Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves	54
Accounting for Asset Retirement Obligations	55
Revenue Recognition	55
Oil, NGL and Natural Gas Sales and Natural Gas Imbalances	55
Recent Accounting Standards	55
Management	56
Directors and Executive Officers of the General Partner	56
Executive Compensation	58
Reimbursement of Expenses to General Partner in Connection with Offering Costs	58
Reimbursement of Expenses to General Partner in Connection with Operations of the Partnership	58
Director Independence	59
Ownership of Our General Partner	59
Prior Real Estate Programs	59
Settlement with the SEC	61
Alternative Investments	62
Proposed Activities	63
Our Investment Objectives	63
Oil and Gas Properties Acquired	63
Description of the Properties We Plan to Purchase	63
Borrowing Policy	65
Hedging Policy	66
Title to Properties	66
Environmental Review	66
Well Operations	66
Ongoing Operations	67
2015 Acquisition	67
Financing for the 2015 Acquisition	68
Oil and Gas Reserves	68
Proved Undeveloped Reserves	69
Production, Prices and Production Cost History	70
Delivery Commitments	70
Drilling Activity	70
Total Productive Wells	70
Developed and Undeveloped Acreage Position	71
Undeveloped Lease Expirations	71
Marketing and Customers	71
Insurance	71
Competition, Markets and Regulation	73
Competition	73
Seasonal Nature of Business	73
Environmental, Health and Safety Matters and Regulation	73
Other Regulation of the Oil and Natural Gas Industry	77

ii

Other Regulation	79
Capital Contribution and Distributions	80
Capital Contributions	80
Distributions	81
Sale of Properties, Merger or Listing of the Common Units	82
Fiduciary Duty of the General Partner	84
Material Federal Income Tax Consequences	86
Partnership Status	86
Tax Consequences of Common Unit Ownership	88
Tax Treatment of Operations	91
Disposition of Common Units	93
Tax-Exempt Organizations and Other Investors	94
Administrative Matters	95
State, Local and Other Tax Considerations	96
Future Legislative Changes	96
Certain Beneficial Owners of the Partnership	97
Summary of the Limited Partnership Agreement	97
Organization and Duration	97
Purpose	97
Power of Attorney	98
Cash Distributions	98
Capital Contributions	98
Voting Rights	98
Limited Liability	99
Issuance of Additional Securities	100
Amendment of the Partnership Agreement	100
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets	102
Termination and Dissolution	102
Liquidation and Distribution of Proceeds	103
Withdrawal or Removal of the General Partner	103
Transfer of General Partner Interest	103
Transfer of Ownership Interests in the General Partner	103
Transfer of Incentive Distribution Rights and Class B Units	103
Meetings; Voting	104
Status as Limited Partner	104
Non-Citizen Assignees; Redemption	104
Indemnification	104
Reimbursement of Expenses	105
Books and Reports	105
Right to Inspect Our Books and Records	105
Governing Law, Venue and Jurisdiction	106
Transferability of Interests	106
Lack of Liquidity in Investment in Common Units	106
Conditions to Becoming a Substitute Partner	106
Plan of Distribution	106
FINRA Action	109
Subscriptions	110
Minimum Investment	110
Subscriber Representations and Subscription Procedures	110
Instruction Concerning “Important Information”	111
Binding Effect of the Limited Partnership Agreement on You	111
Your Citizenship and Residency	111
Co-Signature By Selling Dealer	112
How to Subscribe	112
Sales Material	112
Legal Opinions	112
Change in Accounting Firm	112
Experts	113

iii

Additional Information	113
Information Incorporated by Reference	114
Glossary of Oil and Gas Terms	115
Index to Financial Statements	F-1
Limited Partnership Agreement	Exhibit A
Form of Subscription Agreement	Exhibit B

iv

SUITABILITY STANDARDS

In General

An investment in the Partnership involves risk and is suitable only for persons who have adequate financial means, desire a relatively long-term investment and who will not need immediate liquidity from their investment. Persons who meet this standard and seek to diversify their personal portfolios with an oil and natural gas-based investment, which among its benefits may provide portfolio diversification, may generate cash distributions, may provide certain tax benefits, may provide capital growth, and may hedge against inflation, and are able to hold their investment for a time period consistent with the Partnership’s liquidity plans, are most likely to benefit from an investment in the Partnership. See “Alternative Investments.” On the other hand, an investment in the Partnership is not appropriate for persons who require immediate liquidity or guaranteed income, or who seek a short-term investment. Notwithstanding these investor suitability standards, potential investors should consider all of the information contained in this prospectus, including the “Risk Factors” section contained herein, in determining whether an investment in the Partnership is appropriate.

It is the obligation of our general partner and persons selling the common units to make reasonable efforts to determine that the common units are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth. However, you should invest in the Partnership only if you are willing to assume the risk of a speculative, illiquid, and long-term investment.

The decision to accept or reject your subscription will be made by our general partner, in its sole discretion, and is final. Our general partner will not accept your subscription until it has reviewed your apparent qualifications, and the suitability determination must be maintained by our general partner during our term and for at least six years thereafter.

Restrictions on Sales in Certain States

We are offering common units only in the states where we have been approved to sell common units by the state securities commissions.  If you are a resident of a state where we have not been approved to sell common units, you will not be able to purchase common units. We currently anticipate that we will be approved to sell securities only in the states of New York, New Jersey, Connecticut and Florida.

General Suitability Requirements for Purchasers of Common Units representing Limited Partner Interests

Common units may be sold to you if you meet either of the following requirements:

· You have a net worth, or joint net worth with your spouse, of not less than $150,000, exclusive of home, home furnishings, and automobiles; or

· You have a net worth, or joint net worth with your spouse, of not less than $45,000, exclusive of home, home furnishings, and automobiles, and had during the last tax year gross income, or joint income with a spouse, of at least $45,000, without regard to an investment in the Partnership.

New Jersey Residents

New Jersey investors must have either (a) a minimum liquid net worth of at least $100,000 and a minimum annual gross income of not less than $85,000, or (b) a minimum liquid net worth of $350,000. For these purposes, "liquid net worth" is defined as that portion of net worth (total assets exclusive of home, home furnishings, and automobiles, minus total liabilities) that consists of cash, cash equivalents and readily marketable securities. In addition, a New Jersey investor's investment in us, our affiliates, and other non-publicly traded direct investment programs (including real estate investment trusts, business development companies, oil and gas programs, equipment leasing programs and commodity pools, but excluding unregistered, federally and state exempt private offerings) may not exceed ten percent (10%) of his or her liquid net worth.

Suitability Requirements for IRAs

An individual retirement account, or IRA, can purchase the common units if the IRA owner meets the basic suitability standard.

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Fiduciary Accounts

If there is a sale of common units to a fiduciary account other than an IRA, such as a trust, the basic suitability standards must be met by the beneficiary, the fiduciary account, or the donor or grantor who directly or indirectly supplies the funds to purchase common units if the donor or grantor is the fiduciary.

Generally, you are required to execute your own subscription agreement, and the general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is if you have given someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus.

Additional Considerations for IRAs and Tax-Exempt Organizations

An investment in common units will not, in and of itself, create an IRA. To form an IRA, an investor must comply with all applicable provisions of the Internal Revenue Code of 1986 (the “Code”) and the Employee Retirement Income Security Act of 1974, or ERISA.  IRAs and tax-exempt organizations should consider the following when deciding whether or not to invest:

· for tax-exempt organizations, income or gain realized may constitute unrelated business taxable income, or UBTI;

· for IRAs, ownership of the common units may cause a pro rata share of the Partnership’s assets to be considered plan assets for the purposes of ERISA and the excise taxes imposed by the Code;

· any entity that is exempt from federal income taxation will be unable to take full advantage of any tax benefits generated by the Partnership; and

· charitable remainder trusts that have any UBTI will be subject to an excise tax equal to 100% of such UBTI.

Although common units may represent suitable investments for some IRAs and tax-exempt organizations, common units may not be suitable for your plan or organization due to the particular tax rules that apply to your plan or organization. Furthermore, the investor suitability standards represent minimum requirements, and the fact that your plan or organization satisfies them does not mean that an investment would be suitable. You should consult your plan’s tax and financial advisors to determine whether this investment would be advantageous for your particular situation.

If you are a fiduciary or investment manager of an IRA, or if you are a fiduciary of another tax-exempt organization, you should consider all risks and investment concerns, including those related to tax considerations, in deciding whether this investment is appropriate and economically advantageous for your plan or organization. See “Risk Factors,” “Material Federal Income Tax Consequences” and “Investment by IRAs.”

Qualified Plans

We are not soliciting, and will not accept, subscriptions from pension, profit sharing or stock bonus plans, including Keogh Plans.

Restrictions Imposed by the USA PATRIOT Act and Related Acts

In accordance with the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, as amended, or the USA PATRIOT Act, the common units offered hereby may not be offered, sold, transferred or delivered, directly or indirectly, to any “Prohibited Shareholder,” which means anyone who is:

· a “specially designated national,” “specially designated global terrorist,” “foreign terrorist organization,” or “blocked person” within the definitions set forth in the Foreign Assets Control Regulations of the U.S. Treasury Department;

· acting on behalf of, or an entity owned or controlled by, any government against whom the U.S. maintains economic sanctions or embargoes under the Regulations of the U.S. Treasury Department;

· within the scope of Executive Order 13224 — Blocking Property and Prohibiting Transactions with Persons who Commit, Threaten to Commit, or Support Terrorism, effective September 24, 2001;

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· subject to additional restrictions imposed by the following statutes or regulations, and executive orders issued thereunder: the Trading with the Enemy Act, the Iraq Sanctions Act, the National Emergencies Act, the Antiterrorism and Effective Death Penalty Act of 1998, the International Emergency Economic Powers Act, the United National Participation Act, the International Security and Development Corporation Act, the Nuclear Proliferation Prevent Act of 1994, the Foreign Narcotics Kingpin Designation Act, the Iran and Libya Sanctions Act of 1998, the Cuban Democracy Act, the Cuban Liberty and Democratic Solidarity Act and the Foreign Operations, Export Financing and Related Programs Appropriation Act or any other law of similar import as to any non-U.S. country, as each such act or law has been or may be amended, adjusted, modified or revised from time to time; or

· designated or blocked, associated or involved in terrorism, or subject to restrictions under laws, regulations, or executive orders as may apply in the future similar to those set forth above.

FORWARD LOOKING STATEMENTS

Certain statements within this prospectus, including the sections entitled “Prospectus Summary,” “Risk Factors,” “Investment Objectives” and “Proposed Activities,” may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as “may,” “will,” “could,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “predict,” “continue,” “further,” “seek,” “plan” or “project” and variations of these words or comparable words or phrases of similar meaning.

These forward-looking statements include such things as:

· investment objectives and our ability to make investments in a timely manner on acceptable terms;

· references to future success in the Partnership’s property acquisition, drilling and marketing activities;

· our use of proceeds of the offering and our business strategy;

· estimated future capital expenditures;

· sales of the Partnership’s properties and other liquidity events;

· competitive strengths and goals; and

· other similar matters.

These forward-looking statements reflect our current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside our control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” and the following:

· that our strategy of acquiring oil and gas properties on attractive terms and developing those properties may not be successful or that our operations on such properties may not be successful;

· general economic, market, or business conditions;

· changes in laws or regulations;

· the risk that the wells in which we acquire an interest are productive, but do not produce enough revenue to return the investment made;

· the risk that the wells we drill do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected;

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

· uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and

· the risk that any hedging policy we employ to reduce the effects of changes in the prices of our production will not be effective.

Although we believe the expectations reflected in such forward-looking statements are based upon reasonable assumptions, we cannot assure investors that our expectations will be attained or that any deviations will not be material. Investors are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, we undertake no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.

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PROSPECTUS SUMMARY

The following is a summary of the important, material information about this offering. It may not contain all of the detailed information that is important to you. Accordingly, we urge you to read this summary together with the information contained in this prospectus, including the information under the caption “Risk Factors” on page 17.

We include definitions of terms used to describe oil and gas properties and operations under the caption “Glossary of Oil and Gas Terms” on page 115.  References to “we,” “us,” “our,” or the “Partnership” refer to Energy 11, L.P. and our subsidiaries.

Our Proposed Business

We are a Delaware limited partnership recently formed to acquire and develop oil and gas properties located onshore in the United States.  We 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.  On December 18, 2015, we acquired an 11% working interest in approximately 215 existing producing wells and approximately 262 future development locations in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). We have not identified any additional oil and gas properties that we will acquire and we do not know whether we will be able to acquire any additional assets.

Our Investment Objectives

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

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

· to make distributions to our partners;

· after five to seven years following the termination of this offering, to engage in a liquidity transaction in which we will sell our properties and distribute the net sales proceeds to our partners, merge with another entity or list our common units on a national securities exchange; and

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

We are the first oil and gas partnership formed by our general partner and its affiliates.  There can be no assurances that we will be able to attain our investment objectives.

The Properties We Intend to Acquire and Develop

We intend to target for acquisition working and other interests in producing and non-producing oil and gas properties that we expect will require additional drilling and other exploitation activities to fully develop their potential. Our partnership is a “blind pool” which means that we had not identified any properties for acquisition prior to commencing the offering. Also, our Partnership Agreement does not require that we invest in producing or non-producing properties in a particular ratio, or spend a certain percentage of our available capital to acquire producing or non-producing properties.  As a result, substantially all of the properties we acquire may be producing properties or properties that require additional operations to develop reserves, or any combination of producing and non-producing properties.  Factors that will affect our decision to acquire producing properties or non-producing properties include the current and anticipated future economic conditions at the time we have funds available for acquisition, our evaluation of the desirability of properties available for acquisition at the time we have funds available, the amount of funds available for acquisition and the Partnership’s ability to diversify its portfolio, and the availability and cost of drilling rigs and other equipment necessary to develop non-producing properties.

When we acquire a property, we will estimate the capital required to develop the property, and plan to use a portion of our capital contributions or borrowings available to us to fund the costs of development.  We also plan to use a portion of our cash flow to develop our properties. In addition, we may acquire gathering systems, pipelines, treatment facilities, processing plants and other infrastructure, not associated with our producing properties and assets used in the upstream energy business, so long as the amount of such investments, in the aggregate, does not exceed 20% of the purchase price of common units we issue.

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We do not expect to conduct a material amount of exploration activities on properties that are not located in or adjacent to producing properties.

Our general partner will have the ability to acquire properties and conduct operations that vary from the parameters described in this prospectus.  Our Partnership Agreement provides that our general partner will not be liable to us or our partners if a decision to vary the investments or operations from those described in this prospectus is made in good faith.

Oil and Gas Properties Acquired

On September 15, 2015, we through a wholly owned subsidiary, entered into an Interest Purchase Agreement (“Purchase Agreement”) by and among Kaiser-Whiting, LLC and the owners of all the limited liability company interests therein (the “Sellers”), for the purchase of the Sanish Field Assets. The Partnership closed on the purchase of the Sanish Field Assets on December 18, 2015.

Pursuant to the Purchase Agreement as amended by the First Amendment thereto, the purchase price for the Sanish Field Assets consisted of (i) $60 million in cash, subject to customary adjustments, (ii) an aggregate of $2 million, payable in equal amounts on December 31, 2016 and December 31, 2017, (iii) a promissory note in the amount of $97.5 million payable to Sellers (the “Seller Note”) and (iv) a contingent payment of up to $95 million. The contingent payment will provide for a sharing between us and the Sellers to the extent the NYMEX current five-year strip oil price for WTI at December 31, 2017 is above $56.61 (with a maximum of $89.00) per Bbl. The contingent payment will be calculated as follows: if on December 31, 2017 the average of the monthly NYMEX:CL strip prices for future contracts during the delivery period beginning December 31, 2017 and ending December 31, 2022 (the “Measurement Date Average Price”) is greater than $56.61, then the Sellers will be entitled to a contingent payment equal to (a) (i) the lesser of (A) the Measurement Date Average Price and (B) $89.00, minus (ii) $56.61, multiplied by (b) 586,601 Bbls per year for each of the five years from 2018 through 2022 represented by the contracts for the entire acquisition. The contingent consideration is capped at $95 million and is to be paid on January 1, 2018.  In addition, the First Amendment provides that so long as we not in default under the Seller Note, in lieu of our obligation to pay the contingent payment, we have the one-time right (exercisable between June 15, 2016 through June 30, 2016) to elect to pay Sellers $5 million in full satisfaction of the contingent payment by paying to Sellers $5 million at the time of election or by increasing the amount of the Seller Note by $5 million.

Whiting Petroleum Corporation (“Whiting”), a publicly traded oil and gas company, is the operator of our properties on behalf of us and the other working interest owners in those properties.

Our General Partner

Our general partner is Energy 11 GP, LLC.  Our general partner was recently formed and has limited operating history.  Our general partner was formed and is owned by companies controlled by Glade M. Knight, David McKenney, Anthony “Chip” F. Keating III, and Michael J. Mallick.  See “Management.”

Our executive offices are located at 120 W 3rd Street, Suite 220, Fort Worth, Texas, our telephone number is (817) 882-9192 and our website is www.energyeleven.com.  Information on our website is not part of this prospectus.

Our general partner will not receive a management or similar fee for acting as general partner and will not receive an offering and organization fee for organizing the Partnership.  We reimbursed our general partner for all third party costs incurred and paid by the general partner in connection with the formation of the Partnership, including third-party legal, accounting, printing, filing fees, travel and similar third party costs and expenses.  In addition, the Partnership will reimburse the general partner and its affiliates for all general and administrative expenses incurred by the general partner and its affiliates in managing the Partnership’s business.  These costs and expenses will include the direct and indirect costs and expenses of employee compensation, rental, office supplies, travel and entertainment, printing, legal, accounting, advertising, marketing and overhead.  The general partner estimates that the amount of this reimbursement will not exceed $4.0 million per year if the maximum subscription is achieved during the first year following the initial closing date of the offering.  If affiliates of the general partner organize additional partnerships in the future, or engage in other business activities, the general partner will allocate these costs to the Partnership and any other partnership or business activities based on the relative amount of time spent, or in another manner deemed reasonable by the general partner.  The beneficial owners of the general partner will not be employees of the general partner, and will not receive salary or other compensation from the general partner or Partnership other than reimbursement of third party costs and expenses and with respect to their equity interests in the Partnership.

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Management Agreement

At the initial closing of the sale of our common units, we and our wholly owned subsidiary Energy 11 Operating Company, LLC entered into the Management Services Agreement (the “Management Agreement”) with E11 Management, LLC, (the “Former Manager”), and E11 Incentive Holdings, LLC, an affiliate of the Former Manager (“Incentive Holdings”) whereby the Former Manager agreed to provide management and operating services regarding substantially all aspects of our business. The Former Manager was formed on April 7, 2014 by Aubrey K. McClendon and he served as its Chief Executive Officer.

The services that the Former Manager agreed to provide to us pursuant to the Management Agreement include, but are not limited to:

· identifying and evaluating oil and natural gas properties for acquisition, development, integration, sale or monetization;

· conducting (or overseeing one of its affiliated companies or third-parties to conduct) drilling, completion, production, marketing and hedging operations as the operator of our oil and natural gas properties;

· overseeing the drilling, completion, production, marketing and hedging operations of our oil and natural gas properties operated by other persons or entities;

· identifying and evaluating financing alternatives for acquisitions of producing oil and natural gas properties; and

· managing the financial, accounting and other back office support functions associated with the drilling, completion, production, marketing and hedging of our oil and natural gas properties.

Pursuant to the Management Agreement, we agreed to pay the Former Manager a monthly fee. Upon entering into the Management Agreement, we issued 100,000 class B units to Incentive Holdings. The class B units entitle the holder to receive a portion of distributions made after Payout.

The Management Agreement was terminable by us if, among other reasons, Mr. McClendon, the Former Manager’s key employee, ceased to be employed by the Former Manager and we did not approve of a proposed replacement of such key employee. On March 2, 2016, Aubrey McClendon was killed in a car accident. Following Mr. McClendon’s death and subsequent correspondence between the Former Manager and us, on April 5, 2016, we elected not to approve a replacement key employee for Mr. McClendon and exercised our right to terminate the Management Agreement.  Accordingly the fees under the Management Agreement will no longer accrue as of the effective date of termination. Also, upon termination of the Management Services Agreement and in accordance with the terms therewith, 37.5% of the class B Units owned by Incentive Holdings have been cancelled.

Substantially all of our properties are currently being operated by Whiting. Since we own a 100% non-operating interest in our assets, most of the services that the Former Manager had been contracted to perform are being performed by Whiting, as operator of those properties. Through April 28, 2016, we have raised approximately $105 million in net proceeds of this offering. On December 18, 2015 we acquired the Sanish Field Assets for a purchase price of approximately $160 million. In addition, we anticipate that we will be obligated to invest an additional $75 million in drilling capital expenditures through 2020 to retain our working interests in the Sanish Field Assets.

To the extent that the proceeds of the offering are sufficient for us to pay off the Seller Note related to the Sanish Field Assets and maintain our interest in the Sanish Field Assets, it is likely that we will only invest in non-operated properties, since those are the opportunities that appear to be currently available to us. Clifford J. Merritt, our President, has extensive experience in locating oil and gas properties for investment and we will be relying on his experience in acquiring any additional properties.

In light of the foregoing, it is likely that all of the proceeds of this offering will be invested in non-operating interests where the operator will provide substantially all of the services to us pursuant to the terms of the applicable joint operating agreements that would have been provided by the Former Manager pursuant to the Management Agreement. Consequently, we do not anticipate that the termination of the Management Agreement will have an adverse effect on us. We have not yet determined whether we will enter into any similar agreements to provide any or all of the services that the Former Manager had agreed to provide.

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Risk Factors

This offering involves numerous risks, including risks related to the Partnership’s ability to identify and acquire on acceptable terms oil and gas properties, operating and environmental risks related to an investment in oil and gas properties and tax risks. You should carefully consider a number of significant risk factors inherent in and affecting the business of the Partnership and this offering, set forth under “Risk Factors,” including the following:

· Our Partnership has limited prior operating history and this is the first oil and gas program sponsored by our general partner and its affiliates and there can be no assurance that we will be able to attain our investment objectives;

· Our chief executive officer and chief financial officer have no prior experience in the oil and gas industry;

· Because we have not identified all properties for acquisition at this time, this is in part a “blind pool” offering.  This means that investors may not have an opportunity to evaluate properties we may acquire prior to subscribing;

· An investment in the common units is not a liquid investment;

· A portion of our cash distributions are expected to be made out of the capital contributions we receive from purchasers of common units;

· We cannot guarantee any investment return or the amount or frequency of any distributions we may make or that our distributions will be sufficient to pay your tax liability attributable to your ownership of common units;

· Our general partner will be subject to conflicts of interest;

· Our Partnership Agreement limits the fiduciary duty that our general partner owes;

· Holders of common units have limited voting rights and will not be able to remove our general partner if they are dissatisfied with the manner in which our general partner manages our business;

· We will be subject to the operating and other risks of owning and developing oil and gas properties, including environmental and operational risks, risks of reductions in the prices of oil, natural gas and other hydrocarbons we produce, risks associated with hedging our production, and regulatory risks;

· We will be subject to risks associated with our status as an emerging growth company; and

· We will be subject to tax risks.

 Please carefully read the information under the caption “Risk Factors,” starting on page 17.

Financing

As part of the financing for the purchase of the Sanish Field Assets, on December 18, 2015, the Partnership executed the Seller Note favor of the Sellers in the original principal amount of $97.5 million. The Seller Note bears interest at 5% per annum and is payable in full no later than September 30, 2016 (“Maturity Date”).  Subject to the Partnership’s compliance with the conditions set forth in the Seller Note, the Partnership has the right to extend the Maturity Date to March 31, 2017.  The Partnership’s right to extend the Maturity Date is subject to the satisfaction of the following conditions: (i) the Partnership must deliver to Seller written notice of the election to extend the Maturity Date no later than September 1, 2016, (ii) the Partnership must pay to Seller an extension fee equal to 0.5% of the outstanding principal balance outstanding at September 30, 2016, (iii) during the extension period and until the Seller Note is paid in full, the interest rate on the outstanding principal of the Seller Note shall bear interest at the fixed rate of 7.0% per annum, (iv) the outstanding principal amount of the Seller Note as of September 1, 2016 may not be in excess of $60 million, and (v) both at the time of the delivery of the extension notice and as of September 30, 2016, no event of default shall exist under the Seller Note or any collateral document. There is no penalty for prepayment of the Seller Note. Payment of the Seller Note is secured by a mortgage and liens on all of the Sanish Field Assets in customary form. If the Partnership has not fully repaid all amounts outstanding under the Seller Note on or before June 30, 2016, the Partnership must also pay a deferred origination fee in an amount equal to $250,000.

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Interest is due monthly on the last day of each month while the Seller Note remains outstanding. In addition to interest payments on the outstanding principal balance of the Seller Note, the Partnership must make mandatory principal payments monthly in an amount equal to 75% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the Seller Note is reduced to $60 million and 50% of the net proceeds the Partnership receives from the sale of its equity securities thereafter, until the Seller Note is paid in full. In addition, if the Partnership sells any of the property that is collateral for the Seller Note, the Partnership must make a mandatory principal payment equal to 100% of the net proceeds of such sale until the principal amount of the Seller Note is paid in full.

As of December 31, 2015, the outstanding balance on the Seller Note was $85.0 million.

Borrowing Policy

Prior to the maturity date of the Seller Note, we expect to enter into a credit facility with a commercial lender.  We plan to use borrowings under the credit facility to finance a portion of the Seller Note or for subsequent development of our properties.  We may also use borrowings under our credit facility to pay distributions.  We expect that the credit facility will provide for borrowings up to a borrowing base that will be set by the lenders under the facility, at their discretion, based in part upon the lenders’ valuation of our reserves.  We also expect that our credit facility will be secured by a mortgage on our properties.  We do not expect the borrowings under our credit facility to exceed 50% of our total capitalization determined on an annual basis. However, the general partner is not limited in the amount of borrowings the general partner may cause the Partnership to incur.  See “Risk Factors – The amount of indebtedness that the Partnership may incur is not limited by the terms of the Partnership Agreement.”

We have not received a commitment or a term sheet from a lender with respect to a credit facility, and no assurances can be made that we will be able to arrange for a credit facility.  The financial covenants, interest rate, borrowing base and other terms of the credit facility, if any, will be negotiated by the general partner and will be affected by general economic conditions, the amount of capital contributions we receive, the reserves and production attributable to the properties we acquire or have agreed to acquire, oil and gas prices and other factors, many of which are beyond our control.  See “Risk Factors – We have not negotiated the terms of our credit facility with lenders.”

Hedging Policy

Prices for oil and natural gas have been volatile and uncertain for many years. To mitigate our exposure to decreases in prices, we plan to enter into financial hedges through contracts such as regulated NYMEX futures and options contracts and over-the-counter swap contracts with qualified counterparties. The percentages of oil and/or natural gas production that we elect to hedge under the hedging policy may change from time to time at the discretion of our general partner, but in no event will we hedge more than the projected amounts of oil, natural gas or natural gas liquids reasonably expected to be produced from our wells.

Distributions

Our investment objective is to sell oil, gas and other hydrocarbons produced from properties that we may acquire, and if we do not merge with another company or list our common units on a national securities exchange, to sell our properties, in order to make cash distributions to holders of our common units, incentive distribution rights and class B units.  Because we are a newly formed entity with limited prior operating history and did not acquire any assets until December 2015, we can make no assurances as to the amount, if any, that a holder of common units may receive as distributions with respect to his or her common units or as to the timing of any distributions.  

Prior to “Payout,” which is defined below, all of the distributions we make, if any, will be paid to the holders of common units.  Accordingly, we will not make any distributions with respect to the incentive distribution rights, which will be owned by our general partner, or with respect to its class B units, which are owned by an affiliate of the Former Manager, and will not make the contingent, incentive payments to the dealer manager under the dealer manager agreement, until Payout occurs.  For a description of the other amounts we will pay the general partner and the dealer manager, please read “Compensation” beginning on page 45.

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Our Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of our common units equals $20.00 plus the Payout Accrual as of such date.  Our Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time.  Our Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit.  If at any time we distribute to holders of common units more than the Payout Accrual, the amount we distribute in excess of the Payout Accrual will reduce the Net Investment Amount.  By way of example, if we have distributed to the holders of the common units an amount equal to the Payout Accrual and then distribute an additional $2.00 per common unit, the Net Investment Amount will be reduced to $18.00 per common unit and the Payout Accrual will be 7% per annum simple interest on $18.00.  At the point in time that we distribute $20.00 per common unit in excess of the Payout Accrual, the Net Investment Amount will be $0.00 per common unit and Payout will have occurred.

Our partnership agreement does not require us to make distributions to the holders of our common units.  Because we have limited prior operating history and have only identified one group of oil and gas properties that we will acquire, and can provide no assurances of our ability to make distributions, the 7% per annum Payout Accrual and the Net Investment Amount are not intended to reflect the amount we expect to distribute to holders of common units from our anticipated operations.  Rather, Payout reflects our agreement that the general partner and the affiliate of the Former Manager will not receive any distributions from the incentive distribution rights or class B Units, and the dealer manager will not receive its contingent, incentive fee under the dealer manager agreement, until the holders of common units have received distributions sufficient to cause Payout to occur.

All distribution made prior to Payout will be made as follows:

· 100% to the holders of common units.

All distributions made after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of our assets, will be made as follows (assuming the cancellation and no reissuance of 37,500 of the class B units issued to an affiliate of the Former Manager):

· First, 35% to the holders of the incentive distribution rights, 21.875% to the holders of the class B units, 13.125% to the holders of the common units, and 30% to the dealer manager under the dealer manager agreement as its contingent, incentive fee until the dealer manager receives fees equal to 4% of the gross proceeds of the offering of common units; and then

· Thereafter, 35% to the holders of the incentive distribution rights, 21.875% to the holders of the class B units and 43.125% to the holders of common units.

Because we expect to have multiple closings of sales of common units, the Payout Accrual for common units sold earlier in the offering may have a larger Payout Accrual than common units sold later in the offering.  Our Partnership Agreement provides that distributions to holders of common units will be paid to holders of common units in proportion to the Payout Accrual for the common units owned, until all of the common units have the same Payout Accrual.

There is no requirement in our Partnership Agreement that distributions represent our net income or the proceeds from the sale of oil and gas from properties that we may acquire.  The general partner may make distributions all or a portion of which represent capital contributions.  If our general partner makes distributions in our early years of operation it is more likely that these distributions will represent capital contributions, rather than cash generated by our operations.  This is because as proceeds are raised in the offering it is not always possible immediately to invest them in oil and gas properties.  There may be a “lag” or delay between the raising of offering proceeds and the sale of oil and gas from properties that we acquire.

Although our general partner does not currently plan to use the proceeds of borrowings to make distributions, the general partner will have the right to distribute the proceeds of borrowings, and the general partner may determine that it is in the best interests of the holders of common units to make distributions from the proceeds of borrowings.

The incentive distribution rights and class B units are non-voting limited partner interests in us that will not participate in our cash distributions until Payout occurs.  Initially, our general partner will own the incentive distribution rights and an affiliate of the Former Manager will own the class B units.  The contingent, incentive fee is a contractual obligation we have agreed to pay to the dealer manager pursuant to the dealer manager agreement.

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In connection with the termination of the Management Agreement, 37,500 of the class B units were forfeited and be cancelled.  Consequently, the distributions that would otherwise have been paid with respect to the cancelled class B units will be distributed to holders of common units.  The general partner may cause us to issue additional class B units to a person who performs services for us in an amount not to exceed the number of class B units cancelled.  

The dealer manager agreement with the dealer manager provides that we will pay a contingent, incentive fee to the dealer manager each time we make a distribution to holders of our incentive distribution rights and class B Units after Payout occurs. The dealer manager’s contingent, incentive fee is equal to 30% of the available cash distributed when payments are made to holders of our incentive distribution rights and class B Units after Payout occurs. The contingent, incentive fee will be deemed paid in full when the amount paid to the dealer manager as the incentive, compensation fee plus the amount of account maintenance fees paid to the dealer manager aggregates 4% of the gross proceeds of the offering of common units.

Our ability to make distributions will be dependent on the success of our business, which is subject to numerous risks, and no assurances can be made as to the amount or timing of any distributions that we will be able to make in the future.  See “Risk Factors.”

Sale of Properties, Merger or Listing of the Common Units

Beginning five to seven years after the termination of this offering, we plan either to sell our properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to our partners, to merge with another, unaffiliated company, or to list the common units on a national securities exchange.  The sale of our properties, a merger and the listing of the common units will each require the consent of our general partner and the holders of a majority of our common units.  Additionally, if it is necessary to amend the Partnership Agreement of the Partnership in connection with a liquidity event, and the amendment is materially adverse to the holders of the incentive distribution rights or class B units, the amendment, and therefore the liquidity event will require the approval of the holders of the incentive distribution rights and the class B units.

 The decision by the general partner to sell our assets, and our ability to sell our assets, will depend on the following, among other factors, many of which will be beyond the control of our general partner:

· The market for oil and gas properties;

· The price of oil, gas and other hydrocarbons which our properties produce;

· General economic conditions; and

· Whether we have finished the planned development of the properties we acquire.

The decisions by the general partner to merge us with another entity, and the ability of the general partner to merge us with another entity, will depend upon a number of factors some of which will be beyond the control of the general partner, including:

· The value of our oil and gas properties;

· Any liabilities that we may be subject to, including contingent liabilities; and

· Conditions prevailing in the merger and acquisition market at the time.

 The decision by the general partner to apply to list the common units, and the ability of the general partner to list the common units, will depend upon a number of factors some of which will be beyond the control of the general partner, including,

· The amount of assets, revenues and earnings that we have at the time of our listing;

· The then existing market for oil and gas master limited partnerships; and

· The listing standards of the various national securities exchanges, and whether we are able to meet those listing standards.

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 No assurances can be made that we will be able to sell our assets or list the units, nor can we provide any assurances as to the amounts we will be able to distribute if we sell assets, the amount of consideration that could be received in a merger or as to the price our common units will trade if we are able to list them.

Summary Tax Consequences

Subject to the discussion under “Material Federal Income Tax Consequences” and the limitations set forth therein, it is the opinion of Haynes and Boone LLP that we will be treated as a partnership for U.S. federal income tax purposes. As a result, we generally will not be liable for U.S. federal income taxes. Instead, each of our unitholders will take into account its share of our income, gains, losses and deductions in computing its U.S. federal income tax liability as if it had earned such income directly, even if we do not make cash distributions to that unitholder. Consequently, a unitholder may be liable for U.S. federal income taxes as a result of ownership of our units even if that unitholder has not received a cash distribution from us. Cash distributions by us to a unitholder generally will not give rise to income or gain to the extent of its tax basis in its units, and cash distributions in excess of such unitholder’s tax basis in its units will, subject to certain limitations, generally be taxed as capital gain. A unitholder will generally recognize capital gain or loss upon disposition of its units, subject to certain limitations. A unitholder that disposes of its units during any point in a taxable year will still be allocated its share of our income, gain, loss, and deductions attributable regardless of whether we have made a distribution during that year.

Please see “Risk Factors – Tax Risks to Common Unitholders” starting on page 36 and “Material Federal Income Tax Consequences.”

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THE OFFERING

Offering	A minimum of 1,315,790 common units of limited partner interest and a maximum of up to 100,263,158 common units.
Offering period	Began on January 22, 2015 and is expected to end on January 23, 2017.  We may extend the offering period until April 24, 2017, pursuant to a supplement to this prospectus (we refer to January 23, 2017, or, if the offering is extended, the date of such extension, as the “final termination date”). Our general partner may terminate the offering period at any time prior to the final termination date.
Offering price	Common units are being offered at $20.00 per common unit until a maximum of 100,263,158 common units are sold. A minimum subscription in the Partnership is $5,000. See “Plan of Distribution.” We initially offered common units at $19.00 per common unit until 5,263,158 common units were sold.
Minimum Offering	As of August 19, 2015, we completed our minimum offering of 1,315,790 common units at $19.00 per common unit. As of April 28, 2016, we had completed the sale of a total of 5,863,622 common units for total gross proceeds of $112.0 million and proceeds net of selling commissions and marketing expenses of $105.3 million.  As of April 28, 2016 the common units were held by approximately 1,800 unitholders. Investors should make their checks payable to “David Lerner Associates, Inc.” and David Lerner Associates, Inc. will transmit funds to us at the next monthly closing date.  We plan to have monthly closings, as necessary, until the earlier of the issuance of 100,263,158 common units and the final termination date.
Commissions and marketing fees	David Lerner Associates, Inc., the dealer manager for the offering, will be paid selling commissions of 5% of the gross proceeds of the offering and a marketing fee of 1% of the gross proceeds of the offering. The marketing fee is intended to compensate David Lerner Associates for advertisement for seminars related to the offering, the costs of the seminars including room rental, food, security, printing and mailing, attendance at trade shows, and compensation to non-sales personnel for promotional activities. Prior to the final termination date, we will also pay the dealer manager an account maintenance services fee of $5.00 per customer account that holds our common units and $10.00 per year for each such customer account still active, up to a maximum of $500,000. The dealer manager will also be entitled to receive the contingent, incentive fee described under “—Compensation of our general partner, its affiliates and certain non-affiliates.” The total amount of the account maintenance fee plus the contingent, incentive fee will not exceed 4% of the gross proceeds of the offering.
General partner contribution	The general partner will make only a nominal capital contribution to our Partnership.
Purchase of common units by affiliates of our general partner	The four members of our general partner each acquired 5,000 Common Units in March 2016 for $20.00 per Common Unit upon the Partnership selling 5,263,158 Common Units.
Estimated use of proceeds	The offering proceeds will be used to pay the following:
	•  the costs to acquire oil and gas properties;
	•  the costs to develop, operate and manage our oil and gas properties;
	•  the offering and organization costs, which include sales commissions, the marketing fee and all third party costs such as legal, accounting, printing, travel and similar amounts related to the organization of the partnership and the offering of the limited partner interests;
	•  any portion of the general and administrative cost reimbursement that is not paid with Partnership revenues; and
	•  under the limited circumstances described under “Distributions” to make distributions to the holders of common units. See “Source of Funds and Estimated Use of Offering Proceeds.”

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No additional assessments	You will not be required to make any capital contributions to the Partnership other than payment of the offering price for the units you purchase, except as described under “Summary of Limited Partnership Agreement – Limited Liability.”
Compensation of our general partner, its affiliates and certain non-affiliates	Our general partner, its affiliates and certain non-affiliates will receive fees and compensation from the offering of the common units. The non-affiliates will include the dealer manager, selected dealers, and operators of our oil and gas properties. These fees and compensation will include the following:
	•  In connection with the initial closing, our general partner received the incentive distribution rights which are non-voting limited partner interests that entitle the holder of such rights to 35% of all amounts distributed by us after Payout occurs. •  The general partner will also be entitled to receive reimbursement for offering and organization costs paid to third parties, including legal, accounting, engineering, printing and filing fees. The amount of offering and organization costs paid by the Partnership or reimbursed to the general partner is estimated to be $8.0 million if the maximum offering is achieved.
	•  The Partnership will also reimburse the general partner and the general partner’s affiliates for their general and administrative costs allocable to the Partnership.  Initially, the only business of the general partner will be to act as general partner of the Partnership, and all of the general partner’s general and administrative costs will be paid by the Partnership.  If affiliates of the general partner form other partnerships or engage in other oil and gas activities, the general partner will allocate its general and administrative costs to the Partnership and other partnerships or businesses in a manner deemed reasonable by the general partner.  The general partner estimates that the amount of reimbursable general and administrative expenses for the first year following the initial closing will be $4.0 million if the maximum offering is achieved. •  The Partnership will pay to David Lerner Associates, Inc. a dealer manager fee equal to 5% of the gross offering proceeds and a marketing fee equal to 1% of the gross proceeds of the offering. We will also pay David Lerner Associates, Inc. the contingent, incentive fee which will be based on the amount of distributions made by the Partnership after Payout.  The contingent, incentive fee will be payable to David Lerner Associates, Inc., will be payable solely in cash, and will not exceed 4% of the gross proceeds from the sale of common units or $80.0 million if the maximum subscription is achieved.  If the Partnership engages in a liquidity event, the dealer manager agreement provides that the contingent, incentive fee is payable to the dealer manager after Payout.  If the liquidity event is a sale of assets and distribution of the sales proceeds to the partners, the contingent, incentive fee will be paid as described under “Capital Contributions and Distributions — Distributions” and the dealer manager would receive its 30% share of the distribution, up to the 4% cap. If the liquidity event is a merger or similar transaction in which the incentive distribution rights and class B Units are converted into or exchanged for securities or other property, the dealer manager agreement provides that an amount equal to 42.857% of the sum of the consideration paid to the holders of incentive distribution rights and class B Units will be segregated by the partnership, converted by the partnership to cash as soon as reasonably practicable and the cash proceeds paid to the dealer manager, up to the 4% cap (which would result in the dealer manager receiving 30% of the sum of the amounts paid to the holders of the incentive distribution rights, and class B Units plus the contingent incentive fee).  Prior to the final termination date of the offering, we will pay David Lerner Associates, Inc. an account maintenance services fee of $5.00 per new customer account and $10.00 per year for each active customer account which holds our common units, as a fee for David Lerner Associates, Inc. maintaining information about the account and its owner(s), up to a maximum of $500,000.  Any fees for account maintenance services paid to David Lerner Associates will reduce the maximum amount of the contingent, incentive fee. •  Pursuant to the Partnership Agreement, concurrently with the initial closing, we issued to Incentive Holdings, an affiliate of the Manager, 100,000 class B units that will entitle Incentive Holdings to participate in Partnership distributions after Payout. In connection with the termination of the Management Agreement, 37,500 of these class B units were forfeited and cancelled.
	See “Compensation” for more information about the fees the partnership will pay the general partner, its affiliates and certain non-affiliates.

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Conflicts of interest	Our general partner and its affiliates will be subject to conflicts of interest in offering the common units and in managing our business. These conflicts may include:
	•  the lack of arm’s-length negotiations in determining the substantial compensation our general partner and its affiliates will receive for the formation and management of our business;
	•  competition with other oil and gas partnerships that may be formed by our general partner and its affiliates in the future, including competition for properties to be acquired;
	•  competition for the general partner’s time and attention with other partnerships that the general partner and its affiliates may sponsor and/or manage; •  the incentive distribution rights may cause the general partner to acquire properties or conduct operations that are more risky to the Partnership than other business opportunities that are available to the Partnership.
Partnership Agreement	The relationship between our general partner and limited partners is governed by our Partnership Agreement, a copy of which is attached to this prospectus as Exhibit A. You should be particularly aware that under the Partnership Agreement:
	•  investors will have limited voting rights;
	•  the right of limited partners to inspect books and records is limited; and
	•  the fiduciary duty of our general partner has been modified to provide that the general partner will have no liability to the Partnership or the limited partners unless the general partner does not act in good faith.
Subscriptions	Investors must properly complete and execute a subscription agreement, a copy of which is attached to this prospectus as Exhibit B, in order to purchase common units. By signing the subscription agreement, you will be making the representations and warranties contained in the subscription agreement and will be bound by all of the terms and conditions set forth in the subscription agreement and our Partnership Agreement. Only investors who are residents of one of the following states may purchase common units: New York, New Jersey, Connecticut and Florida.
Federal Income Tax Consequences	This prospectus contains a discussion of the material federal income tax consequences pertinent to investors, including whether the Partnership will be taxed as a partnership or as a corporation. Our general partner has obtained an opinion from its counsel concerning the Partnership’s classification for federal income tax purposes as a partnership. See “Material Federal Income Tax Consequences” for more information.
Plan of distribution	The initial closing of the offering of common units was held on August 19, 2015, and at that time, subscribers for common units were admitted as our limited partners. We intend to hold monthly closings, as necessary, until the offering is terminated.
No market for common units	There is no established market for the common units, and none is expected to develop in the future. Investors in the common units may not be able to sell their common units and should be prepared to hold such common units indefinitely.
Listing of the common units	The common units have not been approved for quotation or trading on a national securities exchange. However, the general partner may seek to list the common units on a national securities exchange in the future. In order to be approved for listing, the common units and the Partnership will be required to meet the listing standards of a national securities exchange. No assurances can be made that the common units will be approved for quotation or trading on a national securities exchange. Listing of the common units will require the approval of the holders of a majority of our outstanding common units. Additionally, if the listing of the common units requires amendments to our Partnership Agreement, and such amendments could be deemed materially adverse to the holders of the incentive distribution rights or class B units, the listing will require the approval of holders of a majority of the incentive distribution rights or class B units, as appropriate.

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 Emerging Growth Company

The Jumpstart Our Business Startups Act of 2012, or the JOBS Act, is intended to reduce the regulatory burden on emerging growth companies. We meet the definition of an emerging growth company and so long as we qualify as an emerging growth company we will, among other things:

· be temporarily exempted from the internal control audit requirements of Section 404(b) of the Sarbanes-Oxley Act;

· be temporarily exempted from various existing and forthcoming executive compensation-related disclosures, for example: “say-on-pay,” “pay-for-performance,” and “CEO pay ratio”;

· be temporarily exempted from any rules that might be adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or supplemental auditor discussion and analysis reporting;

· be temporarily exempted from having to solicit advisory say-on-pay, say-on-frequency and say-on-golden-parachute shareholder votes on executive compensation under Section 14A of the Securities Exchange Act of 1934, as amended;

· be permitted to comply with the SEC’s detailed executive compensation disclosure requirements on the same basis as a smaller reporting company; and

· be permitted to adopt any new or revised accounting standards using the same timeframe as private companies (if the standard applies to private companies).

Our Partnership will continue to be an emerging growth company until the earliest of:

· the last day of the fiscal year during which we have annual total gross revenues of $1 billion or more;

· the last day of the fiscal year following the fifth anniversary of the first sale of our common equity securities in an offering registered under the Securities Act;

· the date on which we issue more than $1 billion in non-convertible debt securities during a previous three-year period; or

· the date on which we become a large accelerated filer, which generally is a company with a public float of at least $700 million.

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Ownership Chart

The following table shows the ownership of the general partner and the Partnership:

 
 

1.   Each of GKOG, LLC, DMOG ,LLC, CFK Energy, LLC and Pope Energy Investors, LP owns a 25% membership interest in Energy 11 GP, LLC.  Energy 11 GP, LLC owns nominal general partner interest and the incentive distribution rights in Energy 11, L.P.  Each of the owners of the general partner will be reimbursed by the Partnership for the third party out of pocket expenses incurred by the owner in connection with the formation of the Partnership and offering of common units.  See “Compensation.”

2.   Each of Messrs. Knight, McKenney, Keating and Mallick have purchased 5,000 common units for $20.00 per unit.

3.   The Former Manager was indirectly owned by Aubrey McClendon.

4.   E11 Holdings, LLC, which is owned by the Former Manager, received class B Units which will entitle E11 Holdings to distributions after Payout occurs.

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RISK FACTORS

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

Risks Related to an Investment in the Partnership

Neither our chief executive officer nor our chief financial officer has any prior experience in investing in oil and gas properties.

The experience of our chief executive officer and our chief financial officer is primarily in the real estate industry. This is the first oil and gas program in which our chief executive officer and our chief financial officer have participated. The Partnership was originally formed with the intention of relying on the services of the Former Manager for primary oil and gas expertise and in identifying the location of suitable properties for acquisition. Since the Management Agreement has been terminated, the Partnership will no longer be able to rely upon the experienced personnel of the Former Manager. You should consider an investment in the Partnership in light of the risks, uncertainties and difficulties frequently encountered by management operating in a new industry.

The Partnership has limited prior operating history, limited established financing sources and this is the first oil and gas program sponsored by the general partner and its affiliates.

The Partnership, which was formed in 2013, has limited operating history, and accordingly, has limited direct costs and administrative costs associated with prior operations.  In addition, since its formation, the Partnership has not owned or operated any operating assets other than the Sanish Field Assets acquired on December 18, 2015.  This is the first oil and gas program sponsored by the general partner and its affiliates. You should consider an investment in the Partnership in light of the risks, uncertainties and difficulties frequently encountered by companies that are, like the Partnership, in their early stage of development. The Partnership cannot guarantee that it will succeed in achieving its goals, and its failure to do so could cause you to lose all or a portion of your investment.

Because we have not yet identified or selected all properties that we may acquire, this is a “blind pool” offering.  This means you may not be able to evaluate all of the Partnership’s properties before making your investment decision.

On December 18, 2015, the Partnership acquired the Sanish Field Assets. We have not selected any other properties for acquisition by the Partnership and may not select additional properties for acquisition until after you invest in the Partnership. You may not have an opportunity before purchasing units to evaluate geophysical, geological, economic or other pertinent information regarding any additional prospects to be selected. If we select additional properties for acquisition by the Partnership during the offering period, we will file a prospectus supplement describing the properties and their proposed acquisition. If you subscribe for units prior to any such supplement you will not be permitted to withdraw your subscription as a result of the selection of any property.

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

If you invest in the Partnership, then you must assume the risks of an illiquid investment. The common units generally will not be liquid because there is not a readily available market for the sale of common units, and one is not expected to develop.  Further, although our Partnership Agreement contains provisions designed to permit the listing of common units on a national securities exchange, the Partnership does not currently intend to list the common units on any exchange or in the over-the-counter market.  See “Transferability of Interests.”

Our distributions to our common unitholders may not be sourced from our cash generated from operations but from offering proceeds or indebtedness, and therefore our distributions during certain periods may exceed earnings and cash flows from operations, and this will decrease our distributions in the future; furthermore, we cannot guarantee that investors will receive any specific return on their investment.

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Our general partner has the right to make distributions from the proceeds of borrowings and capital contributions. It is likely that all or a part of distributions to common unitholders during the early years of our operations will represent the proceeds of capital contributions, rather than cash generated in our operations. This is because as proceeds are raised in the offering, it is not always possible immediately to invest them in oil and gas properties that generate our desired return on investment. There may be a “lag” or delay between the raising of offering proceeds and their investment in oil and gas properties. Investors who acquire common units relatively early in our offering, as compared with later investors, may receive a greater return of offering proceeds as part of the earlier distributions. Offering proceeds that are returned to investors as part of distributions to them will not be available for investments in oil and gas properties. In addition, during certain periods, we expect that distributions may exceed the amount of earnings and cash flows from operations during such periods.  The payment of distributions will decrease the cash available to invest in oil and gas properties and will reduce the amount of distributions we may make in the future. We cannot and do not guarantee that investors will receive any specific return on their investment. Further, there is no limitation on the amount of distributions that can be funded from offering proceeds or financing proceeds. Because cash generated from our operations will be comingled and is fungible with cash received from capital contributions and indebtedness, we are unable to determine a point in time when distributions will no longer be sourced from capital contributions and proceeds of borrowings.  

Moreover, as a result of the Seller Note indebtedness we incurred in connection with the Sanish Field Assets acquisition, we will use a portion of our cash flow to pay interest on and principal of this indebtedness when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.

If the general partner elects to cause us to make distributions rather than reinvesting the cash flow in our business, we may be required to sell or farm-out properties or to elect not to participate in exploration or development drilling activities on our properties, which activities could turn out to be profitable.

If the Partnership were presented with an exploration or development drilling or other opportunity on its properties, and funding the opportunity would require the Partnership’s cash that is required in order to follow its distribution policy or for other purposes approved by our general partner, our general partner may elect to cause the Partnership to sell or farm-out the opportunity or decline to participate in the opportunity, even if the general partner determines that the opportunity could have a favorable rate of return.  Our general partner will have the right to cause the Partnership to participate in opportunities that will use the Partnership’s cash otherwise than in accordance with the distribution policy if the general partner determines that pursuing such opportunity is in the best interests of the Partnership.

Our general partner will be subject to conflicts of interest in operating our business, including conflicts of interest arising out of the general partner’s ownership of the incentive distribution rights.  Our Partnership Agreement limits the general partner’s fiduciary duties to us in connection with these conflicts of interest.

The general partner will be subject to conflicts of interest in operating our business.  These conflicts include:

· Conflicts caused by the incentive distribution rights held by the general partner, which may cause it to acquire properties or conduct operations that are more risky to the Partnership, or to sell properties, in order to generate distributions from the incentive distribution rights;

· Conflicts caused by the sale of properties to programs that may be formed by the general partner and its affiliates in the future; and

· Conflicts caused by competition for management time and attention with other oil and gas partnerships and with other business activities in which management of our general partner may be involved.

Our Partnership Agreement provides that our general partner will have no liability to the Partnership or the holders of the common units for decisions made, if such decisions are made in good faith.  In addition, our Partnership Agreement provides that if the general partner receives a fairness opinion regarding the sale price of a property or in connection with a merger or the listing of our units on a national securities exchange, including transactions that involve affiliates of the general partner, the general partner will be deemed to have acted in good faith.

The general partner is making only a nominal cash contribution to the Partnership.

In connection with the formation of the Partnership, our general partner made a cash capital contribution to the Partnership of $10 and the initial limited partner contributed $990.  Upon the admission of investors pursuant to this offering, the Partnership refunded the $990 capital contribution of the initial limited partner, after which it withdrew as the initial limited partner.

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Amounts paid to our general partner regardless of success of the Partnership’s activities will reduce the cash we have available for distribution.

The general partner and its affiliates will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and will be reimbursed for general and administrative costs of the general partner allocable to the Partnership as described in “Compensation,” regardless of the Partnership’s success in acquiring, developing and operating properties. The fees and direct costs to be paid to the general partner will reduce the amount of cash distributions to investors. With respect to third-party costs, the general partner has sole discretion on behalf of the Partnership to select the provider of the services or goods and the provider’s compensation as discussed in “Compensation.”

Because our general partner has discretion to determine the amount and timing of any distribution we may make, there is no guaranty that cash distributions will be paid by the Partnership in any amount or frequency even if our operations generate revenues.

The timing and amount of distributions will be determined in the sole discretion of the general partner.  The level of distributions, when made, will primarily be dependent upon the Partnership’s levels of revenue, among other factors. Distributions may be reduced or deferred, in the discretion of the general partner, to the extent that the Partnership’s revenues are used or reserved for any of the following:

· compensation and fees paid to the general partner and its affiliates as described above in “— Compensation and fees paid to the general partner and its affiliates regardless of success of the partnership’s activities will reduce cash distributions;”

· repayment of borrowings;

· cost overruns on drilling, completion or operating activities;

· remedial work to improve a well’s producing capability;

· the acquisition of producing and non-producing oil and gas leasehold interests considered in the best interest of the Partnership by the general partner;

· uninsured losses from operational risks including liability for environmental damages;

· direct costs and general and administrative expenses of the partnership;

· reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

· indemnification of the general partner and its affiliates by the Partnership for losses or liabilities incurred in connection with the Partnership’s activities.

Further, because the Partnership’s investments will be in depleting assets, unless reinvested, Partnership revenues and the amount available for distribution to partners will decline with the passage of time.  Accordingly, there can be no assurance that the Partnership will be able to make regular distributions or that distributions will be made at any consistent rate or frequency. See “Capital Contributions and Distributions — Distributions.”

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

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

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

The Partnership was required to receive minimum offering proceeds of $25,000,000 to break escrow, and the Partnership’s maximum offering proceeds may not exceed $2,000,000,000. The minimum offering was reached on August 19, 2015. There are no other requirements regarding the amount of offering proceeds to be received by the Partnership. Generally, the less offering proceeds received the fewer properties the Partnership would acquire, which would decrease the Partnership’s ability to spread the risks of acquisition and development of the Partnership’s properties.

We have not negotiated the terms of our credit facility with lenders.

Prior to the maturity date of the Seller Note, we expect to enter into a credit facility with a commercial lender.  We plan to use borrowings under the credit facility to finance a portion of the Seller Note or for subsequent development of our properties.  The interest rate, amount available to be borrowed, financial and other covenants, maturity date and other terms of the credit facility will be negotiated by our general partner.  The terms of the credit facility will be affected by numerous factors which we may not be able to control, including general economic conditions, the amount of capital we receive, the reserves and production attributable to the properties we acquire or have agreed to acquire, oil and gas prices and other factors.

We can make no assurances that we will be able to enter into a credit facility or as to the terms of the credit facility.

The amount of indebtedness that the Partnership may incur is not limited by the terms of the Partnership Agreement.

Prior to the maturity date of the Seller Note, we expect to enter into a credit facility with a commercial lender. The general partner intends to limit the amount of borrowing to 50% of the Partnership’s total capitalization on an annual basis.  However, the Partnership Agreement does not place any limitation on the amount of indebtedness that the general partner may cause the Partnership to incur, and holders of common units will have no right to control or influence the amount of indebtedness the Partnership incurs.  High levels of indebtedness may have adverse consequences for the Partnership, including

· Cash that would otherwise be available for distribution or to invest in the Partnership’s business will be used to pay interest on indebtedness;

· Covenants in the indebtedness may restrict the Partnership’s ability to conduct its business, to make acquisitions or develop its assets and to make distributions; and

· Default in the repayment of indebtedness could result in foreclosure on the Partnership’s assets, or require the Partnership to refinance indebtedness at higher costs.

We may have indebtedness under a credit facility following the repayment of the Seller Note.  Restrictions in our credit facility may limit our ability to make distributions to holders of our common units and may limit our ability to capitalize on acquisitions and other business opportunities.

We expect that any credit facility we are able to negotiate will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, make investments or dispositions and engage in transactions with affiliates, as well as covenants requiring us to maintain certain financial ratios and tests.  In addition, the borrowing base under our anticipated facility will be subject to periodic review by our lenders.  Difficulties in the credit markets may cause the banks to be more restrictive when redetermining our borrowing base.

 Your common units may be diluted.

The equity interests of investors in our Partnership may be diluted. The investors in the Partnership will indirectly benefit from the Partnership’s production revenues from all of its wells in proportion to your respective number of common units, based on the original purchase price of common units issued in the offering regardless of:

· when you subscribe;

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· which properties are acquired with your subscription proceeds; or

· the actual subscription price you paid for your common units as described below.

There is a “dilutive” effect to investors who purchase our common units at $20.00 rather than at the initial offering price of $19.00 per common unit.

Investors who purchased our common units at $19.00 received a discounted price compared to investors who purchase after 5,263,158 common units have been sold. Investors who purchase our common units at $20.00 experience “dilution” because the sale of some of our common units at $19.00 results in the average per common unit price being less than $20.00 per common unit. The common units are identical in terms of rights to distributions, including the amount of the distribution, voting and other rights, but the purchasers who acquire common units at $20.00 per common unit are paying a comparative premium over the $19.00 per common unit purchasers.

Our general partner has sole responsibility for conducting our business and managing our operations.  Our general partner and its affiliates will have conflicts of interest, which may permit them to favor their own interests to the detriment of holders of our common units.

Conflicts of interest may arise between our general partner, Energy 11 GP, LLC, and its respective affiliates on the one hand, and us and the holders of our common units, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of holders of our common units.  These conflicts include, among others, the following situations:

· neither our Partnership Agreement nor any other agreement requires affiliates of our general partner to pursue a business strategy that favors us or to refer any business opportunity to us;

· our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash that is distributed to holders of our common units or used to service our debt obligations;

· our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

· our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our Partnership Agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that reduce or eliminate the fiduciary and other duties that our general partner, its board of directors (and any committee thereof) and its officers and the other persons who control it might have otherwise owed to us and the holders of our common units.  In taking any action or making any decision on behalf of the general partner or us, such persons will be presumed to have acted in good faith and, in any proceeding brought by or on behalf of any holder of common units or us, the person bringing such proceeding will have the burden of overcoming such presumption.

Furthermore, under our Partnership Agreement, our general partner, its board of directors (and any committee thereof), its affiliates and the directors, officers and other persons who control our general partner or any of its affiliates will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct, or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.By purchasing a common unit, a common unit holder will become bound by the provisions in our Partnership Agreement, including the provisions discussed above.

Holders of our common units have limited voting rights and are not entitled to elect or remove our general partner or the board of directors of our general partner.

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Unlike the holders of common stock in a corporation, common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.  Common unitholders will not elect our general partner, or the members of its board of directors, and will have no right to remove our general partner, or its board of directors.  The board of directors of our general partner is chosen by the owners of Energy 11 GP, LLC, our general partner.

Your liability may not be limited if a court finds that common unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.  Our Partnership is organized under Delaware law and we plan to conduct business in a number of other states.  The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we may do business.  You could be liable for any and all of our obligations as if you were a general partner if:

· a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

· your right to act with other common unitholders to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitutes “control” of our business.

Common unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them.  Under Section 17–607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.  Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.  Substituted limited partners are liable for the obligations of the assignor to make contributions to a partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the Partnership Agreement.  Liabilities to partners on account of their partnership interest and liabilities that are non–recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Fees and cost reimbursements that must be paid to our general partner and the dealer manager regardless of success of the Partnership’s activities will reduce the cash we have available for distribution.

The general partner and its affiliates will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and will be reimbursed for general and administrative costs of the general partner allocable to the Partnership as described in “Compensation,” regardless of the Partnership’s success in acquiring, developing and operating properties. The dealer manager will receive sales commissions, marketing fees, the contingent, incentive fee and account maintenance fees in connection with the offering as described in “Compensation.”  The fees and direct costs to be paid to the general partner, Former Manager and the dealer manager will reduce the amount of cash distributions to investors.

The initial offering price for the common units was determined arbitrarily.

Because there has been no previous market for any of our common units, the initial offering price for the common units was determined arbitrarily on the basis of our proposed capitalization, market conditions and other relevant factors.  The initial offering price will not necessarily reflect the price at which investors would be willing to buy and sell common units if there were a public market for such units.

Common units may be purchased by individuals who have an interest in the offering different from yours.

The owners of our general partner have each purchased 5,000 common units for $20.00 per unit.  In addition, the partnership agreement does not restrict the ability of any service providers or vendors to the Partnership from purchasing common units.  In addition, if a matter were to be submitted to a vote of holders of common units, the owners of our general partner, and any affiliates or employees of the Former Manager or other service providers or vendors who purchase common units may have different interests from other holders of common units in voting their common units.

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Risks Related to Our Business

The financial information included herein regarding the Sanish Field Assets may not represent the financial results of the Sanish Field Assets for subsequent periods.

In accordance with the rules of the SEC, we have included herein financial information for the Sanish Field Assets for the three years ended December 31, 2014, and for the six months ended June 30, 2015 and 2014. During the three-year period ending December 31, 2014, the average price at which oil was sold from the Sanish Field Assets was approximately $95 per Bbl. In addition, reserves included herein at December 31, 2012, 2013, and 2014, were determined by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. At the end of 2014, oil prices began falling steeply, such that during the six months ending June 30, 2015, sales of oil from the Sanish Field Assets averaged approximately $54 per Bbl. While financial information regarding the past performance of a business is not typically a guaranteed indication of future performance, given the great disparity in current oil prices between the date the Sanish Field Assets were acquired and the time frame from which financial information regarding those assets is actually available, investors should understand that in the current pricing environment, past financial performance is less an indication of future financial performance than is usual.

We incurred significant seller secured financing indebtedness in connection with our Sanish Field Assets acquisition in December 2015.  The Seller Note and mortgage instruments governing this indebtedness contain restrictions that could adversely affect our operations, our ability to make acquisitions and our ability to pay distributions to our unitholders.

The Seller Note bears interest at 5% per annum and is payable in full no later than September 30, 2016 (the “Maturity Date”).  Subject to our compliance with the conditions contained in the Seller Note and the related collateral documents, we will have certain rights to extend the Maturity Date to March 31, 2017. Our right to extend the Maturity Date, however, is subject to the satisfaction of numerous conditions.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Oil and Natural Gas Properties Acquired.” Payment of the Seller Note is secured by a mortgage and liens on all of the Sanish Field Assets, having customary terms.  If we have not fully repaid all amounts outstanding under the Seller Note on or before June 30, 2016, we must also pay a deferred origination fee in an amount equal to $250,000.

Interest is due monthly on the last day of each month while the Seller Note remains outstanding. In addition to interest payments on the outstanding principal balance of the Seller Note, we must make mandatory principal payments monthly in an amount equal to 75% of the net proceeds we receive from the sale of our equity securities until the principal amount of the Seller Note is reduced to $60 million, and 50% of the net proceeds we receive from the sale of our equity securities thereafter, until the Seller Note is paid in full. We can make no assurances that we will be successful receiving sufficient proceeds of future sales of our securities in our initial public offering.

Because the indebtedness under the Seller Note is secured by a mortgage on our Sanish Field properties, the Partnership could lose these properties through foreclosure or other proceedings, if it defaults on that indebtedness. If the Partnership defaults under the Seller Note, the interest rate under the Seller Note will increase and it is possible that the Partnership could become involved in litigation related to matters concerning its indebtedness under the Seller Note. Such litigation could result in significant costs.

The dedication of amounts of net proceeds we receive from subsequent sales of equity securities to repay the outstanding indebtedness under the Seller Note will reduce our cash available to make distributions to our unitholders or other operating investments, until the indebtedness is repaid.  In addition, these and other credit arrangements we may enter into may have the effect of restricting our ability to obtain additional financing, make investments, lease equipment, sell assets, enter into commodity and interest rate derivative contracts and engage in further property acquisitions.  Our ability to comply with the terms of these debt arrangements in the future is uncertain and will be affected by the levels of cash flow from our operations, additional equity sums we raise from sales of our units, and events or circumstances beyond our control.  Our failure to comply with certain of the requirements of these debt instruments could result in an event of default under their terms, which, if such default continues beyond any applicable cure periods, could cause all of our existing indebtedness to be immediately due and payable.

Additionally, defaulting under the loan may damage the Partnership’s reputation as a borrower and may limit its ability to secure financing in the future.

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We will need additional funding for the Sanish Field Assets in order to retain our full interest therein.

In addition to the $160 million initial purchase price for the Sanish Assets, we anticipate that we will be obligated to invest an additional $75 million in drilling capital expenditures through 2020 to retain our working interest in the Sanish Field Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties.  We will depend, at least in part, on continued sales pursuant to the terms of this Offering, to fund the anticipated capital expenditures needed to retain our full interest in these assets. We anticipate paying the contingent payment, which will only arise if oil prices increase significantly over the next few years, out of the proceeds of production from the assets acquired and from additional financing that should become available if oil prices rise. None of these funding sources is guaranteed, and if we are unable to obtain all of this funding we may lose all or a portion of the assets acquired, and our results of operations will be negatively affected accordingly.

We will have limited control over the activities on properties we do not operate.

Whiting operates 99% of the properties in which we hold a working interest. We have limited ability to influence or control the operation or future development of the non-operated properties or the amount of capital expenditures that we are required to fund. The failure of Whiting to adequately perform operations, breach the applicable agreements or failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on Whiting and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units under our cash distribution policy.

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

· that our strategy of acquiring oil and gas properties at attractive prices and developing those properties may not be successful or even if we successfully acquire properties, that our operations on such properties may not be successful;

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

· the prices at which we sell our production;

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

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

· the level of our capital expenditures;

· the level of our operating and administrative costs including reimbursement of our general partner; and

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

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

· the amount of cash reserves established by our general partner for the proper conduct of our business and for capital expenditures, which may be substantial;

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

· our debt service requirements and other liabilities;

· fluctuations in our working capital needs;

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· our ability to borrow funds;

· the timing and collectability of receivables; and

· prevailing economic conditions.

As a result of these factors, the amount of cash we distribute to holders of our common units may fluctuate significantly from month to month.

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

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

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

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

· the amount of added production from development of unconventional natural gas reserves;

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

· the level of consumer product demand;

· weather conditions and natural disasters;

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

· overall domestic and global economic conditions;

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

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

· technological advances affecting energy production and consumption;

· domestic and foreign governmental regulations and taxation;

· the impact of energy conservation efforts;

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

· speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

· price and availability of competitors’ supplies of oil and natural gas; and

· the price and availability of alternative fuels.

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

Because we will depend on our general partner and its affiliates to conduct our operations, any adverse changes in the financial health of our general partner or our relationship with them could hinder our operating performance and ability to make distributions.

We will depend on our general partner and its affiliates and possibly other third party operators, for the acquisition, development and operation of our properties. Our general partner has been recently formed and has limited prior operating history. Any adverse changes in the financial condition of the general partner or in our relationship with them could hinder its or their ability to successfully manage our operations.

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

Any acquisition or decision to develop a property we have acquired will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors.  Reserve estimates may be prepared internally by us or by a third party.  The process of estimating oil and gas reserves is complex.  It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds, all of which can be difficult to predict with accuracy.  As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.  We expect that our review efforts will be focused on the higher valued properties in our acquisitions and will be inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential.  Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken.  Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to make cash distributions to holders of our common units and service our debt obligations.

Additional potential risks related to the acquisition and development include, among other things:

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

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

· drilling, operating and other cost overruns;

· an inability to integrate successfully the properties we acquire;

· the assumption of liabilities;

· limitations on rights to indemnity from the seller;

· the diversion of management’s attention from other business concerns; and

· losses of key employees.

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We may engage in exploration activities on properties we acquire which activities are more risky than development activities.

We expect to acquire oil and gas properties which require additional drilling and other exploitation activities to fully develop.  Some of the drilling on our properties may be classified as exploration drilling.  Exploration drilling is inherently more risky than development drilling.  Although we expect that our exploration drilling will be located near areas which have undergone successful drilling or in areas with geological characteristics similar to areas which have been successfully developed, no assurances can be made that the Partnership’s exploration or development drilling will be successful in discovering producible oil and gas reserves.

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

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

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has released a draft of a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater.  These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

Moreover, the EPA proposed effluent limitations for the pretreatment and discharge of wastewater resulting from hydraulic fracturing activities to publicly owned treatment works. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. Further, the Bureau of Land Management has adopted final rules regulating hydraulic fracturing on public lands.  These rules include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  We are currently evaluating the impact of these rules on our operations.  The EPA has also announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals.  If hydraulic fracturing is further regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operations restrictions and also to associated permitting delays and potential increases in costs.  Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we ultimately are able to produce.

Our hedging transactions will expose us to counterparty credit risk.

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

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

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

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

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

Our policy will be to hedge a portion of our near–term estimated production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current oil, natural gas and other hydrocarbon prices.  Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production.  Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases.  It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil, natural gas and natural gas liquids revenues becoming more sensitive to commodity price changes.  Our general partner will not be liable for any losses we incur as a result of our hedging policy or the implementation of that policy.

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

During 2010, President Obama signed into law the Dodd–Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act.  Among other things, the Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over–the–counter market.

In its rulemaking under the new legislation, the CFTC has issued numerous new regulations, including on November 5, 2013, a proposed rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions).  The CFTC has not yet issued a final rule on position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

The Dodd-Frank Act and the regulations enacted thereunder by the CFTC generally mandate that all swaps are required to be: (i) cleared through derivatives clearing organizations, (ii) traded on registered exchanges, and (iii) subject to mandatory posting of initial and variation margin as credit support. In addition, the Dodd-Frank Act and the CFTC’s regulations thereunder provide exemptions for commercial end users (such as us) using swaps to hedge their commercial risk from these clearing, exchange-trading and margin-posting requirements, thereby allowing commercial end-users to enter into over–the–counter, bilaterally negotiated swaps for their hedging transactions.  The CFTC has not yet issued a final rule on capital requirements for swap dealers. However, it is possible that our counterparties in respect of their over-the-counter (i.e., uncleared) hedging transactions with us will be subject to capital requirements. Similarly, with respect to our counterparties’ uncleared swaps with third parties entered into in order to perform under their uncleared hedging transactions with us, our counterparties may be subject to margin-posting requirements.  If the regulations ultimately adopted require our counterparties to maintain higher capital levels or to post margin in connection with entering into hedging transactions with us, the costs of which could be passed through to us, then our hedging would become more expensive and we may decide to alter our hedging strategy.

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The financial reforms required by the Dodd-Frank Act may also require our hedging counterparties to spin off some of their derivative activities to separate entities, which may not be as creditworthy as our current counterparties.  The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, restrict our flexibility in conducting trading and hedging activity and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may be more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and other hydrocarbon prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and other hydrocarbons.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.

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

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

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

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

Our acquisitions involve numerous risks, including:

· operating a significantly larger combined organization and adding operations;

· difficulties in the assimilation of the assets and operations of the acquired properties, especially if the assets acquired are in a new geographic area;

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

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

· the diversion of the management attention of our general partner from other business concerns;

· the failure to realize expected profitability or growth;

· the failure to realize expected synergies and cost savings;

· coordinating geographically disparate organizations, systems and facilities; and

· coordinating or consolidating corporate and administrative functions.

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

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

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

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

· unexpected drilling or operating conditions;

· facility or equipment failure or accidents;

· shortages or delays in the availability of drilling rigs and equipment and in hiring qualified personnel;

· adverse weather conditions;

· shortages of water required for hydraulic fracturing or other operations;

· compliance with environmental and governmental requirements;

· reductions in oil or gas prices;

· proximity to and capacity of transportation and processing facilities;

· title problems;

· encountering abnormal pressures or unusual, unexpected or irregular geological formations;

· pipeline ruptures;

· fires, blowouts, craterings and explosions; and

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

Even if drilled, completed wells may not produce quantities of oil or natural gas that are economically viable or that meet earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources.

We must find or acquire economically recoverable reserves to sustain production and future cash flows.  If we are unable to find or acquire reserves, our future financial condition will be adversely affected.

Our continued success depends upon our ability to find, develop and acquire oil and gas reserves that are economically recoverable. If we do not drill suitable prospects, you are unlikely to realize your investment expectations.

In addition, our future oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful acquisition and development activities. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in developing or acquiring additional reserves.

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 We may be unable to compete effectively with larger companies and may not be able to implement new technology as efficiently as larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to holders of our common units and service our debt obligations.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us.  Our ability to acquire oil and gas properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  Many of our larger competitors not only acquire properties, drill for and produce oil, natural gas and natural gas liquids, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.  These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit.  The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases.  Competition has been strong in hiring experienced personnel, particularly in the technical, accounting and financial reporting, tax and land departments.  In addition, competition is strong for attractive oil and natural gas properties.  We may be often outbid by competitors in our attempts to acquire properties.  Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are able to do the same. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use becomes obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

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

Our business activities are subject to operational risks, including:

· damages to equipment caused by adverse weather conditions, including tornadoes, drought and flooding;

· unexpected formations and pressures;

· facility or equipment malfunctions;

· pipeline ruptures or spills;

· fires, blowouts, craterings and explosions;

· release of toxic gasses;

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

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

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

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

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

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

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

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

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

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

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

· the Endangered Species Act and comparable state and local laws and regulations which protect endangered and threatened species and the ecosystems on which they depend;

· the National Environmental Policy Act and comparable state statutes which ensure that environmental issues are adequately addressed in decisions involving major governmental actions (including the leasing of government land);

· the Toxic Substances Control Act and comparable state statutes which regulate the manufacture, use, distribution and disposal of chemical substances;

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

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

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

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

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

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

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

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements.  Further, the EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources.

In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis.  We are in the process of evaluating whether our operations trigger this requirement. In past years, we have not triggered the reporting obligation and continue to evaluate annually whether we trigger this requirement; should we trigger the reporting requirement, we will incur costs associated with the reporting obligation.

In past legislative sessions, Congress considered legislation to reduce emissions of GHGs and many states and regions have adopted or have considered measures to reduce GHG emission reduction levels, often involving the planned 

development of GHG emission inventories and/or cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances.  Federal efforts at a cap and trade program have not moved forward in Congress.  Some members of Congress have publicly indicated an intention to introduce legislation to curb the EPA’s regulatory authority over GHGs.  The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.

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

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

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

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs.  The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells.  Before January 1, 2015, these standards required owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device.  Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions.  The standards are applicable to newly fractured wells and also existing wells that are refractured.  Further, the finalized regulations also established specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules and any revised rules may require the installation of equipment to control emissions on producing properties we acquire.

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

The marketability of our production will depend upon numerous factors beyond our control, including the availability and capacity of natural gas gathering systems, pipelines and other transportation and processing facilities that we expect to be owned by third parties.  Transportation space on the gathering systems and pipelines we expect to utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements.  Our access to transportation and processing options and the marketing of our production can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, as well as the other risks discussed in this prospectus.  The availability of markets are beyond our control.  If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil, natural gas and natural gas liquids, the value of our common units and our ability to pay distributions on our common units and service our debt obligations.

We may be required to shut-in wells or delay initial production for lack of a viable market or because of the inadequacy or unavailability of pipeline, gathering system, processing, treating, fractionation or refining capacity. When that occurs, we will be unable to realize revenue from such wells until the inadequacy or unavailability is remedied. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas 

reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our general partner and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

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Risks Related to the JOBS Act

We are an emerging growth company under the JOBS Act and we intend to take advantage of reduced disclosure and governance requirements applicable to emerging growth companies, which could result in our common units being less attractive to investors.

We are an emerging growth company, as defined in the JOBS Act, and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved.  We cannot predict if investors will find our common units less attractive because we will rely on these exemptions.  We expect to take advantage of these reporting exemptions until we are no longer an emerging growth company, which in certain circumstances could be for up to five years.

Our election to take advantage of the JOBS Act’s extended accounting transition period may not make our financial statements easily comparable to other public companies.

Pursuant to the JOBS Act, as an emerging growth company we can elect to take advantage of the extended transition period for any new or revised accounting standards that may be issued by the Public Company Accounting Oversight Board or the SEC.  We have elected take advantage of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the standard for the private company.  This may make comparison of our financial statements with any other public company that is neither an emerging growth company nor an emerging growth company that has opted out of using the extended transition period difficult or impossible as different or revised standards may be used.  We cannot predict if investors will find our common units less attractive because we may rely on these exemptions.

Our status as an emerging growth company under the JOBS Act may make it more difficult to raise capital in this offering.

Because of the exemptions from various reporting requirements provided to us as an emerging growth company, and because we will have an extended transition period for complying with new or revised financial accounting standards, we may be less attractive to investors and it may be difficult for us to raise sufficient capital in this offering.  Investors may be unable to compare our business with other companies in our industry if they believe that our financial accounting will not be as transparent as other companies in our industry.  If we are unable to raise sufficient capital in this offering it may impact our ability to raise our maximum offering proceeds.  In addition, if we are unable to raise sufficient additional capital, it may limit the number of oil and gas properties that we may acquire.

The JOBS Act will allow us to postpone the date by which we must comply with certain laws and regulations intended to protect investors and reduce the amount of information provided in reports filed with the SEC.

The JOBS Act is intended to reduce the regulatory burden on emerging growth companies.  We meet the definition of an emerging growth company and so long as we qualify as an emerging growth company we may, among other things:

· be exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act requiring that our independent registered public accounting firm provide an attestation report on the effectiveness of its internal control over financial reporting;

· be exempt from the “say on pay” provisions (requiring a non-binding shareholder vote to approve compensation of certain executive officers) and the “say on golden parachute” provisions (requiring a non-binding shareholder vote to approve golden parachute arrangements for certain executive officers in connection with mergers and certain other business combinations) of the Dodd-Frank Act and certain disclosure requirements of the Dodd-Frank Act relating to compensation of our chief executive officer;

· be permitted to omit the detailed compensation discussion and analysis from proxy statements and reports filed under the Securities Exchange Act of 1934 and instead provide a reduced level of disclosure concerning executive compensation; and

· be exempt from any rules that may be adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report on the financial statements.

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We currently intend to take advantage of all of the reduced regulatory and reporting requirements that will be available to us so long as we qualify as an emerging growth company.  We cannot predict if investors will find our common units less attractive because we may rely on these exemptions.

As long as we qualify as an emerging growth company, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting.

Our independent registered public accounting firm will not be required to provide an attestation report on the effectiveness of our internal control over financial reporting so long as we qualify as an emerging growth company, which may increase the risk that weaknesses or deficiencies in the internal control over financial reporting go undetected.  Likewise, so long as we qualify as an emerging growth company, we may elect not to provide certain information, including certain financial information and certain information regarding compensation of executive officers, which we would otherwise have been required to provide in filings with the SEC, which may make it more difficult for investors and securities analysts to evaluate us.  As a result, investor confidence in us may be adversely affected.

Tax Risks to Common Unitholders

You should read carefully the following discussion of tax risks together with the section entitled “Material Federal Income Tax Consequences,” which includes a more detailed discussion of the U.S. federal income tax consequences associated with an investment in us. There are risks associated with the U.S. federal income tax consequences of becoming a holder of our common units. The following paragraphs summarize some of these risks. Because the tax consequences of becoming a holder of our common units are complex and certain tax consequences may differ depending on individual tax circumstances, you are urged to consult with your own tax advisor regarding the tax consequences of becoming a holder of our common units.

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes and not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to our unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and likely would pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, in Texas, we will be subject to an entity level tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.675% of our total revenue that is apportioned to Texas beginning January 1, 2014 (which rate may decrease to .65% beginning January 1, 2015 upon certification by the State of Texas during 2015 or which may increase to .7% on January 1, 2015 if no such certification is made, and in any case will increase to 0.7% on January 1, 2016). Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to a unitholder.

An IRS contest of our U.S. federal income tax positions may adversely affect the value for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the value of our units. In addition, costs incurred in any contest with the IRS will be borne indirectly by holders of common units and our general partner because the costs will reduce our cash available for distribution.

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You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Because holders of our common units will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us.  You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.

You may not qualify for percentage depletion deductions, and even if you do so qualify, you will be required to determine, and maintain records supporting, your deduction.

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Code Section 613A(c). For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. We cannot determine whether or provide any assurance that you will qualify as an independent producer. Further, if you do qualify as an independent producer, you are required to determine the amount of your allowed percentage depletion deduction and maintain records supporting such determination.

Counsel is unable to express an opinion as to whether percentage depletion will be available to a particular common unitholder or the extent of the percentage depletion deduction available to any particular common unitholder.

Counsel is unable to express any opinion with respect to the availability or extent of percentage depletion deductions to any particular common unitholders for any taxable year. We encourage you to consult your tax advisor to determine whether percentage depletion would be available to you.

We cannot assure you that we will meet the requirements for you to deduct intangible drilling and development costs.

Federal tax law places substantial limits on taxpayers' ability to deduct intangible drilling and development costs (“IDCs”). Generally speaking, an “operator” is permitted to elect to currently deduct, or capitalize and deduct ratably over a 60-month period, costs that are properly characterized as IDCs that the operator incurs in connection with the drilling and development of oil and natural gas wells. For purposes of deducting IDCs, an “operator” is generally defined as one that owns a working or an operating interest in an oil or gas well. If we determine that we are an “operator” with respect to our oil and gas wells, our determination is not binding on the IRS. The IRS may assert that we are not an “operator” with respect to one or more of our oil or gas wells at the time that IDCs are incurred. If the IRS were successful in such a challenge, we and, therefore, you, would not be entitled to deduct the IDCs incurred in connection with such wells.

If we are eligible to deduct IDCs, we cannot assure you that IDCs will be deductible in any given year.

If we are deemed to be an operator with respect to one or more of our oil or gas wells, our classification of a cost as an IDC is not binding on the IRS. The IRS may reclassify an item classified by us as an IDC as a cost that must be capitalized or that is not deductible.

The IRS could challenge the timing of our deductions of IDCs, which could result in an increase your tax liabilities.

IDCs are generally deductible when the well to which the costs relate is drilled. In some cases, IDCs may be paid in one year for a well that is not drilled until the following year. In those cases, the prepaid IDCs will not be deductible until the year when the well is drilled unless (i) drilling on the well to which the prepayment relates starts within 90 days after the end of the year the prepayment is made or (ii) it is reasonable to expect that the well will be fully drilled within 31/2 months of the prepayment.  All of our wells may not be drilled during the year when we pay IDCs pursuant to a drilling contract. As a result, we could fail to satisfy the requirements to deduct the IDCs in the year when paid and/or the IRS may challenge the timing of our deduction of prepaid IDCs.

The deduction for IDCs may not be available to you if you do not have passive income.

If you invest in us, your share of our deduction for IDCs in the year you invest will be a passive loss that can be used to offset only passive income.  Such deductions cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Any unused passive loss from IDCs may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Certain taxpayers are not subject to the passive loss rules.

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On the disposition of property by us or of common units by you, certain deductions for IDCs, depletion, and depreciation must be recaptured as ordinary income.

You may be required to recapture as ordinary income certain deductions for IDCs, depletion, and depreciation on disposition of property by us or on disposition of our common units.

Counsel is unable to express an opinion as to whether the deduction related to U.S. production activities will be available to a particular common unitholder or the extent of any such deduction to any particular common unitholder.

The Code Section 199 deduction is required to be computed separately by each common unitholder.  Consequently, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Code Section 199 deduction to any particular common unitholder.  We encourage you to consult your tax advisor to determine whether the Code Section 199 deduction would be available to you.

Tax gain or loss on disposition of common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that unit, even if the price is less than your original cost. As discussed above, a substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

Investment in common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, much of our income allocated to organizations that are exempt from federal income tax, including IRAs, will be unrelated business taxable income and will be taxable to them. Similarly, much of our income allocable to non-U.S. persons will constitute effectively connected U.S. trade or business income, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.

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

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

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

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

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Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

The Obama administration’s budget proposals for fiscal year 2015 contain numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies. Among others, the provisions include: repeal of the deduction of IDC; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; and an increase in the amortization period for geological and geophysical costs of independent producers.

The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could increase the amount of our taxable income allocable to you.  We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any modifications to the federal income tax laws or interpretations thereof may or may not be applied retroactively.  Any such changes could negatively impact the value of an investment in our common units.

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CONFLICTS OF INTEREST

In General

Your interests and those of the general partner and its affiliates may be inconsistent in some respects or in certain instances and the general partner and its affiliates’ actions may not be the most advantageous to you. The following discussion describes possible conflicts of interest that may arise for the general partner and its affiliates in the course of the Partnership’s property acquisition and drilling activities contemplated in this prospectus.  For some of the conflicts of interest, but not all, there are certain limitations on the general partner that are designed to reduce, but will not eliminate, the conflicts. Other than these limitations, the general partner has no procedures to resolve a conflict of interest and under the terms of the Partnership Agreement, the general partner may resolve the conflict of interest in its sole discretion and best interest.  Our Partnership Agreement contains provisions intended to eliminate the general partner’s liability to our Partnership and the owners of common units as long as the general partner acts in good faith.  See “Fiduciary Duty of the General Partner.”

The following discussion is materially complete; however, other transactions or dealings may arise in the future that could result in additional conflicts of interest for the general partner and its affiliates.

Conflicts Regarding Transactions with the General Partner and its Members and Affiliates

Under our Partnership Agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our Partnership. However, because our general partner is owned by its four members, the officers and directors of our general partner have a duty to manage the business of our general partner in a manner that is in the best interests of those members. As a result of this relationship, conflicts of interest may arise in the future between us and our common unitholders, on the one hand, and our general partner and its members, on the other hand. For example, in the acquisition, development and sale of our oil and gas properties, our general partner will make decisions affecting the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions.  However, these actions are permitted under our Partnership Agreement and will not be a breach of any duty (fiduciary or otherwise) of our general partner.

Although the general partner believes that the compensation and reimbursements that it and its affiliates will receive in connection with the Partnership are reasonable, the compensation has been determined solely by the general partner and did not result from negotiations with any unaffiliated third-party dealing at arm’s length. The general partner and its affiliates will receive reimbursement of direct, third party costs in forming the Partnership and will be reimbursed for general and administrative costs of the general partner and its affiliates allocable to the Partnership, as described in “Compensation,” regardless of the success of the Partnership’s wells. The general partner will also receive the incentive distribution rights entitling the general partner to distributions under certain circumstances.  The terms of the incentive distribution rights were determined by the general partner and are not the results of arms-length negotiation.  See “The Offering — Compensation of Our General Partner, Its Affiliates and Certain Non-Affiliates.”

Under our Partnership Agreement, we will reimburse the general partner for its general and administrative expenses incurred in operating our business.  Initially, managing our Partnership will be the only business activity of the general partner, so all of its general and administrative expenses will be reimbursed by the Partnership.  However, in the future, the general partner may form other partnerships or engage in other business activities.  If this were to occur, our Partnership Agreement provides that the general partner will allocate its general and administrative expenses between our Partnership and the other partnerships or activities in any manner the general partner determines is reasonable.  The general partner will be subject to a conflict of interest in performing such allocation.

Conflicts Regarding Other Activities of Affiliates of the General Partner

Management of the general partner intends to devote to the Partnership the time and attention considered necessary for the proper management of the Partnership’s activities. However, management of the general partner will engage in unrelated business activities, either for their own account or on behalf of other partnerships, joint ventures, corporations, or other entities in which they have an interest. This creates a continuing conflict of interest in allocating management time. See “Risk Factors — Risks Inherent in an Investment in Us.”  Officers of the general partner and its affiliates may manage other businesses and will not devote their time exclusively to managing the Partnership and its business, and the Partnership may face additional competition for time and capital because neither the general partner nor its affiliates are prohibited from raising money for or managing other entities that pursue the same types of investments that the Partnership targets.

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Affiliates of the general partner will not be restricted from participating in other businesses or activities, even if these other businesses or activities compete with the Partnership’s activities and operate in the same areas as the Partnership.

Conflicts Involving the Acquisition and Sale of Properties

The Partnership Agreement gives the general partner the authority to cause the Partnership to acquire producing and non-producing oil and natural gas properties, and to participate with other parties in the conduct of its drilling and other development operations on those properties. Conflicts of interest may arise concerning which properties will be acquired by the Partnership and which properties will be acquired by the general partner and its respective affiliates for their own account or for other affiliated partnerships, third-party programs or joint ventures. It may be to the general partner’s or its affiliates’ advantage to have the Partnership bear the costs and risks of acquiring a particular property rather than another affiliate or itself. Conversely, the general partner and its affiliates may elect to acquire a property for their own account because of the prospective economic benefits. Some of these potential conflicts of interest will be increased if the general partner allocates properties to the Partnership and itself or its affiliates for their own account, or to another affiliated partnership, at the same time. Also, a conflict of interest is created with you and the other holders of units by the general partner’s right to cause the Partnership to enter into a farmout with the general partner or its affiliates.

The four owners of the members of the general partner (each a “GP Owner”) have agreed that, until 90% of the capital contributions have been spent or reserved for investment, the GP Owner will not acquire, directly or indirectly through any entity formed or controlled by such GP Owner, a working interest in an oil and gas property where such business opportunity was referred to the GP Owner or an entity formed or controlled by the GP Owner.   

The properties acquired by the Partnership will be limited and the general partner and its respective affiliates may acquire or retain lease acreage and drilling rights surrounding the prospects and properties.  As a result, the general partner anticipates that the wells drilled by the Partnership to develop its properties will provide the general partner or its affiliates with additional drill sites on adjacent acreage in which they may own an interest by allowing them to determine, at least in part at the Partnership’s expense, the value of adjacent acreage and other geological formations, zones, areas and reservoirs in which the Partnership will not have any interest but in which they may own or acquire an interest.  In this regard, the general partner or its affiliates own, or may own, acreage throughout the area where the Partnership’s properties are situated.

If the general partner and its affiliates must provide properties to two or more partnerships at the same time, the general partner will attempt to ensure that each partnership is treated fairly on a basis consistent with:

· the funds available to each such partnership; and

· the time limitations on the investment of funds for each such partnership.

Also, the Partnership Agreement gives the general partner the authority to cause the Partnership to acquire less than 100% of the ownership interests in oil and gas properties, and to participate with other parties, including other oil and gas limited partnerships subsequently sponsored by the general partner or its affiliates, in the development on those properties. If conflicts of interest arise between the Partnership, on the one hand, and the general partner and its affiliates, on the other, then the general partner may be unable to resolve those conflicts to the maximum advantage of the Partnership, because the general partner and its affiliates must deal fairly with the investors in all of their oil and gas limited partnerships, in addition to the equity owners in itself and its affiliates.

Our general partner currently anticipates that all of our properties will be acquired from independent third parties.  However, it is possible that we will acquire properties from one or more affiliates of the general partner.  In addition, we may acquire an interest in properties in which one or more affiliates of the general partner have an interest.  Our general partner also will be permitted to sell or farmout oil and gas properties which we acquire, including to one or more affiliates of the general partner.

If we acquire an oil and gas property from, or sell or farmout a property to, an affiliate of the general partner, our general partner will be subject to conflicts of interest.  Our partnership agreement has procedures that the general partner may follow to resolve these conflicts of interest, which procedures are intended to protect our general partner if it makes a decision in good faith.

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Conflicts of Interest Relating to the Incentive Distribution Rights

The general partner will own the incentive distribution rights.  The incentive distribution rights entitle the general partner to distributions after Payout occurs.  The incentive distribution rights may cause the general partner to acquire properties or conduct operations that are more risky to the Partnership than other business opportunities that are available to the Partnership.  In addition, the incentive distribution rights may create conflicts of interest in connection with the sale of properties if the sale of properties will change the likelihood of distributions with respect to the incentive distribution rights compared with retaining the properties.

Conflicts of Interest; Standard of Conduct

As described under “Fiduciary Duty of the General Partner” our Partnership Agreement provides that our general partner will discharge its fiduciary duty to us as long as the general partner makes decisions in good faith.  Whenever a potential conflict of interest exists or arises between the general partner or any of its affiliates on the one hand, and the holders of common units, on the other, any resolution or course of action by the general partner or its affiliates in respect of such conflict of interest shall be permitted and deemed approved by all partners, and shall not constitute a breach of our Partnership Agreement, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is:

(i)   approved by the vote of a majority of the common units (excluding common units owned by the general partner and its affiliates),

(ii)  on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties, or

(iii) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership).

If the board of directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (ii) or (iii) above, then it shall be presumed that, in making its decision, the board of directors of the general partner acted in good faith, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or the Partnership challenging such approval, the person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption.

There can be no assurances that conflicts of interest between the general partner and you and the other investors will be resolved in your best interests.

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SOURCE OF FUNDS AND ESTIMATED USE OF OFFERING PROCEEDS

Source of Funds

The Partnership was required receive minimum offering proceeds of $25,000,000 to break escrow, and the maximum offering proceeds may not exceed $2,000,000,000. The minimum offering was reached on August 19, 2015.

There are no other requirements regarding the size of the Partnership.

On completion of this offering of our common units, the Partnership’s source of funds will be as follows:

· the gross offering proceeds, which will be $2,000,000,000 if the maximum number of common units are sold; and

· borrowings under a credit facility we expect to enter into prior to the maturity of the Seller Note.

The net offering proceeds available to the Partnership for investment from capital contributions is expected to be not more than approximately $1,872.0 million if 100,263,158 common units are sold. Such amounts include the gross offering proceeds (net of commissions and marketing fees and estimated offering and organization costs of $8.0 million if the maximum offering is achieved).  The amount of borrowings available under our credit facility for investment will depend on the value of the reserves attributable to the properties we acquire.  We do not plan to borrow more than 50% of our total capitalization determined on an annual basis.

Estimated Use of Offering Proceeds

The gross offering proceeds together with our general partner’s contribution will be used by the Partnership to pay the following:

· the possible payment of distributions as described under “Capital Contributions and Distributions;”

· the acquisition costs of the properties acquired by the Partnership;

· the costs of developing and operating the Partnership’s oil and gas properties; and

· the offering and organization costs incurred by the general partner in forming the Partnership and the reimbursement of the general partner’s general and administrative costs allocable to the Partnership business.

The Partnership Agreement provides that the general partner shall conduct the Partnership’s business so that an amount equal to at least 65% of the gross proceeds from the sale of common units are invested in the acquisition, development, exploration, exploitation of oil and gas properties and related capital assets.

Offering and organization costs are composed of the dealer manager fee, the marketing fee and out-of-pocket third-party costs such as legal, accounting, printing, filing fees and similar costs related to the organization of the partnership and the offering of the common units.  We estimate that the portion of the offering and organization expenses attributable to reimbursed out-of-pocket third party fees will be $8.0 million if the maximum subscription is achieved.  While we make these estimates in good faith, they are inherently imprecise, and are dependent on events that will occur in the future.  Some of the factors that will affect the actual out-of-pocket expenses we will reimburse are,

· The number of prospectuses we print and distribute;

· The number of supplements to the prospectus we prepare, print and distribute;

· The length of time the offering is being made; and

· The number of states in which we offer common units.

 There is no maximum amount of out-of-pocket expenses we will pay or reimburse to the general partner.  Accordingly, the actual amount of reimbursed out-of-pocket expenses could be materially higher than the foregoing estimates.

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The following table presents information concerning the Partnership’s estimated use of the gross proceeds from the sale of common units.

Substantially all of the gross offering proceeds available to the Partnership will be expended for the following purposes and in the following manner:

Estimated Use of Proceeds

(Dollars in Thousands)

	Maximum Offering		%
Gross Proceeds	$	2,000,000		100.00	%
Offering and organization costs:
Dealer manager commissions and marketing fee	$	120,000		6.0	%
Third party fees and expenses related to organization	$	8,000		0.4	%
Amounts available for investment, management fees, general and administrative expenses and distributions to common unitholders.(1)	$	1,872,000		93.6	%

(1)   The Partnership Agreement provides that the general partner shall conduct the Partnership’s business so that an amount equal to at least 65% of the gross proceeds from the sale of common units are invested in the acquisition, development, exploration, exploitation of oil and gas properties and related capital assets.

We plan to use net revenues from our oil and gas properties to pay management fees, general and administrative expenses and to make distributions to partners.  However, until we acquire oil and gas properties and sell production from those properties sufficient to pay such amounts, we will use the net proceeds from the sale of units to pay the management fee, pay general and administrative expenses and make distributions.  The following table indicates our estimates of the management fee, general and administrative expenses and distributions that will be paid during the 12 months following the first closing, assuming the maximum offerings and no indebtedness.  The portion of each of these expenses paid with capital contributions will depend on the amount of time between the initial closing of the offering and the sale of production from the oil and gas properties we acquire, and the amount of net revenues we receive from such sale of production.

	Maximum Offering
	(In thousands)
General and administrative expenses (1)	$	4,000
Distributions (2)	$	140,000

(1) General and administrative expenses will include reimbursement to the general partner for its general and administrative expenses, including compensation expense, rent, travel and other general and administrative expenses.  The amount set forth above is an estimate only and necessarily imprecise.

(2) Assumes that we will distribute the Payout Accrual.  The general partner is under no obligation to cause the Partnership to distribute the Payout Accrual.  See “Distributions.”

We plan to use the net proceeds of the offering that are not used to pay general and administrative expenses and distributions to acquire and develop oil and gas properties. At this time, we cannot estimate the portion of the remaining proceeds that will be spent on acquisitions of oil and gas properties and the development of those oil and gas properties. Factors that will affect the amount we spend on oil and gas property acquisitions and subsequent development will include our general partner’s evaluation of a number of factors, including:

· The oil and gas properties that are identified to us for acquisition and that we determine to acquire and the projected returns to the Partnership from acquisition of the available properties;

· The risks and returns associated with development activities compared with acquisition of producing properties;

· The availability of the equipment and services necessary to conduct development operations, and the possible volatility of the costs of such services and equipment;

· Environmental and other regulatory risks of drilling, completion and other development activities compared with the risks associated with acquisition of producing properties; and

· The timing and amount of cash flows attributable to properties which require additional development compared with properties that are substantially developed. 

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COMPENSATION

The following table summarizes the compensation to be paid to the general partner and the other persons listed below.  The amount of each item of compensation will depend on how many properties are acquired by the Partnership.

Compensation Related to the Organization of the Partnership

and Offering of Common Units

Type of Compensation	Method of Compensation	Estimated Dollar Amount
Sales commissions – paid in cash to David Lerner Associates, Inc. and selected broker-dealers	5% of the gross offering proceeds	Because sales commissions are based upon the number of common units sold, the total amount of sales commissions cannot be determined until this offering is complete.  Sales commissions of up to $100,000,000 will be paid if the maximum number of 100,263,158 common units is sold.
Marketing fee – paid in cash to David Lerner Associates, Inc. to compensate for advertisement for seminars related to the offering, the costs of the seminars including room rental, food, security, printing and mailing, attendance at trade shows, and compensation to non-sales personnel for promotional activities.	1% of the gross offering proceeds	Because the marketing fee is based upon the number of common units sold, the total amount of the marketing fee cannot be determined until this offering is complete.  A marketing fee of $20,000,000 will be paid if the maximum number of 100,263,158 common units is sold.
Reimbursement for third party expenses related to the organization of the Partnership and the offering of common units	Certain third party expenses related to the organization of the Partnership and the offering of common units will be reimbursed on an accountable basis.  The total amount of these costs that will be paid by the Partnership or the general partner will be reimbursed for is estimated to be $8.0 million if the maximum offering is achieved.	These expenses cannot be determined until the offering is completed.

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Compensation Related to the Operation of the Partnership

Type of Compensation	Method of Compensation	Estimated Dollar Amount
Contingent, incentive fee – paid in cash to David Lerner Associates, Inc.	David Lerner Associates, Inc. will receive the contingent, incentive fee after Payout. The contingent, incentive fee will not exceed 4% of the gross proceeds received by the Partnership for the sale of common units, less the amount of any account maintenance fees paid to David Lerner Associates, Inc. as described below. The dealer manager agreement provides that the contingent, incentive fee is payable to the dealer manager after Payout.  If the liquidity event is a sale of assets and distribution of the sales proceeds to the partners, the contingent, incentive fee will be paid as described under “Capital Contributions and Distributions — Distributions” and the dealer manager would receive its 30% share of the distribution, up to the 4% cap.  If the liquidity event is a merger or similar transaction in which the incentive distribution rights and class B Units are converted into or exchanged for securities or other property, the dealer manager agreement provides that an amount equal to 42.857% of the sum of the consideration paid to the holders of incentive distribution rights and class B Units will be segregated by the partnership, sold as soon as reasonably practicable and the cash proceeds paid to the dealer manager, up to the 4% cap (which would result in the dealer manager receiving 30% of the sum of the amounts paid to the holders of the incentive distribution rights, class B Units plus the contingent incentive fee).	The amount of the cash contingent, incentive fees to be paid to David Lerner Associates, Inc. cannot be determined at this time, but will not exceed 4% of the gross proceeds from the sale of the common units.  If the maximum subscription is achieved such fee will not exceed $80,000,000.  Any amounts paid for account maintenance as described below will reduce the maximum amount of the contingent, incentive fee.
Type of Compensation	Method of Compensation	Estimated Dollar Amount
Fee for Account Maintenance Services	Until the final termination date of the offering, David Lerner Associates, Inc. will receive account maintenance services fees of $5.00 per customer account that holds our common units and $10.00 per year for each such customer account still active , as fees for David Lerner Associates, Inc. maintaining information about the account and its owner(s), The account maintenance fees are capped at $500,000.  Account maintenance fees paid to David Lerner Associates, Inc. will reduce the 4% cap for the contingent, incentive fee under the Dealer Manager Agreement.	Future fees for account maintenance are not estimable, but are based on the number of customer accounts.  The maximum account maintenance services fees paid to David Lerner Associates will be $500,000.

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Reimbursement to the general partner and its affiliates for general and administrative expenses The Partnership will pay the general partner the amount of general and administrative expenses incurred by the general partner and its affiliates in connection with management of the Partnership.  These expenses will include compensation expense, rent, travel, and other general and administrative and overhead expenses.  Initially, the sole activity of the general partner will be to act as general partner of the Partnership.  If affiliates of the general partner form other oil and gas partnerships or engage in other oil and gas business activities, the general partner will allocate the general and administrative expenses of its affiliates to the Partnership and such other partnership or business in a manner the general partner determines is reasonable. Will depend on the activities of the Partnership which will depend upon the amount of units sold and other factors, and so cannot be estimated at this time.  The general partner estimates that the general and administrative expense reimbursement during the first year following the initial closing will be approximately $4.0 million if the maximum offering is achieved

Type of Compensation	Method of Compensation	Estimated Dollar Amount
Distributions – paid in cash to the general partner	The general partner received the incentive distribution rights that will entitle the general partner to receive 35% of the distributions after Payout.	Cannot be estimated at this time.
Distributions – paid in cash to Incentive Holdings	Incentive Holdings received class B units which, following cancellation of 37.5% thereof, will entitle it to receive 21.875% of the distributions after Payout.	Cannot be estimated at this time.

Compensation related to the Dissolution and Liquidation of the Partnership

Other than reimbursement of costs and expenses payable to third parties incurred on behalf of the Partnership and the liquidating distributions made and amounts paid with respect to the incentive distribution rights, the class B units, the dealer manager’s contingent, incentive fee and common units, if any, no additional compensation or other amounts will be paid to the general partner, the Former Manager, Incentive Holdings, David Lerner Associates, Inc. or their respective affiliates upon dissolution and liquidation of the Partnership.

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TERMS OF THE OFFERING

Subscription to the Partnership

Energy 11, L.P. was formed to offer for sale a minimum of 1,315,790 of common units, for gross proceeds of $25,000,000, and a maximum of 100,263,158 common units for gross proceeds of $2,000,000,000.  We initially offered common units at $19.00 per common unit until 5,263,158 common units were sold for gross proceeds of $100,000,000.  Since all of the common units offered at $19.00 have been sold, we are now offering common units at $20.00 per common unit until the maximum of 100,263,158 common units are sold.  All of our common units will have identical rights with respect to distributions, and voting rights, regardless of whether purchased for $19.00 or $20.00.

The offering period will terminate on the earlier of (i) January 23, 2017 or our general partner may extend the offering period until April 24, 2017 and (ii) the receipt and acceptance by the Partnership of the maximum subscription.  The general partner may terminate the offering at any time.

Partnership Closings

The initial closing of the offering at which the minimum offering was met was made on August 19, 2015. Additional closings will be held monthly during the offering period as orders are received. The final closing will be held shortly after the termination of the offering period or, if earlier, upon the sale of all the common units. It is expected that purchasers will be sold common units no later than the last day of the calendar month following the month in which their orders are received. Funds received during the offering will be held in purchasers’ accounts with David Lerner Associates, Inc. until the next closing, and then disbursed to us.

Each of the four owners of our general partner have purchased 5,000 common units for $20.00 per common unit ($400,000 total).  

Acceptance of Subscriptions

Your execution of the subscription agreement constitutes your offer to buy common units in the Partnership and to hold the offer open until either:

· your subscription is accepted or rejected by the general partner; or

· you withdraw your offer.

To withdraw your subscription agreement, you must give written notice to the general partner before your subscription agreement is accepted by the general partner.

Also, the general partner will:

· not complete a sale of common units to you until at least five business days after the date you receive a final prospectus; and

· send you a confirmation of purchase.

Status of the Offering

As of August 19, 2015, we completed our minimum offering of 1,315,790 common units at $19.00 per common unit. As of April 28, 2016, we had completed the sale of a total of 5,863,622 common units for total gross proceeds of $112.0 million and proceeds net of selling commissions and marketing expenses of $105.3 million.  As of April 28, 2016 the common units were held by approximately 1,800 unitholders. As of March 4, 2016 we had received subscriptions for all of the common units to be offered at $19.00 per unit. The public offering is being made through David Lerner Associates, Inc. (the “Managing Dealer”) and is continuing at $20.00 per unit.

Also, upon reaching the minimum offering, the Partnership entered into the First Amended and Restated Agreement of Limited Partnership at the Initial Closing, and the Partnership also entered into the Management Services Agreement with the Former Manager at the Initial Closing. Upon entering into the Management Services Agreement with the Former Manager on August 19, 2015, the Partnership issued 100,000 class B units to an affiliate of the Former Manager. On April 5, 2016, we terminated the Management Agreement.  Accordingly the fees under the Management Agreement will no longer accrue as of the effective date of termination. Also, upon termination of the Management Services Agreement and in accordance with the terms therewith, 37.5% of the class B Units owned by Incentive Holdings have been cancelled.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

The Partnership was formed as a Delaware limited partnership.  The General Partner is Energy 11 GP, LLC (the “General Partner”).  The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership is offering common units of limited partner interest (the “common units”) on a “best efforts” basis, with the intention of raising up to $2,000,000,000 of capital, consisting of 100,263,158 common units.  The Partnership’s Registration Statement on Form S-1 (File No. 333-197476) was declared effective by the SEC on January 22, 2015.  As of August 19, 2015, the Partnership completed the sale of the minimum offering of 1,315,790 common units for gross proceeds of $25 million.  Upon raising the minimum offering amount, the holders of the common units were admitted and the Partnership commenced operations.  Through December 31, 2015 the Partnership had sold a total of 4,486,625 common units for gross proceeds of $85.2 million.

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 made by the General Partner are made by the board of directors of the General Partner and its officers.  

The Partnership was formed to acquire and develop 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 nonproducing oil and gas properties.

Oil and Gas Properties Acquired

On September 15, 2015, the Partnership through a wholly owned subsidiary, entered into an Interest Purchase Agreement (“Purchase Agreement”) by and among Kaiser-Whiting, LLC and the owners of all the limited liability company interests therein (the “Sellers”), for the purchase of an 11% working interest in approximately 215 existing producing wells and approximately 262 future development locations in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). The Partnership closed on the purchase of the Sanish Field Assets on December 18, 2015.

Pursuant to the Purchase Agreement as amended by the First Amendment thereto, the purchase price for the Sanish Field Assets consisted of (i) $60 million in cash, subject to customary adjustments, (ii) an aggregate of $2 million, payable in equal amounts on December 31, 2016 and December 31, 2017, (iii) a promissory note in the amount of $97.5 million payable to Sellers (the “Seller Note”) and (iv) a contingent payment of up to $95 million. The contingent payment will provide for a sharing between the Partnership and the Sellers to the extent the NYMEX current five-year strip oil price for WTI at December 31, 2017 is above $56.61 (with a maximum of $89.00) per Bbl. The contingent payment will be calculated as follows: if on December 31, 2017 the average of the monthly NYMEX:CL strip prices for future contracts during the delivery period beginning December 31, 2017 and ending December 31, 2022 (the “Measurement Date Average Price”) is greater than $56.61, then the Sellers will be entitled to a contingent payment equal to (a) (i) the lesser of (A) the Measurement Date Average Price and (B) $89.00, minus (ii) $56.61, multiplied by (b) 586,601 Bbls per year for each of the five years from 2018 through 2022 represented by the contracts for the entire acquisition. The contingent consideration is capped at $95 million and is to be paid on January 1, 2018.  In addition, the First Amendment provides that so long as the Partnership is not in default under the Seller Note, in lieu of the Partnership’s obligation to pay the contingent payment, the Partnership has the one-time right (exercisable between June 15, 2016 through June 30, 2016) to elect to pay Sellers $5 million in full satisfaction of the contingent payment by paying to Sellers $5 million at the time of election or by increasing the amount of the Seller Note by $5 million.

Whiting Petroleum Corporation (“Whiting”), a publicly traded oil and gas company, is the operator of our properties on behalf of the Partnership and the other working interest owners in those properties.

The Partnership expects to invest approximately $3.0 million in capital expenditures during 2016 as long as oil, natural gas and NGL prices remain at or near their current depressed levels. Our capital expenditure plan has the flexibility to adjust, should the commodity price environment change. Reduced capital expenditures are anticipated to result in lower oil, NGL and natural gas production volumes in 2016.

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Since the Partnership is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes 2016 capital expenditures for drilling and completion projects difficult to forecast and current estimated capital expenditure could be significantly different from amounts actually invested.

Looking forward, the Partnership expects to fund overhead costs, capital additions related to the drilling and completion of wells primarily from cash provided by operating activities and cash on hand. Any excess cash (including cash from the net proceeds of sales of units in our public offering) is intended to be used to pay down the principal amount of the Seller Note in favor of the Sellers.

Financing

As part of the financing for the purchase of the Sanish Field Assets, on December 18, 2015, the Partnership executed the Seller Note in favor of the Sellers in the original principal amount of $97.5 million. The Seller Note bears interest at 5% per annum and is payable in full no later than September 30, 2016 (“Maturity Date”).  Subject to the Partnership’s compliance with the conditions set forth in the Seller Note, the Partnership shall have the right to extend the Maturity Date to March 31, 2017.  The Partnership’s right to extend the Maturity Date is subject to the satisfaction of the following conditions: (i) the Partnership must deliver to Seller written notice of the election to extend the Maturity Date no later than September 1, 2016, (ii) the Partnership must pay to Seller an extension fee equal to 0.5% of the outstanding principal balance outstanding at September 30, 2016,, (iii) during the extension period and until the Seller Note is paid in full, the interest rate on the outstanding principal of the Seller Note shall bear interest at the fixed rate of 7.0% per annum, (iv) the outstanding principal amount of the Seller Note as of September 1, 2016 may not be in excess of $60 million, and (v) both at the time of the delivery of the extension notice and as of September 30, 2016, no event of default shall exist under the Seller Note or any collateral document. There is no penalty for prepayment of the Seller Note. Payment of the Seller Note is secured by a mortgage and liens on all of the Sanish Field Assets in customary form. If the Partnership has not fully repaid all amounts outstanding under the Seller Note on or before June 30, 2016, the Partnership must also pay a deferred origination fee in an amount equal to $250,000.

Interest is due monthly on the last day of each month while the Seller Note remains outstanding. In addition to interest payments on the outstanding principal balance of the Seller Note, the Partnership must make mandatory principal payments monthly in an amount equal to 75% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the Seller Note is reduced to $60 million and 50% of the net proceeds the Partnership receives from the sale of its equity securities thereafter, until the Seller Note is paid in full. In addition, if the Partnership sells any of the property that is collateral for the Seller Note, the Partnership must make a mandatory principal payment equal to 100% of the net proceeds of such sale until the principal amount of the Seller Note is paid in full.

As of December 31, 2015, the outstanding balance on the Seller Note was $85.0 million.

Management Agreement

At the initial closing of the sale of common units, August 19, 2015, the Partnership entered into the Management Agreement with the Former Manager to provide management and operating services regarding substantially all aspects of the Partnership.  The Former Manager provided management and other services to the Partnership under direction of the General Partner as provided in the Management Agreement until the Management Agreement was terminated on April 5, 2016. See Note 8 titled “Management Agreement” in our 2015 financial statements for a description of the Management Agreement and the Former Manager.

Results of Operations

The Partnership closed its minimum offering on August 19, 2015.  The Partnership closed on its purchase of the Sanish Field Assets on December 18, 2015. As a result, the Partnership had less than two weeks of operations of those properties. Other than the payment of fees and expenses described herein, the Partnership had no other operations. Because the Partnership had no revenues in fiscal 2014, there is no comparison of our results of operations for the year ended December 31, 2015 to any of our results of operations for the year ended December 31, 2014, except as otherwise indicated below.

Oil, Natural Gas and NGL Sales

For the 14 days from December 18, 2015 to December 31, 2015, oil, natural gas and NGL sales were $703,806. The sale of crude oil was $661,769, which resulted in a realized price of $30.17 per BOE. The sale of natural gas was $27,000, which resulted in a realized price of $1.47 per MCF. The sale of NGLs was $15,037, which resulted in a realized price of $5.29 per BOE of production.

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The oil, natural gas and NGL production resulted from the Partnership’s acquisition of producing properties in the Sanish Field in North Dakota and the associated horizontal wells on that leasehold. 

Operating Costs and Expenses

Lease Operating Expenses (LOE)

For the 14 days from December 18, 2015 to December 31, 2015, LOE was $149,072. LOE costs per BOE of production were $5.35.

Gathering and Processing Expenses

For the 14 days from December 18, 2015 to December 31, 2015, gathering and processing fees were $16,689. Gathering and processing costs per BOE of production were $0.60.

From time to time, operations will be incurred on a producing well to restore or increase production. For the 14 days from December 18, 2015 to December 31, 2015, workover expenses were $1,450. Workover expenses per BOE of production were $0.05.

Production Taxes

North Dakota’s oil and gas tax structure is comprised of two main taxes: the production tax and the extraction tax. The extraction tax rate was 6.5% of the gross value until December 31, 2015. Beginning January 1, 2016, the extraction tax rate decreased to 5% of the gross value at the well. This rate can increase to 6% if the high-price trigger is in effect. The production tax is 5%.

Our production taxes for the 14 days from December 18, 2015 to December 31, 2015 were $74,460. Production taxes per BOE of production were $2.67.

Depreciation, Depletion and Amortization (DD&A)

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves.  Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves.  Our DD&A for the 14 days of production from December 18, 2015 to December 31, 2015 was $392,084.

Management Fees

Fees incurred under the management agreement with the Former Manager for the year ended December 31, 2015 were $252,524.

Acquisition Costs

Costs related to the acquisition of the Sanish Field assets for the year ended December 31, 2015 were $313,366. These costs include legal, accounting and due diligence associated with the purchase.

General and Administrative Costs

General and administrative costs for the year ended December 31, 2015 were $745,884 and include primarily accounting and legal fees, consulting fees and cost reimbursements to our Former Manager.  For the year ended December 31, 2014, we incurred general and administrative expenses of $163,595.

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Related Parties

The Partnership has, and is expected to continue to engage in, significant transactions with related parties.  These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties.  The General Partner’s Board of Directors oversee and review the Partnership’s related party relationships and are required to approve any significant modifications, as well as any new significant related party transactions.

See further discussion in Note 7 titled “Related Parties” in our 2015 financial statements below.

Partners Equity

At inception the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership.  Upon closing of the minimum offering (i) the organizational limited partner withdrew its initial capital contribution of $990, and (ii) the General Partner received Incentive Distribution Rights (defined below). The General Partner has been and will continue to be reimbursed for its documented third party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

As of August 19, 2015, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit.  As of December 31, 2015, the Partnership had completed the sale of a total of 4,486,625 common units at $19.00 per common unit for total gross proceeds of $85.2 million and proceeds net of offering costs including selling commissions and marketing expenses of $78.3 million. On March 4, 2016, the Partnership had received subscriptions for all 5,263,158 common units that the Partnership was offering at $19.00 per common unit. The Partnership is continuing the offering of the remaining common units at $20.00 per common unit in accordance with this prospectus. As of April 28, 2016, we had completed the sale of a total of 5,863,622 common units for total gross proceeds of $112.0 million and proceeds net of selling commissions and marketing expenses of $105.3 million. The Partnership will offer common units until January 22, 2017, unless the offering is extended by the General Partner, provided that the offering will be terminated if all of the common units are sold before then.

The Partnership intends to continue to raise capital through its “best-efforts” offering of common units by David Lerner Associates, Inc. (the “Managing Dealer”). Under the agreement with the Managing Dealer, the Managing Dealer will receive a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold.  The Managing Dealer will also be paid a contingent incentive fee which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold.  The General Partner received Incentive Distribution Rights (defined below), and has been and will be reimbursed for its documented third party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

Distributions

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or with respect to class B units and will not make any contingent, incentive payments to the Managing Dealer, until Payout occurs.

The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the units equals $20.00 plus the Payout Accrual.  The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount per unit outstanding from time to time.  The Partnership Agreement defines Net Investment Amount initially as $20.00 per Unit, regardless of the amount paid for the Unit.  If at any time the Partnership distributes to holders of units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of our assets, will be made as follows (assuming the cancellation and no reissuance of 37,500 of the class B units issued to an affiliate of the Former Manager):

· First, 35% to the holders of the incentive distribution rights, 21.875% to the holders of the class B units, 13.125% to the holders of the common units, and 30% to the dealer manager under the dealer manager agreement as its contingent, incentive fee until the dealer manager receives fees equal to 4% of the gross proceeds of the offering of common units; and then

· Thereafter, 35% to the holders of the incentive distribution rights, 21.875% to the holders of the class B units and 43.125% to the holders of common units.

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All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the year ended December 31, 2015, the Partnership paid distributions of $0.510138 per unit or $1,271,730.

Since distributions to date have been funded with proceeds from the offering of units, the Partnership’s ability to maintain its current intended rate of distribution will be based on its ability to generate cash from operations resulting from its acquisitions.  In addition, a significant portion of the proceeds from the sale of units during 2015 will be applied to the repayment of the outstanding principal amount of the indebtedness under the Seller Note, leaving less sums available for distribution to unitholders. As there can be no assurance of the Partnership’s ability to produce income at this level, there can be no assurance as to the classification or duration of distributions at the current rate.  Proceeds of the offering which are distributed are not available for investment in properties.

Liquidity and Capital Resources

The Partnership’s principal source of liquidity will be the proceeds of the “best-efforts” offering and the cash flow generated from properties the Partnership has acquired.  In addition, the Partnership may borrow additional funds to pay operating expenses, distributions, make acquisitions or for other capital needs of the Partnership. In connection with the acquisition of the Sanish Field Assets, the Partnership executed the Seller Note in the original principal amount of $97,500,000. The Partnership intends to use proceeds from the offering to repay the Seller Note and its contingent payment and deferred payment obligations. As a result, until the Seller Note is repaid, the Partnership may not have available liquidity to fund additional acquisitions, capital improvements or distributions.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

Our critical accounting policies are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates. We believe that the following are the critical accounting policies used in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil andnatural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

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The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

Impairment

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Independent reserve engineers prepare our reserve estimates at the end of each year.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense. Our reserves are also the basis of our supplemental oil and natural gas disclosures.

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Accounting for Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

Revenue Recognition

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

There are two principal accounting practices to account for natural gas imbalances. These methods differ as to whether revenue is recognized based on the actual sale of natural gas (sales method) or an owner’s entitled share of the current period’s production (entitlement method). We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies, in the footnotes to our 2015 financial statements for a summary of recent accounting standards.

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MANAGEMENT

The Partnership will have no officers, directors or employees.  Instead, the general partner will manage the day to day affairs of the Partnership. Substantially all of our properties are currently being operated by Whiting Petroleum Corporation, an independent third party (“Whiting”). Since we own a 100% non-operating interest in our assets, most of the services that the Former Manager had been contracted to perform are being performed by Whiting, as operator of those properties.

The general partner will have full authority to conduct and manage our business, including the following:

· The acquisition, development, operation and disposition of oil and gas properties and other assets by our Partnership;

· The making of all expenditures by the Partnership;

· The making of all tax and other regulatory filings by the Partnership;

· The negotiation, execution and performance of contracts by the Partnership;

· The determination of the amount and timing of distributions to the partners;

· The retention of insurance coverage by the Partnership;

· The control of any matters relating to the Partnership’s rights and obligations, including the bringing and defending of law suits; and

· The acquisition of common units or other interests issued by the Partnership.

All decisions regarding the management of the Partnership made by the general partner will be made by the board of directors of the general partner and its officers.

Directors and Executive Officers of the General Partner

The general partner has a board of directors composed of four individuals.  The directors, executive officers and persons who have agreed to act as an executive officer of the general partner are as follows:

Name	Age	Position
Glade M. Knight	72	Chairman of the Board and Chief Executive Officer
David McKenney	53	Director and Chief Financial Officer and Secretary
Anthony Francis “Chip” Keating III	36	Director and Co-Chief Operating Officer
Michael J. Mallick	53	Director and Co-Chief Operating Officer
Clifford J. Merritt	55	President

Glade M. Knight. Mr. Knight is the founder and Chairman of Apple Hospitality REIT, Inc. and Chairman and Chief Executive Officer of Apple REIT Ten, Inc., each of which is a real estate investment trust, or REIT. Mr. Knight was the Chairman of the Board and Chief Executive Officer of Apple Hospitality Two, Inc., a lodging REIT, from 2001 until the company was sold to an affiliate of ING Clarion in May of 2007. Mr. Knight served in the same capacity for Apple Hospitality Five, Inc., another lodging REIT, from 2002 until the company was sold to Inland American Real Estate Trust, Inc. in October of 2007 and Apple REIT Six, Inc. from 2004 until the company was sold to BRE Select Hotels Corp in May of 2013.  In addition, Mr. Knight served as Chairman and Chief Executive Officer of Cornerstone Realty Income Trust, Inc. until it merged with a subsidiary of Colonial Properties Trust in 2005. Following the merger in 2005 until April of 2011, Mr. Knight served as a trustee of Colonial Properties Trust. Cornerstone Realty Income Trust, Inc. owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. Apple Hospitality REIT, Inc. and Apple REIT Ten, Inc. each own hotels in selected metropolitan areas of the United States. Mr. Knight is Chairman of the Board of Trustees of Southern Virginia University in Buena Vista, Virginia. He also is a member of the Advisory Board to the Graduate School of Real Estate and Urban Land Development at Virginia Commonwealth University. He has served on a National Advisory Council for Brigham Young University and is a founding member of the university’s Entrepreneurial Department of the Graduate School of Business Management.

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David McKenney. Mr. McKenney serves as Senior Advisor for Apple Hospitality REIT, Inc. and President of Capital Markets of Apple REIT Ten, Inc., each of which is a real estate investment trust. Mr. McKenney previously served as President of Capital Markets for Apple Hospitality REIT, Inc.  Mr. McKenney was President of Capital Markets of Apple Hospitality Two, Inc., a lodging REIT, from 2001 until the company was sold to an affiliate of ING Clarion in May of 2007. Mr. McKenney served in the same capacity for Apple Hospitality Five, Inc., another lodging REIT, from 2002 until the company was sold to Inland American Real Estate Trust, Inc. in October of 2007 and Apple REIT Six, Inc. from 2004 until the company was sold to BRE Select Hotels Corp in May of 2013. From 1994 to 2001, Mr. McKenney served as Senior Vice President and Treasurer of Cornerstone Realty Income Trust, Inc., a REIT that owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. From 1992 to 1994, Mr. McKenney served as Chief Financial Officer for The Henry A. Long Company, a regional development firm located in Washington, D.C. From 1988 to 1992, Mr. McKenney served as a Controller at Bozzuto & Associates, a regional developer of apartments and condominiums in the Washington, D.C. area. Mr. McKenney holds Bachelor of Science degrees in Accounting and Management Information Systems from James Madison University.

Anthony Francis “Chip” Keating III . Mr. Keating has been a principal with Rock Creek Capital, a real estate and oil and gas investment company, since March 2010. He currently serves on the boards of Apple REIT Ten, Inc., The Children’s Hospital Foundation and The Salvation Army.  Mr. Keating is also a Director and Gubernatorial appointee of The Oklahoma Law Enforcement Retirement System by Governor Mary Fallin, and a director of Leadership Oklahoma City, The Downtown Club of Oklahoma City and International Council of Shopping Centers.  Prior to founding Rock Creek Capital, Mr. Keating served as the Real Estate Development Manager for Chesapeake Energy Corporation in Oklahoma City, Oklahoma from March 2007 to March 2010.  While at Chesapeake, Mr. Keating closed and transacted over $850 million in real estate transactions ranging from corporate headquarters, sale leasebacks, field offices, investment properties and raw land in urban natural gas plays for drill sites.  Prior to joining Chesapeake, Mr. Keating worked as a commercial real estate broker with Trammell Crow Company from August 2004 to March 2007.  While at Trammell Crow Company, he specialized in tenant representation and investment sales.  Before joining Trammell Crow Company, he spent just over three years as an Oklahoma State Trooper from May 2001 to August 2004. Mr. Keating received a Bachelor of Business Administration from Southern Methodist University.

Michael J. Mallick. Mr. Mallick is the founder of Fort Worth, Texas-based Mallick Group, Inc., a real estate and energy related investment firm.  Mr. Mallick is a principal investor in various entities and serves as the principal officer of sponsoring and managing partners for numerous and diverse real estate investments and energy related interests funded with established co-investment relationships with high net worth private investors, institutional investors and lenders. Mr. Mallick’s varied experience includes development of the 349 room Horseshoe Bay Marriot Resort Hotel, located in Horseshoe Bay, Texas (financed with a national pension fund); Sierra Vista, a redevelopment initiative in a public/private partnership with the City of Fort Worth, Texas, including the assemblage and acquisition of approximately 300 acres located within a concentration of blight inside the central city and resulting in environmental remediation and demolition of 1,000 crime ridden apartment units and new quality affordable housing and shopping; and acquisition of a large multi-property portfolio of properties financed via a structured private placement offering with multiple institutional investors.

Clifford J. Merritt. Mr. Merritt was appointed as President on December 18, 2015. Mr. Merritt has been a consultant to us since July 1, 2014, and to other private exploration and development companies since November 2013. Prior to that time and since 2004 he was employed by Chesapeake Energy Corporation. From 2010 to 2013 he served as Chesapeake’s Vice President Land – Southern Division and from 2005 to 2010 as Chesapeake’s Land Manager – Barnett Shale District. Before joining Chesapeake he worked for Okland Oil, Ricks Exploration and Concho Resources during the years of 1990 through 2003, each of which is an independent oil and gas company. He has a B.B. A. from the University of Central Oklahoma and is a member of OCAPL (Oklahoma City Association of Professional Landmen) and AAPL (American Association of Professional Landmen). During his career Mr. Merritt has been involved and managed the Land functions of numerous acquisitions and divestitures of oil and gas properties and supervised the drilling and completion of over 2000 oil and gas wells throughout multiple states in the continental US.

The general partner anticipates that it will identify and hire a controller who will be responsible for preparation of the Partnership’s financial statements.  Depending on the amount of common units sold by the Partnership, the general partner anticipates that it will identify and hire additional personnel to manage the Partnership’s business.

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Executive Compensation

 Summary Compensation

The following table summarizes, with respect to each of the Chief Executive Officer and the two other most highly compensated officers of our General Partner (the “Named Executive Officers”), information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2015, 2014 and 2013. Since the only person being paid any compensation by the Partnership or the General Partner is Mr. Merritt, the Named Executive Officers only include Mr. Knight, our Chief Executive Officer, and Mr. Merritt.

						All Other
Name and Principal Position:	Year	Salary		Bonus		Compensation		Total
Glade M. Knight	2015	$	—	$	—	$	—	$	—
Chairman of the Board and Chief Executive Officer	2014	$	—	$	—	$	—	$	—
	2013	$	—	$	—	$	—	$	—
Clifford J. Merritt	2015	$	222,009	$	—	$	—	$	222,009
President

We do not directly employ any of the persons responsible for managing our business. Instead, our General Partner manages our day to day affairs. The owners of our General Partner will be reimbursed for documented out-of-pocket travel, entertainment and similar expenses incurred by them in connection with attending board of directors meetings or managing the Partnership’s business. The owners of the General Partner will not receive any salary, bonus or consulting fees for serving on the board of directors or managing the Partnership’s business other than distributions in accordance with the incentive distribution rights, if any.

Prior to being appointed President Mr. Merritt provided consulting services to the General Partner. The General Partner has agreed to pay Mr. Merritt base compensation of $300,000, basic health insurance benefits, which will be paid or reimbursed to the General Partner by the Partnership and a 5% interest in the General Partner’s incentive distribution rights.

Outstanding Equity Awards at Fiscal Year-End

There were no outstanding equity awards for our named executive officers as of December 31, 2015, other than the Incentive Distribution Rights.

Compensation of Directors

The employee and non-employee members of the General Partner’s board of directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending board meetings.

Reimbursement of Expenses to General Partner in Connection with Offering Costs

Our Partnership Agreement provides that the General Partner is entitled to be reimbursed out of capital contributions for offering and organization costs paid to third parties, including legal, accounting, engineering, printing and filing fees. During the year ended December 31, 2015, Apple Suites Realty Group an affiliate of GKOG, LLC, was reimbursed $1,544,372 and Pope Energy Investors, LP was reimbursed $209,783 in 2015 for offering and organizational costs paid by such members of the General Partner.

Reimbursement of Expenses to General Partner in Connection with Operations of the Partnership

The Partnership will also reimburse the General Partner and the General Partner’s affiliates for their General and administrative costs allocable to the Partnership. These expenses will include compensation expense, rent, travel, and other general and administrative and overhead expenses. Currently, the only business of the General Partner is to act as General Partner of the Partnership, and all of the General Partner’s general and administrative costs will be paid by the Partnership. If affiliates of the General Partner form other partnerships or engage in other oil and gas activities, the General Partner will allocate its general and administrative costs to the Partnership and other partnerships or businesses in a manner deemed reasonable by the General Partner. During the year ended December 31, 2015, approximately $62,000 of related party costs were incurred by the General Partner and reimbursed by us in connection with our operations.

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Director Independence

Because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our Board of Directors has not made any determination as to whether the non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

Ownership of Our General Partner

Our general partner is a limited liability company. The members of our general partner and the membership interest owned are as follows:

· GKOG, LLC, owns a 25% membership interest in our general partner.  GKOG, LLC is a limited liability company owned by Mr. Knight

· DMOG, LLC owns a 25% membership interest in our general partner.  DMOG, LLC is a limited liability company wholly owned by Mr. McKenney.

· CFK Energy, LLC owns a 25% membership interest in our general partner.  CFK Energy, LLC is a limited liability company owned by Mr. Keating and his immediate family.

· Pope Energy Investors, LP, a limited partnership, owns a 25% membership interest in our general partner.  The general partner and the limited partner interests of Pope Energy Investors, LP are owned by Mr. Mallick and his immediate family.

The owners of our general partner will be reimbursed for documented out-of-pocket travel, entertainment and similar expenses incurred by them in connection with attending board of directors meetings or managing the Partnership’s business.  The owners of the general partner will not receive any salary, bonus or consulting fees for serving on the board of directors or managing the Partnership’s business other than distributions in accordance with the incentive distribution rights, if any.

 Each member of our general partner has the right to appoint one person to the general partner’s board of directors.  All decisions regarding the business of our general partner and our Partnership will be made by the board of directors of our general partner at meetings of the board of directors at which a quorum is present.  The presence of a majority of the directors constitutes a quorum, and the vote of a majority of a quorum constitutes a decision by the board of directors.

The owners of the members of our general partner have granted each other the right of first refusal to acquire any interests in the members of our general partner that the owners propose to sell.  If the owners of the members of our general partner do not exercise the right of first refusal, the purchaser of the owner of our general partner will have the right to appoint a member to our board of directors, and if a person or group of affiliated persons were to acquire a controlling interest in three of the owners of our general partner, the person would be able to control our general partner and the Partnership.  Our Partnership Agreement does not give the holders of common units the right to cause an owner of our general partner to exercise its buy-sell right, or provide the holders the right to consent to or otherwise approve the transfer by an owner of our general partner of its membership interest in our general partner.  Our general partner does, however, agree not to permit a change of control of our general partner to occur.  A change of control is defined as a person who is not currently a beneficial owner of our general partner or a “qualifying owner” becoming the beneficial owner of 50% or more of the membership interest in our general partner.  A qualifying owner generally is defined as the following with respect to the current beneficial owners of our general partner:  conservators, guardians, executors, administrators, and similar persons of any trust, private foundation or custodianship that such beneficial owner, his spouse, lineal descendants or estate is a beneficiary.

Prior Real Estate Programs

Mr. Knight was responsible for the formation of real estate investment trusts, or REITs, under the name “Apple REITs” and Mr. McKenny was an executive officer of the Apple REITs.  In addition, Mr. Knight formed and owned the companies that acted as advisors to each of the Apple REITs (“Advisory Companies”).  Also, Mr. Keating serves on the board of directors of Apple REIT Ten, Inc. Each of the Apple REITs was formed to invest in income producing real estate with the objective of maintaining a relatively stable distribution rate over the life of the investment, instead of raising and lowering the distribution rate with varying economic cycles. Because of varying economic cycles and operating performance, the Apple REITs paid distributions in excess of operating cash flow in certain periods and used financing proceeds, offering proceeds or other resources to fund distributions.  The Apple REITS also periodically adjusted their distribution rates relative to the performance of the real estate owned. The following is further information regarding the formation and activities of the Apple REITs formed during the last 10 years.

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Apple REIT Six, Inc. (“Apple REIT Six”)

Mr. Knight was responsible for the organization of Apple REIT Six, a real estate investment trust formed to acquire and own hotels, residential apartment communities and other property in selected metropolitan areas. Mr. Knight was the chairman and chief executive officer of Apple REIT Six and owned its Advisory Company, and Mr. McKenney was the President of Capital Markets.  From 2004 to 2006, Apple REIT Six sold approximately $1 billion in units in its best-efforts offering at prices of $10.50 and $11.00 per share.  The net proceeds of the Apple REIT Six offering were used to acquire 68 hotels in select metropolitan areas in the United States, with an aggregate purchase price of approximately $870 million.  In May 2013, Apple REIT Six, was acquired by BRE Select Hotels Corp. (“BRE Select Hotels”), an affiliate of Blackstone Real Estate Partners VII, L.P.  Pursuant to the acquisition, each outstanding unit of Apple REIT Six was converted into the right to receive (i) $9.20 in cash, without interest, and (ii) one share of 7% Series A Cumulative Redeemable Preferred Stock of BRE Select Hotels with an initial liquidation preference of $1.90 per share.  The initial liquidation preference of $1.90 per share will be subject to downward adjustment should net costs and payments relating to certain legacy litigation and regulatory matters affecting Apple REIT Six exceed $3.5 million.  No downward adjustment to the liquidation preference has been made.

Apple REIT Seven, Inc. (“Apple REIT Seven”)

Mr. Knight was responsible for the organization of Apple REIT Seven, a real estate investment trust formed to acquire and own hotels, residential apartment communities and other property in selected metropolitan areas.  Mr. Knight was the chairman and chief executive officer of Apple REIT Seven and owned its Advisory Company, and Mr. McKenney was the President of Capital Markets.  During 2006 and 2007, Apple REIT Seven sold approximately $1 billion in units in a best-efforts offering.  The net proceeds of the Apple REIT Seven offering were used to acquire 51 hotels in select metropolitan areas in the United States, with an aggregate purchase price of approximately $933 million.

Apple REIT Eight, Inc. (“Apple REIT Eight”)

Mr. Knight was responsible for the organization of Apple REIT Eight, a real estate investment trust formed to acquire and own hotels, residential apartment communities and other property in selected metropolitan areas.  Mr. Knight was the chairman and chief executive officer of Apple REIT Eight and owned its Advisory Company, and Mr. McKenney was the President of Capital Markets.  During 2007 and 2008, Apple REIT Eight sold approximately $1 billion in units in a best-efforts offering.  The net proceeds of the Apple REIT Eight public offering have been used to acquire 51 hotels in select metropolitan areas in the United States, with an aggregate purchase price of approximately $990 million.

Apple Hospitality REIT, Inc. (“Apple REIT Nine”)

Mr. Knight was responsible for the organization of Apple REIT Nine, a real estate investment trust formed to acquire and own hotels, residential apartment communities and other property in selected metropolitan areas.  Mr. Knight was the chairman and chief executive officer of Apple REIT Nine and owned its Advisory Company, and Mr. McKenney was the President of Capital Markets.  During 2008, 2009 and 2010, Apple REIT Nine sold approximately $2 billion in units in a best-efforts offering.  The net proceeds of the Apple REIT Nine public offering were used to acquire 89 hotels through December 31, 2012 in select metropolitan areas in the United States, with an aggregate purchase price of approximately $1.5 billion.

On April 27, 2012, a subsidiary of Apple REIT Nine closed a sale transaction for 110 parcels of land located in the Ft. Worth, Texas area to 111 Realty Investors, LP, an entity controlled by Mr. Mallick and Mr. Keating, for $198.4 million.  Prior to the sale, the land was leased by Apple REIT Nine to a third party.

Merger of Apple REIT Seven, Apple REIT Eight and Apple REIT Nine

In March 2014, Apple REIT Seven and Apple REIT Eight merged into Apple REIT Nine, and the name of Apple REIT Nine was changed to Apple Hospitality REIT, Inc.  In connection with completion of the mergers, Apple REIT Nine became a self-advised REIT and the existing advisory agreements between Apple REIT Nine, Apple REIT Eight and Apple REIT Seven and their advisors were terminated.

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Apple REIT Ten, Inc. (“Apple REIT Ten”)

Mr. Knight was responsible for the organization of Apple REIT Ten, a real estate investment trust formed to acquire and own hotels and other property in selected metropolitan areas.  Mr. Knight is the chairman and chief executive officer of Apple REIT Ten and owns its Advisory Company, and Mr. McKenney is the President of Capital Markets.  Mr. Keating serves on the board of directors of Apple REIT Ten.  Beginning on January 19, 2011, and through March 31, 2014, Apple REIT Ten sold approximately $938.5 million in units in a best-efforts offering.  As of March 31, 2014, the net proceeds of the Apple REIT Ten public offering had been used to acquire 49 hotels in select metropolitan areas in the United States, with an aggregate purchase price of approximately $830 million.

Settlement with the SEC

On February 12, 2014, the SEC and the Apple REITs settled an SEC investigation that focused principally on the adequacy of certain disclosures by certain of the Apple REITs in its filings with the SEC.  Each of the Apple REITs and their Advisory companies (which were wholly-owned by Mr. Knight) agreed to the settlement.  To effectuate the settlement, and without admitting or denying any allegations, certain of the Apple REITs consented to the issuance of an administrative order alleging deficiencies related to the disclosure of the process used to price shares sold in the dividend reinvestment plans sponsored by the Apple REITs, disclosure of compensation paid to executives by the Advisory Companies, and disclosure of transactions among the Apple REITs.  

The order provides that based on the foregoing alleged disclosure deficiencies, Apple REIT Six, Apple REIT Seven and Apple REIT Eight violated Sections 17(a)(2) and 17(a)(3) of the Securities Act of 1933 and certain of the Apple REITs violated Sections 13(a), 13(b)(2)(A), 13(b)(2)(B) and 14(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) and Rules 12b-20, 13a-1, 13a- 13 and 14a-9 thereunder.  The order requires certain of the Apple REITs to cease and desist from committing or causing any such violations in the future, but does not require the Apple REITs to pay a financial penalty.

Certain of the Advisory Companies and Mr. Knight, without admitting or denying any allegations, also consented to the issuance of the order alleging that, based on the alleged disclosure deficiencies described above, they were a cause of the Apple REITs’ violations of Sections 13(a), 13(b)(2)(A), 13(b)(2)(B), 14(a) of the Exchange Act and Rules 12b-20, 13a-1, 13a-13 and 14a-9 thereunder.  In addition, the order provides that Mr. Knight violated Section 16(a) of the Exchange Act and Rule 16a-3 thereunder based on Mr. Knight’s alleged failure to file timely with the SEC one Form 3 and one Form 4.  Further, the order provides that Mr. Knight violated Rule 13a-14 of the Exchange Act based on the officer certification he provided in his role as Chief Executive Officer for certain of the Apple REITs.  Finally, to settle the proceedings, the Advisory Company to Apple REIT Six agreed to pay a penalty of $437,500, the Advisory Company to Apple REIT Seven agreed to pay a penalty of $375,000, and the Advisory Company to Apple REIT Eight agreed to pay a penalty of $437,500, the Advisory Company to Apple REIT Nine agreed to pay a penalty of $250,000 and Mr. Knight agreed to pay a penalty of $125,000.

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ALTERNATIVE INVESTMENTS

Financial planners generally recommend that investors hold a diversified investment portfolio, including traditional investments, such as stocks, bonds and mutual funds, and alternative investments. The objective of this strategy is to reduce the overall portfolio risk and volatility of an investor’s wealth portfolio while achieving acceptable rates of return.

An investment in an oil and natural gas partnership may be regarded as an alternative investment. The appropriate proportion of an investor’s wealth portfolio that should be held in alternative investments will vary from investor to investor. You should consult your financial advisor regarding asset allocation strategies.

As a wealth management strategy, oil and natural gas partnerships may be appropriate for certain investors for reasons that include:

· Portfolio diversification. An investment in an oil and natural gas partnership may provide diversification between alternative and other forms of investments. It may also provide diversification among your alternative investments.

· Cash distributions. Oil and natural gas partnerships may generate cash distributions.

· Tax advantages. Oil and natural gas partnerships may provide tax benefits for some investors compared with ownership of oil and gas properties in a corporation. See “Federal Income Tax Consequences.”

· Potential for capital growth. Oil and natural gas partnerships may offer the potential for the growth of invested capital as the result of reinvesting the production proceeds from earlier wells to compound the return achieved from such earlier wells.

· Potential inflation hedge. The price of oil and natural gas will typically rise in conjunction with higher inflation, which can benefit partnerships that acquire producing properties before the beginning of inflationary periods.

The Partnership expects to exhibit some or all of the characteristics described above. Before considering any investment in the common units, you should first consult with your financial advisor and read and understand this prospectus, including the section entitled “Risk Factors.” You must also meet the suitability standards as set out in this prospectus. See “Suitability Standards.”

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PROPOSED ACTIVITIES

We are a Delaware limited partnership recently formed to acquire and develop 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 oil and gas properties.  On December 18, 2015, we acquired an 11% working interest in approximately 215 existing producing wells and approximately 262 future development locations in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). We have not identified any additional oil and gas properties that we will acquire and we do not know whether we will be able to acquire any additional assets.

Our Investment Objectives

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

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

· to make distributions to our partners;

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

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

We are the first oil and gas partnership formed by our general partner and its affiliates.  There can be no assurances that we will be able to attain our investment objectives.

Oil and Gas Properties Acquired

On December 18, 2015, we acquired the Sanish Field Assets. The purchase price for the Sanish Field Assets consisted of (i) $60 million in cash, subject to customary adjustments, (ii) an aggregate of $2 million, payable in equal amounts on December 31, 2016 and December 31, 2017, (iii) a promissory note in the amount of $97.5 million payable to Sellers (the “Seller Note”) and (iv) a contingent payment of up to $95 million.  See “Ongoing Operations.” Whiting Petroleum Corporation (“Whiting”), a publicly traded oil and gas company, is the operator of our properties on behalf of us and the other working interest owners in those properties.

Description of the Properties We Plan to Purchase

General

We intend to target for acquisition and development producing and non-producing oil and gas properties that we expect will require additional drilling activities to develop their full potential.  Our partnership is a “blind pool” which means that we had not identified any properties for acquisition prior to commencing the offering. Also, our Partnership Agreement does not require that we invest in producing or non-producing properties in a particular ratio, or spend a certain percentage of our available capital to acquire producing or non-producing properties.  As a result, substantially all of the properties we acquire may be producing properties or properties that require additional operations to develop reserves, or any combination of producing and non-producing properties.  Factors that will affect our decision to acquire producing properties or non-producing properties include the current and anticipated future economic conditions at the time we have funds available for acquisition, our evaluation of the desirability of properties available for acquisition at the time we have funds available, the amount of funds available for acquisition and the Partnership’s ability to diversify its portfolio, and the availability and cost of drilling rigs and other equipment necessary to develop non-producing properties.

When we acquire a property, we will estimate the capital required to develop the property, and plan to use a portion of any borrowing capacity or other funds available to us, to fund all or a substantial portion of these estimated costs of development.  During our first five years of operations we also plan to use a substantial portion of our available cash flows to develop our properties.

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We do not expect to conduct a material amount of exploitation activities on properties that are not located in or adjacent to producing properties.  In addition, although we do not intend to acquire gathering systems, pipelines, treatment facilities, processing plants and other infrastructure, except in connection with the oil and gas properties we acquire, we have the right to acquire gathering systems, pipelines, treatment facilities, processing plants and other infrastructure, not associated with our producing properties and assets used in the upstream energy business, so long as the amount of such investments, in the aggregate, does not exceed 20% of the purchase price of common units we issue.

The remainder of this section describes the parameters that our general partner will use in selecting the oil and gas properties we acquire.  Unless otherwise indicated, our general partner may acquire oil and gas properties that do not meet the all or some of parameters listed below.  Our Partnership Agreement provides that our general partner will not have any liability to our partners so long as the general partner makes its decisions in good faith, including a decision to acquire a property which does not meet the parameters below.

Onshore Properties Located in the United States

Our Partnership Agreement provides that any properties we acquire will be located onshore in the United States.  Ownership of oil and gas properties located offshore present unique operational risks; such as lengthy interruption of production from hurricanes and increased costs and risks associated with environmental compliance, which our general partner believes are not appropriate for a partnership that seeks to make cash distributions to its partners.  Properties located outside the United States may present title and other ownership issues, and may have adverse tax consequences, that our general partner does not believe our Partnership should be exposed to.  In addition, the risks associated with properties located outside the United States or offshore in the United States require additional insurance, which our general partner does not plan to acquire for our Partnership.

The requirement to acquire only properties located onshore in the United States may not be changed or waived by the general partner without amending our Partnership Agreement, which would require the approval of holders of a majority of our common units, including common units held by the general partner and its affiliates.

Oil and Gas Properties

The general partner will target for our acquisition producing and non-producing properties that it believes are suitable for our ownership and development.  These properties are expected to be in areas of known hydrocarbon production with reasonably predictable drilling and production results.

Our general partner will have considerable discretion in determining the parameters it will use to evaluate and acquire producing and non-producing properties which will require the general partner to determine the following parameters, among others:

· The applicable discount rate to use in calculating present value of reserves.  In determining the present value of our properties for use in preparing our financial statements, the SEC requires us to use a 10% discount rate.  However, a 10% rate is not necessarily appropriate for evaluating a property for acquisition, and our general partner may decide to use a greater or lesser discount rate in making this calculation based on prevailing interest rates, the perceived risk associated with production of the reserves, perceptions of volatility of future prices, the discount rates our general partner determines are being use generally in the oil and gas business to acquire reserves, and other factors.

· The prices that are assumed to be received for future production.  In order to calculate present value, our general partner will make assumptions regarding the prices at which we will sell production in the future.  In preparing present value estimates of oil and gas reserves in our financial statements, we will be required to use the unweighted average of the prices on the first day of each of the 12 months prior to the date of determination, with appropriate adjustment for the location and quality of the reserves.  The general partner may use different assumptions, such as the prices quoted in the futures market (the “forward curve”) or other prices.

· The costs, including capital costs, required to develop and produce the reserves.  The general partner also will be required to estimate the production costs to be incurred in the future to produce the reserves, including the capital costs we will spend to drill wells and conduct additional development activities.

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· The future production rates.  In order to calculate present value of reserves, the rate at which properties we propose to acquire will produce oil, gas and natural gas liquids must be estimated.  These estimates will be made for us by reservoir engineers using methodology customary in the oil and gas industry.  The reserve engineers may be in-house engineers employed by our general partner or independent third party engineers selected by our general partner.

In making the various assumptions necessary to calculate the discounted present value of estimated net proved reserves, our general partner will be required to act in good faith.  Our Partnership Agreement provides that so long as our general partner acts in good faith in making the various assumptions, our general partner will have no liability to us or our partners.

Drilling

We expect that the properties we acquire will require that we drill wells and conduct other activities to fully develop the potential of the properties.  Some of the drilling activities are expected to be on locations to which proved reserves have not been assigned, and such drilling activities will be classified as exploration drilling.  However, the general partner expects to acquire properties located adjacent to or in the vicinity of producing properties, and with geological characteristics similar to productive properties in the area.  While this will reduce the risk of exploration drilling, it will not eliminate the risk.

When we acquire an oil and gas property, we will estimate the costs to drill any wells necessary to fully develop the property, and will use a portion of any available borrowings under our credit facility or other amounts available to use that the general partner determines is required to pay for drilling the wells.  We also expect to use a portion of our available cash from operations to drill wells on and otherwise develop our properties.

If the Partnership has the opportunity to participate in wells, the general partner also may decide to sell or farmout the well. Also, if a well is proposed under an operating agreement for one of the properties we own, the general partner may cause us to “non-consent” the well under the applicable operating agreement.  Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well.

If the general partner makes the decision to sell, farmout or non-consent a well or other activity, our Partnership Agreement provides that the general partner will have no liability to us so long as the decision is made in good faith.

Infrastructure

In connection with the acquisition and development of producing oil and gas properties, we may acquire interests in gathering systems, treatment facilities, processing plants, pipelines and other oil and gas infrastructure.  Our interest in the infrastructure will generally be similar to our working interest in the producing properties that we acquire.  Although we do not plan to acquire interests in oil and gas infrastructure that are not associated with our oil and gas properties, we have the right to acquire infrastructure not associated with our oil and gas properties as long as the amount of such investments, in the aggregate, does not exceed 20% of the purchase price of common units we issue.

Borrowing Policy

Prior to the maturity date of the Seller Note, we expect to enter into a credit facility with a commercial lender. See “Ongoing Operations—Financing of the 2015 Acquisition.”  We plan to use borrowings under the credit facility to finance a portion of the Seller Note or for subsequent development of our properties. We may also use borrowings under our credit facility to pay distributions.  We expect that the credit facility will provide for borrowings up to a borrowing base that will be set by the lenders under the facility, at their discretion, based in part upon the lenders’ valuation of our reserves.  We also expect that our credit facility will be secured by a mortgage on our properties.  We do not expect the borrowings under our credit facility to exceed 50% of our total capitalization determined on an annual basis.

We have not received a commitment or a term sheet from a lender with respect to a credit facility, and no assurances can be made that we will be able to arrange for a credit facility.  The financial covenants, interest rate, borrowing base and other terms of the credit facility, if any, will be negotiated by the general partner and will be affected by general economic conditions, the amount of capital contributions we receive, the reserves and production attributable to the properties we acquire or have agreed to acquire, oil and gas prices and other factors, many of which are beyond our control. See “Risk Factors – We have not negotiated the terms of our credit facility with lenders.”

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Hedging Policy

Prices for oil and natural gas have been volatile and uncertain for many years. To mitigate our exposure to decreases in prices, we plan to enter into financial hedges through contracts such as regulated NYMEX futures and options contracts and over-the-counter swap contracts with qualified counterparties. The percentages of oil and/or natural gas production that we elect to hedge under the hedging policy may change from time to time at the discretion of our general partner, but in no event will we hedge more than the projected amounts of oil, natural gas or natural gas liquids reasonably expected to be produced from our wells.

Title to Properties

Prior to completing an acquisition of an oil and gas property, we expect to perform title reviews on the most significant interests being acquired.  The properties we acquire are likely to be subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

Holders of common units will be relying on the general partner to use its best judgment of the best interests of the Partnership to obtain appropriate title to properties.  The general partner will perform due diligence, including title review, with respect to the properties to be acquired by the Partnership.  The general partner may also retain separate legal, land and other consultants to review title.  The general partner will take such steps as it deems appropriate to determine that title to a property is appropriate for acquisition by the Partnership.  The general partner may elect to waive apparent or possible defects in title, or may elect not to do a thorough review of title prior to an acquisition.  Provisions in our Partnership Agreement will relieve our general partner for liability for any decision made with respect to waiver of title defects, or mistakes made in review of title, so long as such mistakes were made in good faith.

Environmental Review

As with title, holders of common units will be relying on the general partner to review environmental matters on properties we plan to acquire.  Such review may include a Phase I environmental review of the properties conducted by third party environmental consultants or other environmental review.  The general partner may elect not to conduct a full environmental review of all properties being acquired by the Partnership.  Provisions in our Partnership Agreement will relieve the general partner for liability for any decision made with respect to environmental matters, or mistakes made in review of environmental matters, so long as such mistakes were made in good faith.

Well Operations

We expect that the Operating Agreements that we will enter into will be based on the model form operating agreement issued by the American Association of Petroleum Landmen.  Under the applicable operating agreement for a property, a third-party operator will act as operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest.  As operator, the third-party operator will design and manage the production from and drilling and completion of our wells and manage the day to day operating and maintenance activities for our wells.  The applicable operating agreements will commit the parties to participate in operations on the contracted area and provide a procedure for dealing with disagreements among the parties about what operations will be conducted.  Under these operating agreements, all costs and liabilities incurred in operations under the operating agreement will be borne and paid, and all equipment and materials acquired in operations on the contracted area will be owned, by the parties as per their respective interests.  

Under the applicable operating agreements, a third-party operator will establish a joint account for each well in which we have an interest.  We are required to pay our working interest share of amounts charged to the joint account.  The joint account is charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities.  The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells is done in accordance with the Council of Petroleum Accountants Societies, or COPAS, model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and wells, as well as gathering and other equipment used on our properties.  In addition, direct expenses include the allocable share of the cost of services performed on our properties and wells by a third-party operator.  The allocation of the cost of the third-party operator who perform services on our properties will be based on the applicable provisions of the relevant operating agreement.  Direct expenses charged to the joint account also include an amount determined by the operator to be the fair rental value of facilities owned by the operator and used in the operation of our properties.

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The operating agreements will also contain terms with respect to resolving title issues, the liability of the parties, transfers of interests, tax provisions, and claims and lawsuits.  The operating agreements will provide that title examination will be made prior to the commencement of drilling operations and will provide for the responsibility of the operator and non-operators for title examination and curing any title issues.  The operating agreements will also address the identification and drilling of initial wells and any subsequent wells on the contracted area.  The operating agreements will provide for terms with respect to an election not to participate (non-consent) in a subsequent operation, including relinquishment of interests by non-participating parties, assessment of non-consent risk penalties and recoupment of costs out of production by the participating parties.  The operating agreements will provide for creation of mutual liens and security interests among the parties to secure payment and performance.  The operating agreements will also set forth the allocation of liability with respect to joint operations and provide remedies for a party’s failure to pay its share of expenses. The liability of the parties under the operating agreements will be several, not joint or collective, and each party will be responsible only for its obligations.  The operating agreements will also provide for limits on a party’s rights with respect to transfer and acquisition of interests in the oil and gas leases in the contracted area.  The operating agreements will include an election under §761 of the Code by the parties, as co-owners under the operating agreement, to be excluded from partnership treatment for federal income tax purposes.  The operating agreements will also provide for an upper dollar limit on amounts the operator may spend to settle any claim or lawsuit.

 Ongoing Operations

2015 Acquisition

On September 15, 2015, we entered into an Interest Purchase Agreement by and among Kaiser-Whiting, LLC and the owners of all the limited liability company interests therein (the “Sellers”), for the purchase of the Sanish Field Assets. We completed the purchase transaction on December 18, 2015. Prior to this acquisition, we owned no oil or natural gas assets. The Sanish Field Assets currently constitute all of our oil and gas properties.

The Sanish field is part of the Greater Williston Basin where industry activity is focused on development of the prolific Bakken Shale formation.  Whiting, a publicly traded oil and gas company, operates the assets on behalf of the Partnership and other working interest owners. The Bakken Shale and its close geologic cousin, the Three Forks Shale, are found in the Williston Basin, centered in North Dakota.  The Bakken Shale in the Williston Basin is one of the largest oil fields in the U.S., covering an area of approximately 17,500 square miles. While oil has been produced in North Dakota from the Williston Basin since the 1950s, it is only since 2007 through the application of horizontal drilling and hydraulic fracturing technologies that the Bakken has seen an increase in production activities.

Under the Purchase Agreement, we agreed to pay a cash purchase price for the Sanish Field Assets, consisting of (i) an initial $160 million, payable at closing subject to customary adjustments, (ii) an aggregate of $2 million, payable in equal amounts on December 31, 2016 and December 31, 2017 and (iii) a contingent payment of up to $95 million. The contingent payment was to provide a means for a sharing between the Partnership and the Sellers to the extent the NYMEX current five-year strip oil price for WTI at December 31, 2017 is above $56.61 (with a maximum of $89.00) per Bbl.  The contingent payment will be calculated as follows: if on December 31, 2017 the average of the monthly NYMEX:CL strip prices for future contracts during the delivery period beginning December 31, 2017 and ending December 31, 2022 (the “Measurement Date Average Price”) is greater than $56.61, then the Sellers will be entitled to a contingent payment equal to (a) (i) the lesser of (A) the Measurement Date Average Price and (B) $89.00, minus (ii) $56.61, multiplied by (b) 586,601 Bbls per year for each of the five years from 2018 through 2022 represented by the contracts for the entire acquisition.  The contingent consideration is capped at $95 million and is to be paid on January 1, 2018.

In connection with the closing of the acquisition on December 18, 2015, we entered into a First Amendment to Interest Purchase Agreement, which changed the method of payment of the initial $160 million of the purchase price.  Under the terms of the First Amendment, we paid the Sellers $60 million in cash at the closing, and delivered the Seller Note payable to the Sellers in the original principal amount of $97.5 million.  See “Financing for the 2015 Acquisition” below.  The purchase price was also net of estimated operating cash flow of approximately $2.5 million from September 15, 2015 through December 31, 2015.  The First Amendment provides that so long as the Partnership is not in default under the Seller Note, in lieu of our obligation to make the contingent payment, we will have a one-time right (exercisable between June 15, 2016 through June 30, 2016) to elect to pay the Sellers $5 million in full satisfaction of the contingent payment obligation, by either paying to the Sellers $5 million at the time of election or by increasing the amount of the Seller Note by $5 million.

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Financing for the 2015 Acquisition

The Seller Note bears interest at 5% per annum and is payable in full no later than September 30, 2016 (“Maturity Date”).  Subject to the Partnership’s compliance with the conditions set forth in the Seller Note and below, the Partnership shall have the right to extend the Maturity Date to March 31, 2017.  The Partnership’s right to extend the Maturity Date is subject to the satisfaction of the following conditions: (i) the Partnership must deliver to Seller written notice of the election to extend the Maturity Date no later than September 1, 2016, (ii) the Partnership shall pay to Seller by September 30, 2016, an extension fee equal to 0.5% of the outstanding principal balance outstanding at that date, (iii) during the extension period and until the Seller Note is paid in full, in cash, the interest rate on the outstanding principal amount of the Seller Note shall bear interest at the fixed rate of 7.0% per annum, (iv) the outstanding principal amount of the Seller Note as of September 1, 2016 shall not be in excess of $60 million, and (v) both at the time of the delivery of the extension notice and as of September 30, 2016, no event of default shall exist under the Seller Note or any collateral document. There is no penalty for prepayment of the Seller Note. Payment of the Seller Note is secured by a mortgage and liens on all of the Sanish Field Assets in customary form. If the Partnership has not fully repaid all amounts outstanding under the Seller Note on or before June 30, 2016, the Partnership must also pay a deferred origination fee in an amount equal to $250,000.

Interest is due monthly on the last day of each month while the Seller Note remains outstanding. In addition to interest payments on the outstanding principal balance of the Seller Note, the Partnership must make mandatory principal payments monthly in an amount equal to 75% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the Seller Note is reduced to $60 million and 50% of the net proceeds the Partnership receives from the sale of its equity securities thereafter, until the Seller Note is paid in full. In addition, if the Partnership sells any of the property that is collateral for the Seller Note, the Partnership must make a mandatory principal payment equal to 100% of the net proceeds of such sale until the principal amount of the Seller Note is paid in full.

Our Oil and Natural Gas Reserves

The table below summarizes our estimated net proved reserves as of December 31, 2015:

	As of December 31, 2015
					Natural
	Oil		NGLS		Gas
	(MBbls)		(MBbls)		(MMcf)
Proved Reserves (1)
Developed		5,603		962		3,966
Undeveloped		3,465		903		3,723
Total Proved Reserves		9,068		1,865		7,689

(1) Our proved reserves as of December 31, 2015 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. The oil, natural gas and NGL prices used in computing the Partnership’s reserves as of December 31, 2015 were $50.28 per Bbl, $2.59 per MMbtu, and $15.74 per Bbl of NGL before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2015 were $41.74 per Bbl of oil, $1.46 per MMbtu of natural gas and $9.77 per Bbl of NGL. See “Note 9 — Supplemental Oil and Natural Gas Disclosures (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.  Prices for oil or natural gas at their current levels are below the average calculated for 2015.  Sustained lower prices will cause the estimated quantities and present values of our reserves being reduced and may necessitate future write-downs. 

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Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and our peers, and in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The Partnership engaged Pinnacle Energy Services, LLC (“Pinnacle Energy”) to prepare the reserve estimates for all of the Partnership’s assets for the year ended December 31, 2015 in this prospectus.  Pinnacle Energy founder J.P. Dick has over 30 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations and issues during that time, and is a Registered Professional Engineer in the states of Texas and Oklahoma. Further qualifications include a bachelor of science in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, Mr. Dick is an active participant in industry reserve seminars, professional industry groups and is a member of the Society of Petroleum Engineers.

Our controls over reserve estimates include engaging Pinnacle Energy as our independent petroleum engineer. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Pinnacle Energy and they prepared estimates of our reserves attributable to our properties. All of the information regarding reserves in this report was derived from the report of Pinnacle Energy, which is included as an exhibit to the registration statement of which this prospectus is a part.  The Partnership has no internal technical person responsible for overseeing the preparation of the reserves estimates by Pinnacle.

Our President works closely with our independent engineers, Pinnacle Energy, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. He works with Pinnacle Energy to review properties and discuss the methods and assumptions used by Pinnacle Energy in their preparation of the year end reserve estimates. Our President also meets with Pinnacle Energy to review the methods and assumptions used by them in the preparation of year end reserve estimates, and assess them for reasonableness. The Board of Directors of our General Partner also meet with our President to discuss matters and policies related to our reserves.

Our methodologies include reviews of production trends, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields. We apply and maintain internal controls, including but not limited to the following, to ensure the reliability of reserves estimations:

· no employee’s compensation is tied to the amount of reserves booked;

· we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;

· reserve estimates are made by experienced reservoir engineers or under their direct supervision;

· annual review by the Board of Directors of our General Partner of our year-end reserve estimates prepared by Pinnacle Energy.

· each quarter, the Board of Directors of our General Partner reviews all significant reserves changes and all new proved undeveloped reserves additions.

Proved Undeveloped Reserves

At December 31, 2015, we had proved undeveloped reserves (“PUDs”) of approximately 5.0 MMBOE, or approximately 40% of total proved reserves. Total PUDs at December 31, 2014 were 0 MMBOE.  The following table reflects the changes in PUDs during 2015: 

	MBOE
Proved undeveloped reserves, December 31, 2014		0
Proved undeveloped reserves acquired		4,988
Proved undeveloped reserves, December 31, 2015		4,988

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Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of their date of original booking unless specific circumstances justify a longer time.  We will be required to remove our current PUDs if we do not drill those reserves within the required five-year time frame, unless specific circumstances justify a longer time.  All of our PUDs at December 31, 2015 are scheduled to be drilled within five years of the date they were initially recorded. Lower prices for oil and natural gas as seen in the recent decline may cause us in the future to forecast less capital to be available for development of our PUDs, which may cause us to decrease the amount of our PUDs we expect to develop within the five year time frame.  In addition, lower oil and natural gas prices may cause our PUDs to become uneconomic to develop, which would cause us to remove them from the proved undeveloped category. 

Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil, natural gas, and natural gas liquids for the periods indicated below.  

	Year (Period) Ended December 31,
	2015		2014		2013
Net production MBOE(1):
Oil		21,937		-		-
Natural gas		3,065		-		-
Natural gas liquids		2,841		-		-
Total (MBOE)		27,843		-		-
Average sales price per unit:
Oil (per Bbl)	$	30.17	$	-	$	-
Natural gas (per Mcf)		1.47		-		-
Natural gas liquids (per Bbl)		5.29		-		-
Combined (per BOE)		25.28		-		-
Average costs per BOE:
Lease operating expense	$	5.35	$	-	$	-
Production and ad valorem taxes		3.32		-		-

(1) All production and cost figures are derived from the Partnership’s ownership of the properties from December 18, 2015 through December 31, 2015.

Delivery Commitments

As of December 31, 2015, we had no commitments to provide a fixed quantity of oil or natural gas.

Drilling Activity

Since we have only owned assets since December 18, 2015 we have limited drilling activity. As of December 31, 2015, we were drilling 1 gross (.1365 net) well.

Total Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2015:

	December 31, 2015
	Gross		Net
Oil wells:
Sanish Field		215		23.5
Natural gas wells
Sanish Field		-		-

Of the total well count for 2015, 0 gross wells (0 net) are multiple completions.   

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Productive wells are producing wells and wells we deem mechanically capable of production, including shut-in wells, wells waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up.  A gross well is a well in which we own a working interest.  The number of net wells represents the sum of fractional working interests the Partnership owns in gross wells.

Developed and Undeveloped Acreage Position

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2015, all of which is located in the State of North Dakota in the United States:

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

Sanish Field, Mountrail County, N.D.

37,537

4,278

-

-

37,537

4,278

As is customary in the oil and natural gas industry, we can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.

Undeveloped Acreage Expirations

The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2015, all of which is located in the United States, that will expire over the following three years by core area unless production is established within the spacing units covering the acreage prior to the expiration dates:

	2016				2017				2018
	Gross		Net		Gross		Net		Gross		Net
Sanish Field		-		-		-		-		-		-

The Partnership has no undeveloped acreage expirations as all acreage is held by production.

Marketing and Customers

The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Whiting, as operator of our properties, sells 99% of our production on our behalf.

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things. Since we are not the operator of any of our properties, we rely on the insurance of the operator of our properties, of which our share of the cost is allocated back to the Partnership through the Joint Operating Agreement.

Currently, we have general liability insurance coverage up to $1,000,000 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

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We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

The description of the Purchase Agreement set forth above is only a summary and is qualified in its entirety by reference to the Purchase Agreement, a copy of which is filed as an exhibit to the registration statement of which the Prospectus is a part.  Combined Statements of Revenues and Direct Operating Expenses for the Sanish Field Assets for the three years ending December 31, 2014, and the six months ending June 30, 2015 and 2014, along with the Partnership’s pro forma financial statements reflecting the acquisition of the Sanish Field Assets for the year ending December 31, 2015, are included in this prospectus beginning on Page F-21.

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COMPETITION, MARKETS AND REGULATION

Competition

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

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

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

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas where we may acquire producing properties.  In addition, it is possible that we will acquire oil and gas properties that are subject to flooding, drought or tornados.  These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations.  Generally, demand for natural gas is higher in summer and winter months.  In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months.  This can also lessen seasonal demand fluctuations.

Environmental, Health and Safety Matters and Regulation

Our operations will be subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment as well as the discharge of materials into the environment.  These laws and regulations may, among other things:

· require the acquisition of various permits before drilling commences;

· require the installation of pollution control equipment in connection with operations;

· place restrictions or regulations upon the use or disposal of the material utilized in our operations;

· restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

· limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

· require remedial measures to mitigate or remediate pollution from former and ongoing operations, and may also require site restoration, pit closure and plugging of abandoned wells; and

· require the expenditure of significant amounts in connection with worker health and safety.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.  The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.  Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs.  In general, the oil and natural gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters.  The US Environmental Protection Agency, or EPA, has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2014 to 2016 and recently renewed this enforcement initiative for fiscal years 2017 to 2019.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

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Solid and Hazardous Waste Handling

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste.  Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we expect to generate waste as a routine part of our operations that may be subject to RCRA.  Although a substantial amount of the waste expected to be generated in our operations is regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future.  Any such change could result in substantial costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our expected operations, we will generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum, and there is no guarantee that federal law will not adopt more stringent requirements with respect to the petroleum substances.  We may also be the owner or operator of sites on which hazardous substances have been released.  If contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.  Further, we could be required to suspend or cease operations in contaminated areas.

We have and may acquire producing properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances, wastes or hydrocarbons may have been released on or under the properties to be acquired by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of the properties we acquire may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.  The federal Clean Water Act only regulates surface waters.  However most of the state analogs to the Clean Water Act also regulate discharges which impact groundwater.

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Safe Drinking Water Act and Hydraulic Fracturing

Many of the properties we own and expect to acquire will require additional drilling operations to fully develop the reserves attributable to the properties.  Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel).

 Congress has repeatedly considered legislation (including a bill introduced in the current Congressional session) to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process.  Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies.  A number of states, local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations.

Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal, state, regional and local levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities.  The EPA has commenced a wide-ranging study on the effects of hydraulic fracturing on drinking water resources and released a draft report in 2015.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we acquire properties that require additional drilling, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our assets.

Toxic Substances Control Act and Hydraulic Fracturing

On August 4, 2011, Earthjustice and 114 other organizations petitioned EPA under section 21 of the Toxic Substances Control Act (TSCA) to use section 8(a) to require manufacturers and processors of oil and gas exploration and production (E&P) chemical substances and mixtures to maintain certain records and submit reports on those records; TSCA section 8(d) to require manufacturers, processors, and distributors to submit to EPA existing health and safety studies related to E&P chemical substances and mixtures; TSCA section 8(c) to request submission of copies of any information related to significant adverse reactions to human health or the environment alleged to have been caused by E&P chemical substances and mixtures; and TSCA section 4 to require manufacturers and processors of E&P chemical substances and mixtures to conduct toxicity testing of E&P chemical substances and mixtures. In a letter dated November 2, 2011, EPA informed petitioners that it denied the TSCA section 4 request and in a letter dated November 23, 2011, EPA informed petitioners that it granted in part the TSCA section 8(a) and 8(d) requests. The document sets forth EPA's reasons for denying in part the petitioners' requests. In addition, EPA has concluded that TSCA section 21 does not apply to requests for a TSCA section 8(c) data call-in.  EPA is launching a stakeholder and public engagement process to seek input on the design and scope of a system of reporting requirements. This is part of EPA general review of hydraulic fracturing.

Oil Pollution Act

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge on properties we acquire, we may be liable for costs and damages.

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Air Emissions

Our operations are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring us to forego construction, modification or operation of certain air emission sources.

 On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation.  The EPA rules include standards for completions of hydraulically fractured natural gas wells.  Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device.  Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of “green completions.”  The standards are applicable to newly fractured wells and also existing wells that are refractured.  Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment.  The EPA received numerous requests for reconsideration of these rules, and court challenges to the rules were also filed.  The EPA has expressed an intent to issue some revisions that are likely responsive to some of the requests.  For example, in September 2013, the EPA promulgated amendments related to certain storage vessels and in July 2014 proposed amendments related to well completion actions and to remove affirmative defense provisions.  These rules and any revised rules may require the installation of equipment to control emissions on producing properties we acquire.

In 2015, EPA proposed new rules limiting methane emissions from the oil and gas industry.  The proposed rules, if adopted, would amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane.  Simultaneously with the proposal of the methane rules, EPA released a proposal soliciting comments on two alternatives for aggregating multiple surface sites into a single-source of air quality permitting purposes. Depending upon the alternative selected by EPA, sites which currently would not require permitting under the Clean Air Act could require permits, an outcome that could result in costs and delays to our operations; however, given the present uncertainty regarding this rule, the extent and magnitude of that impact cannot be reliably or accurately estimated.  In January 2016, BLM has proposed rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls and well as inspection requirements. If adopted or enacted, additional regulations on our air emissions is likely to result in increased compliance costs and additional operating restrictions on our business.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All proposed exploration and development plans on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Climate Change Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. Both houses of Congress have considered legislation to reduce emissions of GHGs, but no legislation has yet passed.  In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.  The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources, the proposal of which is discussed above.

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In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Some members of Congress have expressed the intention to promote legislation to curb the EPA’s authority to regulate GHGs. In addition to possible federal regulation, a number of states, individually and regionally as well as some localities, also are considering or have implemented GHG regulatory programs or other steps to reduce GHG emissions. These potential regional, state and local initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 

Endangered Species Act

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat.  Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.  We may conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act.  The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species.  A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected properties that we acquire.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we might conduct operations could result in limitations or prohibitions on our activities and could adversely impact the value of our leases.

OSHA and Other Laws and Regulation

We will be subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes.  The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. Our drilling and production operations will be subject to various types of regulation at the federal, state and local levels.  These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations.  Most states and some counties and municipalities in which we operate also regulate one or more of the following:

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· the location of wells;

· the method of drilling, completing and operating wells;

· the surface use and restoration of properties upon which wells are drilled;

· the plugging and abandoning of wells;

· the marketing, transportation and reporting of production;

· notice to surface owners and other third parties; and

· produced water and waste disposal.

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gasproduced by assigning allowable rates of production and control contamination of the environment.  Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which can affect our operations.  State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions.  States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

In addition, a number of states and some tribal nations have enacted surface damage statutes, or SDAs. These laws are designed to compensate for damage caused by oil and natural gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and require specific payments by the operator to surface owners/users in connection with exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We will not control the availability of transportation and processing facilities that may be used in the marketing of our production. For example, we may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by BLM Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States.  If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General.  We qualify as an entity formed under the laws of the United States or of any U.S. State or territory.  Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal countries, there are presently no such designations in effect.  It is possible that our common unitholders may be citizens of foreign countries and do not own their common units in a U.S corporation or even if such interest is held through a U.S. corporation, their country of citizenship may be determined to be non–reciprocal countries under the Mineral Act.  In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

Federal Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

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Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

 FERC has also issued several other generally pro–competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, FERC generally reaffirmed its policy of allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline–by–pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, FERC established criteria to allow providers to charge market–based (i.e., negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short–term releases by shippers of interstate pipeline transportation capacity.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the properties we may acquire. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.

The U.S. Department of Energy (“DOE”) regulates the export of natural gas produced in the U.S., including the export of liquefied natural gas (“LNG”), and the FERC regulates the construction and operation of liquefaction facilities used to convert gaseous natural gas into liquid for export as LNG. The DOE has granted several long-term LNG export licenses and FERC has authorized the construction and operation of several LNG export facilities for natural gas produced in the lower 48 States of the U.S., several of which are currently under construction. In March 2016, the first cargo of LNG from the lower 48 States of the U.S. is expected to be exported from an LNG export facility located in Louisiana. It is too early to tell what impact this expansion of the markets available to natural gas produced in the U.S. will have on U.S. natural gas prices.

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our proposed operations.

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CAPITAL CONTRIBUTIONS AND DISTRIBUTIONS

Capital Contributions

For each of the first 5,263,158 common units we sold, the net capital contribution of common unitholders was the $19.00 purchase price of a common unit less the $0.95 commission and $0.19 marketing fee payable to David Lerner Associates, Inc. or broker dealers selected by David Lerner Associates, Inc. to participate in the offering of common units.  The net capital contributions of common unitholders for each of the remaining 95,000,000 common units will be the $20.00 purchase price of a common unit less the $1.00 commission and $0.20 marketing fee payable to David Lerner Associates, Inc. or broker dealers selected by David Lerner Associates, Inc. to participate in the offering of common units.  No commissions or marketing fee will be paid with respect to common units purchased by the general partner, and the directors, officers and employees of the general partner or the general partner’s affiliates.

The general partner will make only a nominal capital contribution to the Partnership.

The general partner intends that the capital contributions will be used as follows:

Distributions.  It is possible that all or a part of distributions to common unitholders during the early years of our operations will represent the proceeds of capital contributions or borrowings, rather than cash generated in our operations. This is because as proceeds are raised in the offering, it is not always possible immediately to invest them in oil and gas properties that generate our desired return on investment. There may be a “lag” or delay between the raising of offering proceeds and their investment in oil and gas properties. Persons who acquire common units relatively early in our offering, as compared with later investors, may have a greater percentage of their distributions generated from debt or capital contributions. Further, there is no limitation on the amount of distributions that can be funded from offering proceeds or financing proceeds.  For a description of the circumstances under which the general partner may cause the Partnership to make distributions of capital contributions, please read “Distributions.”

Offering and Organization and General and Administrative Costs.  The Partnership will pay the offering and organization costs out of capital contributions, and the general partner will be entitled to be reimbursed out of capital contributions for offering and organization costs paid by the general partner.  Offering and organization costs are costs paid to third parties in connection with the preparation and filing of this prospectus and the offering of common units, including accounting, legal, printing, travel and similar costs.  Offering and organization costs include only documented, out of pocket expenses incurred by the general partner and do not include any allocable overhead or other internal costs of the general partner and its affiliates.  Total offering and organizational costs paid by the Partnership or reimbursed to the general partner is estimated to be $8.0 million if the maximum offering is achieved.  While we have made these estimates in good faith, they are inherently imprecise, and are dependent on events that will occur in the future.  Some of the factors that will affect the actual out-of-pocket expenses we will reimburse are,

· The number of prospectuses we print and distribute;

· The number of supplements to the prospectus we prepare, print and distribute;

· The length of time the offering is being made; and

· The number of states in which we offer common units.

 There is no maximum amount of out-of-pocket expenses we will pay or reimburse to the general partner.  Accordingly, the actual amount of reimbursed out-of-pocket expenses could be materially higher than the foregoing estimates.

We will also reimburse the general partner for the amount of its general and administrative costs allocable to the Partnership’s activities.  These general and administrative expenses will include salary and other compensation expense, rent, office supplies, and travel expenses.  Initially, all of the general partner’s activities will be allocable to the Partnership. If, in the future, the general partner forms other partnerships or engages in other activities, the general partner’s general and administrative expenses will be allocated to the Partnership and such other activities in a manner deemed reasonable by the general partner.  The general partner estimates that that the amount of reimbursed general and administrative costs for the first year following the initial closing will be $4.0 million if the maximum offering is achieved.

Oil and Gas Property Acquisition Costs.  The general partner intends to use the capital contributions and Partnership borrowings to pay the purchase price of oil and gas properties and related costs and expenses, such as broker fees, and legal, land, environmental review and reserve engineering fees.

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Drilling and Other Property Development Costs.  When the Partnership acquires a property, it will estimate the amount of costs to be incurred to conduct any additional development activities necessary to develop the property’s reserves.  The general partner will reserve an amount of capital contributions and borrowing capacity under its credit facility to pay such development costs.  The general partner may also use partnership revenues to pay such costs.

Distributions

Our investment objective is to sell oil, gas and other hydrocarbons produced from properties that we may acquire, and if we do not merge with another company or list our common units on a national securities exchange, to sell our properties, in order to make cash distributions to holders of our common units, incentive distribution rights and class B units.  Because we are a newly formed entity with limited prior operating history and did not acquire any assets until December 2015, we can make no assurances as to the amount, if any, that a holder of common units may receive as distributions with respect to his or her common units or as to the timing of any distributions.  

Prior to “Payout,” which is defined below, all of the distributions we make, if any, will be paid to the holders of common units.  Accordingly, we will not make any distributions with respect to the incentive distribution rights, which will be owned by our general partner, or with respect to its class B units, which are owned by an affiliate of the Former Manager, and will not make the contingent, incentive payments to the dealer manager under the dealer manager agreement, until Payout occurs.  For a description of the other amounts we will pay the general partner, the Former Manager and the dealer manager, please read “Compensation” beginning on page 45.

Our Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of our common units equals $20.00 plus the Payout Accrual as of such date.  Our Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time.  Our Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit.  If at any time we distribute to holders of common units more than the Payout Accrual, the amount we distribute in excess of the Payout Accrual will reduce the Net Investment Amount.  By way of example, if we have distributed to the holders of the common units an amount equal to the Payout Accrual and then distribute an additional $2.00 per common unit, the Net Investment Amount will be reduced to $18.00 per common unit and the Payout Accrual will be 7% per annum simple interest on $18.00.  At the point in time that we distribute $20.00 per common unit in excess of the Payout Accrual, the Net Investment Amount will be $0.00 per common unit and Payout will have occurred.

Our partnership agreement does not require us to make distributions to the holders of our common units.  Because we have limited prior operating history and have identified only one group of oil and gas properties that we will acquire, and can provide no assurances of our ability to make distributions, the 7% per annum Payout Accrual and the Net Investment Amount are not intended to reflect the amount we expect to distribute to holders of common units from our anticipated future operations.  Rather, Payout reflects our agreement that the general partner and the affiliate of our Former Manager will not receive any distributions from the incentive distribution rights or class B Units, and the dealer manager will not receive its contingent, incentive fee under the dealer manager agreement, until the holders of common units have received distributions sufficient to cause Payout to occur.

All distribution made prior to Payout will be made as follows:
 

· 100% to the holders of common units.

All distributions made after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of our assets, will be made as follows (assuming the cancellation and no reissuance of 37,500 of the class B units issued to an affiliate of the Former Manager):

· First, 35% to the holders of the incentive distribution rights, 21.875% to the holders of the class B units, 13.125% to the holders of the common units, and 30% to the dealer manager under the dealer manager agreement as its contingent, incentive fee until the dealer manager receives fees equal to 4% of the gross proceeds of the offering of common units; and then

· Thereafter, 35% to the holders of the incentive distribution rights, 21.875% to the holders of the class B units and 43.125% to the holders of common units.

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Because we expect to have multiple closings of sales of common units, the Payout Accrual for common units sold earlier in the offering may have a larger Payout Accrual than common units sold later in the offering.  Our Partnership Agreement provides that distributions to holders of common units will be paid to holders of common units in proportion to the Payout Accrual for the common units owned, until all of the common units have the same Payout Accrual.

There is no requirement in our Partnership Agreement that distributions represent our net income or the proceeds from the sale of oil and gas from properties that we may acquire.  The general partner may make distributions all or a portion of which represent capital contributions.  If our general partner makes distributions in our early years of operation it is more likely that these distributions will represent capital contributions, rather than cash generated by our operations.  This is because as proceeds are raised in the offering it is not always possible immediately to invest them in oil and gas properties.  There may be a “lag” or delay between the raising of offering proceeds and the sale of oil and gas from properties that we acquire.

Although our general partner does not currently plan to use the proceeds of borrowings to make distributions, the general partner will have the right to distribute the proceeds of borrowings, and the general partner may determine that it is in the best interests of the holders of common units to make distributions from the proceeds of borrowings.

The incentive distribution rights and class B units are non-voting limited partner interests in us that will not participate in our cash distributions until Payout occurs.  Initially, our general partner will own the incentive distribution rights and an affiliate of the Former Manager will own the class B units.  The contingent, incentive fee is a contractual obligation we have agreed to pay to the dealer manager pursuant to the dealer manager agreement.

In connection with the termination of the Management Agreement, 37,500 of the class B units issued to an affiliate of the Former Manager were forfeited and cancelled.  Consequently, the distributions that would otherwise have been paid with respect to the cancelled class B units will be distributed to holders of common units.  The general partner may cause us to issue additional class B units to a person who performs services for us in an amount not to exceed the number of class B units cancelled. 

The dealer manager agreement with the dealer manager provides that we will pay a contingent, incentive fee to the dealer manager each time we make a distribution to holders of our incentive distribution rights and class B Units after Payout occurs. The dealer manager’s contingent, incentive fee is equal to 30% of the available cash distributed when payments are made to holders of our incentive distribution rights and class B Units after Payout occurs. The contingent, incentive fee will be deemed paid in full when the dealer manager has received an aggregate 4% of the gross proceeds of the offering of common units, less any amounts paid to the dealer manager as account maintenance fees.

Our ability to make distributions will be dependent on the success of our business, which is subject to numerous risks, and no assurances can be made as to the amount or timing of any distributions that we will be able to make in the future.  See “Risk Factors.”

For the year ended December 31, 2015, the Partnership paid distributions of $0.510138 per common unit or $1,271,730.

Neither the Partnership nor the General Partner has adopted an equity compensation plan.

Sale of Properties, Merger or Listing of the Common Units

Beginning five to seven years after the termination of this offering, we plan either to sell all or substantially all of our properties and distribute to our partners the proceeds of the sale, after payment of liabilities and expenses, to our partners, merge with another, unaffiliated entity or list the common units on a national securities exchange.  The sale of all or substantially all of our properties and the listing of the common units both require the consent of the holders of a majority of our common units.

The decision by the general partner to sell our assets, and our ability to sell our assets, will depend on the following, among other factors, many of which will be beyond the control of our general partner:

· The market for oil and gas properties;

· The price of the oil, gas and other hydrocarbons which our properties produce;

· General economic conditions; and

· Whether we have finished the planned development of the properties we acquire.

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The decision by the general partner to merge us with another entity, and the ability of our general partner to merge us with another entity, will depend upon a number of factors some of which are beyond the control of the general partner, including:

· The value of our oil and gas properties;

· Any liabilities we may be subject to, including contingent liabilities; and

· Conditions prevailing in the merger and acquisition market at the time.

The decision by the general partner to apply to list the common units, and the ability of the general partner to list the common units, will depend upon a number of factors some of which will be beyond the control of the general partner, including,

· The amount of assets, revenues and earnings that we have at the time of our listing;

· The then existing market for oil and gas master limited partnerships; and

· The listing standards of the various national securities exchanges, and whether we are able to meet those listing standards.

No assurances can be made that we will be able to sell our assets, merge or list the common units, nor can we provide any assurances as to the amounts we will be able to distribute if we sell assets, the amount of consideration that could be received in a merger or as to the price our common units will trade if we are able to list them.

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FIDUCIARY DUTY OF THE GENERAL PARTNER

Our general partner is accountable to the Partnership and the holders of common units as a fiduciary. Fiduciary duties owed to holders of common units by our general partner are prescribed by law and our Partnership Agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our Partnership Agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed to us by our general partner. We have adopted these restrictions to allow our general partner or their affiliates to engage in transactions with us that might otherwise be prohibited by state law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us.  These modifications may be detrimental to holders of our common units because they restrict the remedies available to them for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

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The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership Agreement modified standards

Our Partnership Agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our Partnership Agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the holders of our common units whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

	In addition to the other more specific provisions limiting the obligations of our general partner, our Partnership Agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.
Special provisions regarding affiliated transactions.	Our Partnership Agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of holders of common units must be:
	·on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
	·“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
	It will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each investor automatically agrees to be bound by the provisions in our Partnership Agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a discussion of the material U.S. federal income tax consequences that may be relevant to prospective common unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Haynes and Boone, LLP, counsel to us, insofar as it relates to matters of U.S. federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Code, existing and proposed Treasury regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Energy 11, L.P. and, where appropriate, our operating subsidiaries.

This section does not address all U.S. federal income tax matters that affect us or the common unitholders. Furthermore, this section focuses on common unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, foreign persons, or other common unitholders subject to specialized tax treatment, such as tax-exempt institutions, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts (“REITs”), or mutual funds. Accordingly, we urge each prospective common unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local, and foreign tax consequences particular to him of the ownership or disposition of our common units.

No ruling has been or will be requested from the Internal Revenue Service (“IRS”) regarding any matter that affects us or prospective common unitholders. Instead, we will rely on opinions and advice of Haynes and Boone, LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest with the IRS may materially and adversely impact the value of our common units. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our common unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any such modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Haynes and Boone, LLP and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Haynes and Boone, LLP.

For the reasons described below, Haynes and Boone, LLP has not rendered an opinion with respect to the following specific U.S. federal income tax issues:

(1) whether percentage depletion will be available to a particular common unitholder or the extent of the percentage depletion deduction available to any particular common unitholder (please read “— Tax Treatment of Operations — Depletion Deductions”); and

(2) whether the deduction related to U.S. production activities will be available to a particular common unitholder or the extent of any such deduction to any particular common unitholder (please read “— Tax Treatment of Operations — Deduction for U.S. Production Activities”).

Partnership Status

We have not made an election to be treated as a corporation or association under the so-called “check-the-box” regulations, under Treasury Regulation section 301.7701-1 et seq. Nonetheless, there a risk that we could be treated as a “publicly traded partnership” for U.S. federal income tax purposes resulting in our treatment as an association taxable as a corporation. A publicly traded partnership for U.S. federal income tax purposes is generally any partnership whose interests are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Our common units will not be traded on an established securities market, so the Partnership should not be treated as a publicly traded partnership as a result of being traded on an established security market.

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Notwithstanding the foregoing, interests in a partnership are readily tradable on a secondary market or the substantial equivalent thereof if taking into account all of the facts and circumstances, the partners are readily able to buy, sell, or exchange their partnership interests in a manner that is comparable, economically, to trading on an established securities market. For this purpose, partnership interests will be treated as readily tradable on a secondary market or the substantial equivalent if: (1) interests in the partnership are regularly quoted by any person, such as a broker or dealer, making a market in the interests; (2) any person regularly makes available to the public (including customers or subscribers) bid or offer quotes with respect to interests in the partnership and stands ready to effect buy or sell transactions at the quoted prices for itself or on behalf of others; (3) the holder of an interest in the partnership has a readily available, regular, and ongoing opportunity to sell or exchange the interest through a public means of obtaining or providing information of offers to buy, sell or exchange interests in the partnership; or (4) prospective buyers and sellers otherwise have the opportunity to buy, sell or exchange interests in the partnership in a time frame and with the regularity and continuity that is comparable to that described in (1) - (3).

The Treasury Regulations set forth certain transfers that will be disregarded in determining whether there is trading on a secondary market. Those transfers include transfers at death, transfers between family members, distributions from a qualified retirement plan and so-called block transfers as defined by the Treasury Regulations.

The Treasury Regulations also provide certain safe harbors that permit certain transfers (other than disregarded transfers) of partnership interests without creating a deemed secondary market or the substantial equivalent thereof. For example, one safe harbor provides that interests in a partnership will not be considered tradable on a secondary market or the substantial equivalent thereof if the sum of the partnership interests transferred during any taxable year of the partnership, excluding certain disregarded transfers, does not exceed 2% of the total interest in the capital or profits of the partnership. Failure to satisfy a safe harbor provision under the regulations, however, will not necessarily cause a partnership to be treated as a publicly traded partnership if, taking into account all of the facts and circumstances, the partners are not readily able to buy, sell or exchange their interests in a manner that is comparable, economically, to trading on an established securities market.

It is unclear whether we will satisfy one or more of the secondary market safe harbors. However, we believe that no market will exist for common unitholders to readily buy, sell or exchange their units in a manner that is comparable, economically, to trading on an established securities market, and we will not make a market for the common units.

If we were treated as a publicly traded partnership for U.S. federal income tax purposes, we would nonetheless not be taxable as a corporation if 90% or more of our gross income for each taxable year in which we were a publicly traded partnership consisted of “qualifying income.” For this purpose, qualifying income generally includes, among other things, income and gains derived from the exploration, development, mining, production or marketing of oil and natural gas, and the gain from the sale of assets to produce such income. We believe that, under current law, at least 90% of our gross income will constitute income derived from the exploration, development, production, and/or marketing of oil and gas.

If we were taxable as a corporation in any taxable year, as a result of being treated as a publicly traded partnership and a failure to meet the qualifying income exception described above, our items of income, gain, loss, and deduction would be reflected only on our tax return rather than being passed through to the common unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a common unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the common unitholder’s tax basis in his common units, and generally taxable capital gain to the extent of the excess over the common unitholder’s tax basis in his common units. Accordingly, taxation as a corporation would result in a material reduction in a common unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction in the value of the common units.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. Instead, we will rely on the opinion of Haynes and Boone, LLP. Haynes and Boone, LLP is of the opinion, based upon the Code, Treasury regulations, published revenue rulings, court decisions, and certain representations we have provided, that we will be classified as a partnership for U.S. federal income tax purposes.

The remainder of this section is based on the position that we will be classified as a partnership for U.S. federal income tax purposes.

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Tax Consequences of Common Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “— Tax Consequences of Common Unit Ownership — Entity Level Collections,” we will not pay any federal income tax. Instead, each common unitholder will be required to report on his income tax return his share of our income, gains, losses, and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a common unitholder even if he has not received a cash distribution. Each common unitholder will be required to include in income his share of our income, gain, loss, and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a common unitholder generally will not be taxable to him for U.S. federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Cash distributions made by us to a common unitholder in an amount in excess of his tax basis in his common units generally will be considered to be gain from the sale or exchange of those common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. To the extent that cash distributions made by us cause a common unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Tax Consequences of Common Unit Ownership — Limitations on Deductibility of Tax Losses.”

Any reduction in a common unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that common unitholder. A decrease in a common unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. Notwithstanding the discussion in the previous paragraph, an actual or deemed non-pro rata distribution of money or property may result in ordinary income or loss to a common unitholder, regardless of his tax basis in his common units, if the distribution reduces the common unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual items distributed to him. This latter deemed exchange will generally result in the common unitholder’s realization of ordinary income or loss. That income or loss will equal the difference between (1) the non-pro rata portion of that distribution over (2) the common unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units

A common unitholder’s tax basis for his common units generally will equal to the amount he paid for the common units, increased by his share of our income (including tax-exempt income) and by any increases in his share of our nonrecourse liabilities, and decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized.

Limitations on Deductibility of Tax Losses

The deduction by a common unitholder of his share of our taxable losses will be limited to his tax basis in his common units and, in the case of an individual common unitholder, an estate, a trust or a corporate common unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or certain tax-exempt organizations, to the amount for which the common unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A common unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that the common unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a common unit, any gain recognized by a common unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

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In general, a common unitholder will be at risk to the extent of his tax basis in his common units, excluding any portion of that tax basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to the common unitholder or can look only to the common units for repayment. A common unitholder’s at risk amount will increase or decrease as the tax basis of the common unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The at risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer’s oil and natural gas properties. Although it is unclear how this statutory rule should be applied in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for U.S. federal income tax purposes, current guidance will permit aggregation of oil or gas properties we own in computing a common unitholder’s at risk limitation with respect to us. If a common unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his common units as a whole.

In addition to the tax basis and at risk limitations discussed above, the passive activity loss rules, which apply to individuals, estates, trusts, personal service corporations and closely held C corporations, limit the ability of these types of taxpayers to deduct losses generated from passive activities. Under the passive activity loss rules, losses from passive activities can only be deducted against income from the passive activity that generated the loss and from other passive activities. Passive activity losses generally cannot be used to offset income from wages or salaries (or other sources of so-called “active” income) or against income from interest, dividends or royalties not derived in the ordinary course of business or against the gain from the sale of property producing such income (so-called “portfolio income”). If a taxpayer has a loss from a passive activity for a given tax year that cannot be used because of the forgoing limitation, the loss will be suspended and may be carried forward by the taxpayer and used to offset future income from passive activities. If a taxpayer has a suspended loss from a passive activity when it disposes of its interest in the activity to an unrelated party, the taxpayer is allowed to deduct the suspended loss against its non-passive income provided that the interest is disposed of in its entirety to an unrelated party in a taxable transaction.

The term “passive activity” encompasses all activities involving a trade or business with respect to which the individual taxpayer does not “materially participate.” This material participation standard is applied individually on an investor-by-investor basis. Thus, in the case of an investment in us, the material participation test will be applied at the common unitholder level to determine whether each common unitholder materially participates in the Partnership’s activities.

Because common unitholders will not significantly participate with regard to the Partnership, common unitholders will be subject to the passive activity loss rules with respect to much of our income or loss.

Limitation on Interest Deductions

The deductibility of a noncorporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense means interest on indebtedness properly allocable to property held for investment. Property held for investment includes, among other things, property that produces passive income, such as royalties.  Based on our anticipated investments, a portion of any interest expense incurred by or allocable to a noncorporate common unitholder may be subject to the investment interest limitations.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any common unitholder or any former common unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the common unitholder on whose behalf the payment was made. Payments by us as described above could give rise to an overpayment of tax on behalf of a common unitholder in which event the common unitholder would be required to file a claim in order to obtain a credit or refund.

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Allocation of Taxable Income, Gain, Loss and Deduction

Each common unitholder’s share of our taxable income, gains, losses, and deductions is determined under the partnership agreement.  In the event we issue additional common units or engage in certain other transactions in the future, certain items of our income, gain, loss, and deduction will be allocated among common unitholders under Section 704(c) of the Code, using the remedial method, to account for the difference between the tax basis and fair market value of our assets at such time(s), and, to the extent necessary following any such Section 704(c) allocations, may be allocated disproportionately among common unitholders in order to achieve capital account parity with respect to all common units.  Allocations to a common unitholder of items of our income, gain, loss, or deduction generally will be given effect for U.S. federal income tax purposes if the allocations have substantial economic effect or are determined to be in accordance with the common unitholders’ interests in the Partnership (taking into account all facts and circumstances).

Notwithstanding the foregoing, certain allocations of income made to a common unitholder who provides certain types of services to or for the benefit of the Partnership (such as the dealer manager) may be recharacterized for federal income tax purposes as a fee paid to such common unitholder which is subject to capitalization by the Partnership and as a result the U.S. federal taxable income allocated to the common unitholders may be increased.  Counsel is of the opinion concerning that the allocations in the partnership agreement will more likely than not be given effect for U.S. federal income tax purposes in determining a common unitholder’s share of an item of income, gain, loss, or deduction.  There can be no assurance that the IRS will not challenge the allocations in the partnership agreement on this or any other basis and attempt to reallocate such items (and the tax obligations associated with such items) among the common unitholders in some other manner. If the IRS were to successfully assert that any item of income, gain, loss or deduction should be allocated in a manner other than as set forth in the partnership agreement, the common unitholders could owe additional tax, interest and penalties for the tax year(s) such reallocations are made.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 20%. These rates are subject to change by new legislation at any time.

A 3.8% Medicare tax is imposed on net investment income earned by certain individuals, estates and trusts. For these purposes, net investment income generally will include a common unitholder’s allocable share of our income and any gain realized by a common unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (1) the common unitholder’s net investment income or (2) the amount by which the common unitholder’s modified adjusted gross income exceeds $250,000 (if the common unitholder is married and filing jointly or a surviving spouse), $125,000 (if the common unitholder is married and filing separately) or $200,000 (in any other case).

Alternative Minimum Tax

Each common unitholder will be subject to the alternative minimum tax (“AMT”) to the extent that his “tentative minimum tax” exceeds his regular income tax liability. For an individual common unitholder, the AMT rate is 26% or 28%, depending on the amount of the common unitholder’s alternative minimum taxable income that is above an exemption amount. Alternative minimum taxable income is a common unitholder’s taxable income increased by certain tax preference items and increased or decreased by certain tax adjustments. The computation of a common unitholders AMT will depend on the common unitholder’s income, gains, deductions, losses, adjustments and tax preference items from sources other than the Partnership and the interaction of these items with the common unitholder’s share of our income, gains, deductions, losses, adjustments and tax preference items. Each common unitholder is urged to consult his own tax advisor with regard to the impact of the AMT with respect to an investment in the Partnership.

Section 754 Election

We are permitted to make an election under Section 754 of the Code to adjust a common unitholder’s tax base in our assets in connection with certain distributions or transfer of common units.  In addition, in certain circumstances, we may be required to make such an adjustment regardless of whether we have made an election under Section 754 of the Code.  Specifically, if in connection with a distribution to a common unitholder or the disposition of common units, there is a “substantial basis reduction” or a “substantial built-in loss,” as the case may be, then such an adjustment will be required.  At this time, we do not plan to make an election under Code Section 754 of the Code.

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Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each common unitholder will be required to include in his taxable income his share of our taxable income, gain, loss, and deduction for our taxable year ending within or with his taxable year. In addition, a common unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss, and deduction in income for his taxable year, with the result that he will be required to include in his taxable income for his taxable year his share of more than twelve months of our income, gain, loss, and deduction.

Depletion Deductions

Subject to the limitations on deductibility of taxable losses discussed above, common unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas properties.

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property generally is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance and without the deduction under Code Section 199. A common unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the common unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 Bbls. This depletable amount may be allocated between natural gas and oil production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one Bbl of crude oil. The 1,000-Bbl limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question. A common unitholder who qualifies for the independent producer exemption is required to determine the amount of its allowed percentage depletion deduction and maintain records supporting such determination.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, any deduction allowable under Code Section 199, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the common unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Common unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (1) dividing the common unitholder’s share of the tax basis in the underlying mineral property by the number of mineral units (Bbls of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (2) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder’s share of the total tax basis in the applicable property.

All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the common unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion and certain other deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury regulations relating to the availability and calculation of depletion deductions by the common unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by us, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to any particular common unitholder for any taxable year. We encourage each prospective common unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

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Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs) associated with wells located in the United States. IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies, and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy.

Although we will elect to currently deduct IDCs, each common unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made or incurred. If a common unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for AMT purposes. Certain expenses, including IDCs, may be subject to the passive income and loss rules.  See “— Tax Consequences of Ownership of Common Units — Limitations on Deductibility of Tax Losses.”

IDCs are generally deductible when the well to which the costs relate is drilled. In some cases, IDCs may be paid in one year for a well that is not drilled until the following year. In those cases, the prepaid IDCs will not be deductible until the year when the well is drilled unless (i) drilling on the well to which the prepayment relates starts within 90 days after the end of the year the prepayment is made or (ii) it is reasonable to expect that the well will be fully drilled within 31/2 months of the prepayment.  All of our wells may not be drilled during the year when we pay IDCs pursuant to a drilling contract. As a result, we could fail to satisfy the requirements to deduct the IDCs in the year when paid and/or the IRS may challenge the timing of our deduction of prepaid IDCs.

Integrated oil companies must capitalize 30% of all their IDCs and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a common unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 Bbls of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (held directly or through ownership of an interest in a partnership) and that would have been included in the tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a common unitholder of common units. Recapture is generally determined at the common unitholder level. See “— Disposition of Common Units — Recognition of Taxable Gain or Loss.”

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, each common unitholder will be entitled to a maximum deduction, herein referred to as the Section 199 deduction, equal to the lesser of (i) 9% of our qualified production activities income that is allocated to such common unitholder or (ii) its taxable income.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts and other expenses, losses or deductions properly allocable to those receipts. The products produced must be manufactured, produced, grown, or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each common unitholder will aggregate his share of the qualified production activities income allocated to him from us with the common unitholder’s qualified production activities income from other sources. Each common unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the common unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at risk rules or the passive activity loss rules. However, disallowed losses subsequently allowed under those rules are taken into account for purposes of the Section 199 deduction when subsequently allowed. Please read “— Tax Consequences of Common Unit Ownership — Limitations on Deductibility of Tax Losses.”

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The amount of a common unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the common unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each common unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the common unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to common unitholders. Further, because the Section 199 deduction is required to be computed separately by each common unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to any particular common unitholder. Each prospective common unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs

The cost of acquiring natural gas and oil leaseholds or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “— Tax Treatment of Operations — Depletion Deductions.”

Geophysical Costs

The costs of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deducted ratably over a 24-month period. This 24-month period is extended to 7 years in the case of major integrated oil companies.

Operating and Administrative Costs

Amounts paid for operating a producing well (excluding tangible property having a salvage value (the cost of which would be capitalized and depreciated)) are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Tax Basis, Depreciation and Amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a common unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his common units. Please read  “— Disposition of Common Units — Recognition of Taxable Gain or Loss.”

Disposition of Common Units

Recognition of Taxable Gain or Loss

Gain or loss will be recognized on a sale of common units equal to the difference between the common unitholder’s amount realized and the common unitholder’s tax basis for the common units sold. A common unitholder’s amount realized will equal the sum of the cash and/or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.

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Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a common unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the common unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a common unitholder, other than a “dealer” in common units, on the sale or exchange of a common unit will generally be taxable as capital gain or loss, and if the common unit was held by a noncorporate common unitholder for more than one year, as long-term capital gain or loss.  Long-term capital gain of noncorporate taxpayers is currently subject to federal income tax at preferential rates.  A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a common unit and may be recognized even if there is a net taxable loss realized on the sale of a common unit. Thus, a common unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may be used to offset only capital gains in the case of corporations.

 Tax Allocations Between Transferors and Transferees

In general, each item of our income, gain, loss and deductions, for U.S. federal income tax purposes, shall be determined on an annual basis.  In the event that a common unitholder transfers his common units during the year, allocations of income, gain, loss or deduction with respect to such common units shall be allocated between the transferor and transferee in accordance with a method permissible under section 706 of the Code and the Regulations thereunder.

A common unitholder who disposes of common units at any time will be allocated items of our income, gain, loss, and deductions regardless of whether the Partnership has made a distribution during the year.

Notification Requirements

A common unitholder who sells any of his common units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale.  Failure to notify us of a transfer of common units may lead to the imposition of substantial penalties.

Constructive Termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all common unitholders. The closing of our taxable year as a result of this rule may result in more than 12 months of our taxable income or loss being includable in the taxable income of common unitholders for the year of termination. A constructive termination occurring on a date other than December 31 will result in our filing two U.S. federal income tax returns (and common unitholders’ receiving two Schedule K-1s) for one fiscal year, and the cost of the preparation of these returns will be borne by all common unitholders. We would also be required to make certain new tax elections after a termination, and a termination could result in a deferral of our deductions for depreciation. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Tax-Exempt Organizations and Other Investors

Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

 Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Much of our income allocated to a common unitholder that is a tax-exempt organization likely will be unrelated business taxable income and will be taxable to them.

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Non-resident aliens and foreign corporations, trusts, or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence they will be required to file U.S. federal tax returns to report their share of our income, gain, loss, or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under applicable tax rules, we will be required to withhold tax on income allocable to such persons.  In addition, because a foreign corporation that owns common units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30% (or such lower rate as may be specified by an applicable income tax treaty), in addition to regular federal income tax, on its share of much of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each common unitholder, as soon as available to us, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss, and deductions for our preceding taxable year. In preparing this information, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each common unitholder’s share of income, gain, loss, and deductions.  A common unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a common unitholder to substantial penalties.

We cannot assure you that the positions we take will yield a result that conforms to the requirements of the Code, Treasury regulations or administrative interpretations of the IRS. Neither we nor Haynes and Boone, LLP can assure prospective common unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any such challenge by the IRS could negatively affect the value of the common units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each common unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a common unitholder’s return could result in adjustments related to our returns and adjustments not related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss, and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The Partnership Agreement appoints our general partner as our Tax Matters Partner.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return: (1) for which there is, or was, “substantial authority,” or (2) as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss, or deduction included in the distributive share of common unitholders could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for common unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of common units if we were classified as a “tax shelter.”

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A substantial valuation misstatement exists if (1) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis; (2) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price; or (3) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly common unitholders) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million in a single taxable year or $4 million in any combination of taxable years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and a common unitholder’s tax return) is audited by the IRS. Please read “— Administrative Matters —Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, common unitholders could be subject to the following provisions and/or limitations: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Administrative Matters — Accuracy-Related Penalties;” for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and in the case of a listed transaction, an extended statute of limitations.

State, Local and Other Tax Considerations

In addition to federal income taxes, common unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance, or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which the common unitholders are resident. Although an analysis of the various taxes is not presented here, each prospective common unitholder should consider their potential impact on his investment in us. Common unitholders may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. Common unitholders will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property and may be subject to penalties for failure to comply with those requirements. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder’s income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Common Unit Ownership — Entity-Level Collections.”

It is the responsibility of each common unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Haynes and Boone, LLP has not rendered an opinion on the state, local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective common unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each common unitholder to file all tax returns that may be required of him.

Future Legislative Changes

The Obama administration’s budget proposals for fiscal year 2015 contain numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies. Among others, the provisions include: repeal of the deduction of IDC; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; and an increase in the amortization period for geological and geophysical costs of independent producers.

The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could increase the amount of our taxable income allocable to you.  We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any modifications to the federal income tax laws or interpretations thereof may or may not be applied retroactively.  Any such changes could negatively impact the value of an investment in our common units.

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CERTAIN BENEFICIAL OWNERS OF THE PARTNERSHIP

The following table sets forth as of April 28, 2016 the beneficial ownership of our common units that are owned by:

· all persons who, to the knowledge of our management team, beneficially own more than 5% of our common units;

· each executive officer of our General Partner; and

· all current directors and executive officers of our General Partner as a group.

	Common		Percentage
	Units		Of Common Units
	Beneficially		Beneficially
Name of Beneficial Owner	Owned		Owned
Glade M. Knight 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*
David S. McKenney 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*
Anthony Francis “Chip” Keating III 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*
Michael J. Mallick 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*
Clifford J. Merritt 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		—		—
Directors and principal officers as a group (5 persons)		20,000		*

* Less than 1% of outstanding common units.

SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT

The following is a summary of our Partnership Agreement, a copy of which is attached as Exhibit A.  While we believe this summary is materially complete, you should carefully read Exhibit A for all of the information regarding the Partnership that may be important to you.  The Partnership Agreement attached as Exhibit A, not this summary, will govern your legal rights and obligations as a holder of common units.

Organization and Duration

Our Partnership was organized in June 2013 and will have a perpetual existence.

Purpose

Our purpose under our Partnership Agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.  In addition, our Partnership Agreements provides that we will not acquire any oil and gas properties located outside the United States or offshore.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of acquiring, developing, producing, marketing and transporting producing oil and gas properties, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

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Power of Attorney

Each limited partner, and each person who acquires a common unit from a common unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our Partnership Agreement.

Cash Distributions

Our Partnership Agreement specifies the manner in which we will make cash distributions to holders of our common units as well as to our general partner in respect of its general partner interest and its incentive distribution rights and the holders of class B units.  See “Capital Contributions and Distributions”.

Capital Contributions

Common unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability”.  The general partner will make only a nominal capital contribution to our Partnership.  No cash capital contributions will be made with respect to the incentive distribution rights or class B units.

Voting Rights

The following is a summary of the voting rights of the holders of common units.  A common unit majority is a vote or consent by the holders of a majority of the common units then outstanding.  None of the incentive distribution rights or class B units have the right to vote on Partnership matters, except with respect to the incentive distribution rights and class B units for amendments to the Partnership Agreement that would adversely affect such limited partner interests, in which case the holder of the incentive distribution rights and class B units will have a right to vote thereon as a separate class.

Issuance of additional common units	No approval right prior to the end of the offering period, provided that the Partnership may issue no more than 100,263,158 common units.  Any common units issued after the offering period or if we were to propose to issue common units in excess of 100,263,158 common units would require an amendment to our Partnership Agreement, which must be approved by the general partner and the holders of a majority of the common units, including any common units held by our general partner and its affiliates.
Amendment of the Partnership Agreement	Certain amendments may be made by the general partner without the approval of the common unitholders. Other amendments generally require the approval of the holders of a majority of our common units (including common units held by the general partner and its affiliates) which we refer to as a “common unit majority.”  If the amendment materially adversely affects the rights of holders of incentive distribution rights or class B units, the amendment must also be approved by the holders of a majority of the incentive distribution rights or class B units. Please read “— Amendment of the Partnership Agreement”.
Merger of our Partnership or the sale of all or substantially all of our assets	Common unit majority and the holder of a majority of the incentive distribution rights or class B units in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets”.
Dissolution of our Partnership	Common unit majority. Please read “— Termination and Dissolution”.
Continuation of our business upon dissolution	Common unit majority. Please read “— Termination and Dissolution”.

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Withdrawal of our general partner	Our general partner does not have the right to withdraw as our general partner without the consent of the holders of a majority of our common units other than common units owned by our general partner and its affiliates.  Please read “— Withdrawal or Removal of the General Partner”.
Removal of our general partner	Holders of our common units do not have the right to remove our general partner.  Please read “— Withdrawal or Removal of the General Partner”.
Transfer of the general partner interest	Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our common unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party.  See “— Transfer of General Partner Interest”.
Transfer of incentive distribution rights	Our general partner has agreed not to transfer the incentive distribution rights for three years following the end of the offering period. Please read “— Transfer of Incentive Distribution Rights”.
Transfer of ownership interests in our general partner	Our general partner has agreed that it will not permit a change of control of the general partner to occur. Please read “— Transfer of Ownership Interests in the General Partner”.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the Partnership Agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

· to approve some amendments to the Partnership Agreement; or

· to take other action under the Partnership Agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the Partnership Agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the Partnership Agreement.

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Our subsidiaries will conduct business in states other than Delaware. Maintenance of our limited liability as an owner of our subsidiaries may require compliance with legal requirements in the jurisdictions in which the subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our Partnership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to approve some amendments to the Partnership Agreement, or to take other action under the Partnership Agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

The only interests the Partnership may issue are the general partner interests, the common units, up to a maximum of 100,263,158, the incentive distribution rights and the class B units.  Except as provided below, the Partnership may not issue additional common units following the offering period and the Partnership may not issue additional class B units without the consent of the holder(s) of a majority of the then outstanding class B units.  However, the general partner may cause the Partnership to issue to any person who performs services for the Partnership a number of class B units equal to the number of class B units canceled in connection with termination of the Management Agreement.  

Amendment of the Partnership Agreement

General.

Amendments to our Partnership Agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a common unit majority.

Prohibited Amendments.

No amendment may be made that would:

· enlarge the obligations of any limited partner without its consent; or

· enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option; or

· materially adversely affect the rights of the holders of the incentive distribution rights or class B units without the consent of the holders of a majority of the incentive distribution rights or class B units, as applicable; provided that if such amendment to the Partnership Agreement is made in connection with a Liquidity Event, such consent by the holders of incentive distribution rights or class B units may not be unreasonably withheld.

No Common Unitholder Approval.

Our general partner may generally make amendments to our Partnership Agreement without the approval of any limited partner or assignee to reflect:

· a change in our name, the location of our principal place of our business, our registered agent or our registered office;

· the admission, substitution, withdrawal or removal of partners in accordance with our Partnership Agreement;

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· a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor our wholly-owned operating subsidiary will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

· an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA;

· any amendment expressly permitted in our Partnership Agreement to be made by our general partner acting alone;

· an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our Partnership Agreement;

· any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our Partnership Agreement;

· a change in our fiscal year or taxable year and related changes;

· conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

· any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our Partnership Agreement without the approval of any limited partner if our general partner determines that those amendments:

· do not adversely affect the limited partners in any material respect;

· are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

· are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

· are necessary or appropriate for any action taken by our general partner relating to splits or combinations of common units under the provisions of our Partnership Agreement; or

· are required to effect the intent expressed in this prospectus or the intent of the provisions of our Partnership Agreement or are otherwise contemplated by our Partnership Agreement.

Opinion of Counsel and Common Unitholder Approval.

Our general partner will not be required to obtain an opinion of counsel that an amendment proposed by our general partner will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our Partnership Agreement will become effective without the approval of holders of at least 90% of the outstanding common units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding common units constitute not less than the voting requirement sought to be reduced.

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, the Partnership Agreement generally prohibits our general partner without the prior approval of the holders of a common unit majority from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries.  In addition, if the sale of assets or merger, consolidation or other combination would result in an amendment to our Partnership Agreement that is materially adverse to the holders of incentive distribution rights or class B units, the sale of assets, merger, consolidation or other combination will require approval of the holders of a majority of incentive distribution rights or class B units, as the case may be, which approval may not be unreasonably withheld.  Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

If the conditions specified in the Partnership Agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the Partnership Agreement. The common unitholders are not entitled to dissenters’ rights of appraisal under the Partnership Agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our Partnership Agreement. We will dissolve upon:

· the election of our general partner to dissolve us, if approved by the holders of common units representing a common unit majority;

· there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

· at any time after 90% of the net proceeds from the sale of common units (after deduction of sales commissions, marketing fees and offering and organization expenses), the election of our general partner to cause us to dissolve at any time that the present value of our after tax cash flows, discounted at 10%, from estimated net proved reserves at the end of any year falls below 20% of the net proceeds from our sale of common units;

· the entry of a decree of judicial dissolution of our partnership; or

· the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our Partnership Agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a common unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our Partnership Agreement by appointing as a successor general partner an entity approved by the holders of common units representing a common unit majority, subject to our receipt of an opinion of counsel to the effect that:

· the action would not result in the loss of limited liability of any limited partner; and

· neither our partnership, nor our wholly-owned operating subsidiary would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

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Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner, take such actions that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation in the same manner that we distribute cash at the end of each quarter. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Our general partner may not withdraw as general partner without the consent of holders of a majority of the common units, other than common units held by the general partner and its affiliates.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a common unit majority may select a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a common unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution”.

Our general partner may not be removed by the holders of common units.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

· an affiliate of our general partner (other than an individual); or

· another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer its general partner interest in our Partnership without the consent of a common unit majority.  As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our Partnership Agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer common units to one or more persons, without common unitholder approval.

Transfer of Ownership Interests in the General Partner

Our general partner has agreed not to undergo a change of control.  A change of control is defined as any person or group of persons, other than “qualifying owners”, acquiring beneficial ownership of 50% or more of the outstanding membership interests in the general partner.  A qualifying owner is generally defined as the current beneficial owners of the general partner and any conservator, guardian or similar person of such existing beneficial owner, and any trust, foundation or similar organization the beneficiaries of which include the existing beneficial owner.

Transfer of Incentive Distribution Rights and Class B Units

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the holders of a majority of the common units.  The general partner may not otherwise transfer the incentive distribution rights for three years following the final closing date, without the consent of a unit majority.

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Incentive Holdings, its affiliates or a subsequent holder may transfer its class B units to an affiliate of the holder or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the holders of a majority of the common units.  Incentive Holdings may not otherwise transfer the incentive distribution rights for three years following the final closing date, without the consent of a unit majority.

Meetings; Voting

Record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of common unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the common unitholders may be taken either at a meeting of the common unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of common units necessary to authorize or take that action at a meeting. Meetings of the common unitholders may be called by our general partner or by common unitholders owning at least 20% of the outstanding common units.  Common unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding common units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the common unitholders requires approval by holders of a greater percentage of the common units, in which case the quorum will be the greater percentage.

Each record holder of a common unit has one vote.  Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our Partnership Agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our Partnership Agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability” , the common units will be fully paid, and common unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the common units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his common units and may not receive distributions in-kind upon our liquidation.

Indemnification

We will indemnify the following persons under our Partnership Agreement:

· Our general partner,

· Any former general partner, and

· Any director, officer, member, partner, fiduciary or trustee of any of the foregoing entities.

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Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our Partnership Agreement.

Reimbursement of Expenses

Our Partnership Agreement requires us to reimburse our general partner for all direct out of pocket expenses it incurs or payments it makes on our behalf.  We will not reimburse or otherwise pay our general partner for any internal costs of our general partner, or its affiliates, such as overhead, salary, benefits and similar costs.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a common unit with information reasonably required for tax reporting purposes as soon as available after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to common unitholders will depend on the cooperation of common unitholders in supplying us with specific information. Every common unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our Partnership Agreement provides that a limited partner may, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

· a current list of the name and last known address of each partner;

· information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

· copies of our Partnership Agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

· information regarding the status of our business and financial condition; and

· any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.  Our Partnership Agreement provides that partners do not have the right to review our books and records for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or certain of its affiliates relating to the affairs of the Partnership.

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Governing Law, Venue and Jurisdiction

The Partnership Agreement is governed by the laws of the State of Delaware without regard to the principles of conflicts of law.  Under the terms of the Partnership Agreement, each partner and each person holding any beneficial interest in the Partnership agree that any claims arising under the Partnership Agreement or related to the Partnership shall be exclusively brought in the Court of Chancery of the State of Delaware, provided, however that any claims over which the Court of Chancery of the State of Delaware does not have jurisdiction shall be brought in any other court in the State of Delaware having jurisdiction.  The terms of the Partnership Agreement also provide that each partner irrevocably submits to the exclusive jurisdiction of the courts of the State of Delaware in connection with any claims pursuant to the Partnership Agreement.
 

TRANSFERABILITY OF INTERESTS

Lack of Liquidity in Investment in Common Units

The common units will not be listed for trading or quotation on any securities exchange or other market, and you may have difficulty selling your common units.  The common units are an illiquid investment, and purchasers should be able to hold their common units indefinitely.

Conditions to Becoming a Substitute Partner

An assignee of a common unit will not be entitled to any of the rights granted to a partner under the Partnership Agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner.  In general, an assignee of a common unit will become a substitute limited partner upon acquisition of a common unit.

A substitute partner is entitled to all of the rights of full ownership of the assigned common units, including the right to vote.

As of April 28, 2016 the common units were held by approximately 1,800 unitholders.

PLAN OF DISTRIBUTION

We are selling the common units using the services of David Lerner Associates, Inc. as the managing dealer. David Lerner Associates, Inc. is not affiliated with us. The common units are being offered on a “best efforts” basis, meaning that the managing dealer is not obligated to purchase any common units. No common units were to be sold unless at least a minimum of 1,315,790 common units were sold no later than two years after the date of this prospectus. That minimum was met on August 19, 2015.

The common units were offered at $19.00 per common unit until 5,263,158 ($100,000,000) common units are sold. Since this number of common units has been sold, the common units are now being offered at $20.00 per common unit.

On the sale of 5,263,158 common units, each of Glade M. Knight, David McKenney, Anthony “Chip” F. Keating III, and Michael J. Mallick or an affiliate of such individuals, purchased 5,000 common units at $20.00 per common unit from us. Each of Messrs. Knight, McKenney, Keating and Mallick undertakes not to sell his common units (other than to an affiliate, as defined in our bylaws) so long as he is an officer and director of us.

Neither prospective investors nor common unitholders should assume that the per-common unit prices reflect the intrinsic or realizable value of the common units or otherwise reflect our value, earnings or other objective measures of worth. If we were to list the common units on a national securities exchange, the common unit price might drop below our common unitholders’ original investment.

The offering of common units is expected to terminate when all common units offered by this prospectus have been sold or January 23, 2017, unless extended by us for up to an additional three months in order to achieve the maximum offering of 100,263,158 common units.

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Purchasers will be sold common units at one or more closings. Investors should make their checks payable to “David Lerner Associates, Inc.” and David Lerner Associates, Inc. will transmit funds directly to us at the next monthly closing date.  We plan to have additional closings monthly during the offering period as orders are received. The final closing will be held shortly after the termination of the offering period or, if earlier, upon the sale of 100,283,158 common units. It is expected that purchasers will be sold common units no later than the last day of the calendar month following the month in which their orders are received. Funds received during the offering but after the initial disbursement of funds will be held in purchasers’ accounts with David Lerner Associates, Inc. until the next closing, and then disbursed to us.

In no event are we required to accept the subscription of any prospective investor, and no subscription shall become binding on us until a properly completed subscription agreement prepared and executed by the prospective investor has been accepted by our duly authorized representative, David Lerner Associates, Inc. By executing the subscription agreement, the investor is not waiving any rights under the Securities Act of 1933.

Investors’ funds will be held in each purchaser’s account with David Lerner Associates, Inc. or other broker-dealers pending each applicable closing.

Each investor who desires to purchase common units will be required to complete and sign a subscription agreement in the form attached to this prospectus as Exhibit B. In addition to requesting basic identifying information concerning the investor, such as his or her name and address, the number of common units subscribed for, and the manner in which ownership will be held, the subscription agreement requires the investor to make a series of representations to us set forth in paragraphs designated “(a)” through “(h).”

We ask for these representations to help us determine whether you have received the disclosure materials pertaining to the investment, meet certain suitability requirements we have established, and understand what you are investing in. Should a dispute later arise between you and us concerning matters that are the subject of any representation, we would expect to rely upon your making of that representation in the subscription agreement if you later claim that that representation is not correct.

We have established suitability standards in determining whether we should accept a subscription agreement from any purchaser.  Each purchaser of common units must certify that he or she has either:

· a minimum annual gross income, or joint income with a spouse, of $45,000 and a net worth, or joint net worth with his or her spouse, (exclusive of equity in home, home furnishings and personal automobiles) of at least $45,000, or

· a net worth (similarly defined), or joint net worth with his or her spouse, of at least $150,000

These standards impose minimum income and net worth standards that we believe are reasonable considering our planned business activities and the risks associated with a purchase of the common units. These risks are summarized under “Risk Factors.”

We will require each purchaser to review and complete a subscription agreement in which he or she will represent that he meets the applicable suitability standards described above. The form of the subscription agreement is attached as Exhibit B.  We and David Lerner Associates, Inc. rely on the representations made by the purchaser in the subscription agreement in assuring adherence to these suitability standards.

Set forth below is a brief summary of the nature of each representation in the lettered paragraphs of the subscription agreement. You should, however, carefully review the subscription agreement in its entirety.

(a) You acknowledge that you have received a copy of the prospectus and that you understand that your investment will be governed by the terms of that prospectus.

(b) You represent that you are of majority age and, therefore, can enter into a binding contract to purchase the common units.

(c) You represent that you have adequate financial resources, understand the financial risks of an investment in common units, and understand that there is no ready ability to sell or otherwise dispose of your investment in common units.

(d) You specifically represent that you either have a net worth (excluding home, furnishings and automobiles) of at least $45,000 and gross income of $45,000, or a net worth (with the same exclusions) of at least $150,000. This representation helps us determine that your proposed investment is suitable for you based on your financial condition.

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(e) If you are acting on behalf of an entity, you represent that you have authority to bind the entity.

(f) You represent that the taxpayer identification number (social security number in the case of an individual) provided is correct and that you are not subject to backup withholding. This representation allows us to make distributions to you without any requirement to withhold for income tax purposes.

(g) You understand that we have the right, in our sole discretion, to accept or reject your subscription for common units.

(h) You agree to settle by arbitration any controversy between you and your broker concerning the subscription agreement and the investment represented by the subscription agreement.

Funds not invested in oil and gas properties may be invested by us only in:

(a) bank accounts, including savings accounts and bank money market accounts (as bank is defined in Section 3(a)(6) of the Securities Exchange Act of 1934) (including bank money market accounts managed by the escrow agent and its affiliates);

(b) short-term direct obligations of the United States of America or obligations the principal of and the interest on which are unconditionally guaranteed by the United States of America;

(c) short-term certificates of deposit issued by any bank (as defined in Section 3(a)(6) of the Securities Exchange Act of 1934) (including the escrow agent and its affiliates) located in the United States and having net worth of at least $50,000,000; or

(d) similar highly liquid investments to the extent permitted by applicable laws and regulations.

We will pay to David Lerner Associates, Inc. selling commissions on all sales made in an amount equal to 5% of the purchase price of the common units or $0.95 per common unit sold for $19.00 prior to selling 5,263,158 common units and $1.00 per common unit purchased for $20.00 thereafter.  We also will pay to David Lerner Associates, Inc. a marketing expense allowance equal to 1% of the purchase price of the common units, as a non-accountable reimbursement for expenses incurred by it in connection with the offer and sale of the common units. The marketing expense allowance will equal $0.19 per common unit sold for $19.00 prior to reaching 5,263,158 common units and $0.20 per common unit purchased for $20.00 thereafter. The maximum selling commission payable to David Lerner Associates, Inc. is $100,000,000. The maximum marketing expense allowance payable to David Lerner Associates, Inc. is $20,000,000. The selling commissions and marketing expense allowance are payable to David Lerner Associates, Inc. at the times of the issuance of common units to purchasers.

 David Lerner Associates, Inc. will provide the following services to us until the offering termination date: (i) maintain up-to-date contact and other information regarding its customers who are common unitholders and make such information available to us upon request, (ii) assist us in communicating with common unitholders and (iii) coordinate the ongoing provision of information regarding the partnership to common unitholder as may be required or desirable from time to time.  For providing such services, David Lerner Associates, Inc. will be paid (i) an initial one-time fee of $5 for each of its customer who acquires common units and (ii) an annual fee of $10 per such customer.  The total of these account maintenance fees will not exceed $500,000.

The following table reflects the compensation payable to David Lerner Associates, Inc. for the offer and sale of the common units (see “Compensation” for a further discussion of compensation):

	Price To Public(1)		Commissions(2)		Marketing Expense Allowance
Per common unit	$	20.00	$	1.00	$	0.2000
Total maximum offering	$	2,000,000,000	$	100,000,000	$	20,000,000

1. The initial 5,263,158 common units were sold at a per common unit price of $19.00 per common unit, with the commissions at $0.95 per common unit and the marketing expense allowance of $0.19 per common unit.

2. We will pay the dealer manager a contingent, incentive fee based on the amount of distributions made by the Partnership after Payout occurs.  The contingent, incentive fee will be payable solely in cash and will not exceed 4% of the gross proceeds of the offering of common units.  The contingent, incentive fee will not exceed $1,000,000 and if the maximum offering is achieved the fee will not exceed $80,000,000.  The maximum amount of the contingent, incentive fee will be reduced by the amount of any account maintenance fees paid to David Lerner Associates, Inc.

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The dealer manager or other broker-dealers will not purchase common units from us.

The exclusive dealer manager agreement between us and David Lerner Associates, Inc. permits David Lerner Associates, Inc. to use the services of other broker-dealers in offering and selling the common units, subject to our approval.  However, no such broker-dealers have been identified or approved at this time and none will be employed prior to the initial sale of common units.  If any other broker-dealers are engaged to offer common units, David Lerner Associates, Inc. will pay the compensation owing to the broker-dealers out of the selling commissions or marketing expense allowance payable to it. Sales by the broker-dealers will be carried on in accordance with customary securities distribution procedures. David Lerner Associates, Inc. may be deemed to be an “underwriter” for purposes of the Securities Act of 1933 in connection with this offering.

David Lerner Associates, Inc. is a member of FINRA. Any other broker-dealers allowed to sell common units will be FINRA members. The maximum total underwriting compensation from any source that we will pay to David Lerner Associates, Inc. or any other FINRA member firm or their affiliates will not exceed 10% of the gross proceeds of this offering.

Purchasers are required to purchase a minimum of $5,000 in common units.  Existing common unitholders may purchase additional common units pursuant to procedures and minimum amounts established by David Lerner Associates, Inc. In addition, upon the sale of 5,263,158 common units, each of the four principals of our general partner (or their affiliates) purchased in this offering 5,000 common units for $20.00 per common unit, on the same terms and conditions as the public.  The four principals will be permitted to vote on any matters submitted to a vote of holders of the common units. All purchases of common units in this offering by the four principals of our general partner must be for investment, and not for resale or distribution.

There has been no previous market for any of our common units. The initial offering price for the common units is arbitrary and was determined on the basis of our proposed capitalization, market conditions and other relevant factors.

We have agreed to indemnify David Lerner Associates, Inc. against a limited number of liabilities under the Securities Act of 1933, as amended. These liabilities include liabilities arising out of untrue statements of a material fact contained in this registration statement or arising out of the omission of a material fact required to be stated in this registration statement. We will also indemnify David Lerner Associates, Inc. for losses from a breach of any warranties made by us in the agency agreement.

FINRA Action

In connection with the resolution of two FINRA disciplinary actions, on October 22, 2012, David Lerner Associates, Inc., without admitting or denying, agreed to pay fines and restitution totaling $14 million.  Of that amount, David Lerner Associates, Inc. agreed to pay approximately $12 million in restitution to certain investors in Apple REIT Ten, a real estate investment trust formed by affiliates of two of the owners of our general partner. In addition, David Lerner, individually, without admitting or denying, was fined $250,000 and suspended for one year from the securities industry, followed by a two year suspension from acting as a principal.  While the order also imposed sanctions and penalties and fines on both David Lerner Associates, Inc. and David Lerner, individually, the order does not prohibit David Lerner Associates, Inc. from serving as the managing dealer for our best-efforts offering of common units. We do not believe this settlement will affect the administration of our common units.

In the disciplinary actions, FINRA alleged that David Lerner Associates, Inc. failed to conduct adequate due diligence with respect to Apple REIT Ten, thereby leaving it without a reasonable basis for recommending customer purchases of Apple REIT Ten, in addition to using false, exaggerated and misleading statements regarding the performance of earlier closed Apple REIT programs.  FINRA also alleged that David Lerner Associates, Inc. made false, exaggerated and misleading communications to the public, through customer correspondence and investment seminars, about the investment returns, market values, performance of earlier closed Apple REITs as well as untrue statements and/or omitted material facts concerning the prior performance, steady distribution rates, unchanging valuations, and prospects of the earlier closed Apple REITs and/or Apple REIT Ten.

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SUBSCRIPTIONS

Minimum Investment

The minimum number of common units you can purchase is 250 common units for $5,000.

Subscriber Representations and Subscription Procedures

Each potential investor must sign the subscription agreement found on pages B-1 to B-4. The partnership will promptly review each subscription and will accept or decline to accept you as limited partner in its sole and absolute discretion. If your subscription is accepted, you will be given prompt written confirmation of your admission to the partnership.

By your signature on the signature page of the subscription agreement (on page B-4), you are indicating your desire to become a limited partner and to be bound by all the terms of the Partnership Agreement. You also appoint the general partner to be your true and lawful attorney-in-fact to sign documents, including the Partnership Agreement, which may be required for your admission to the partnership.

Your signature and initials on the signature page of the subscription agreement also serve as your affirmation that the acknowledgments, agreements and representations printed in that section on page B-1 to B-3 of the subscription agreement are true, by which you confirm, among other things, that:

· you have received a copy of the prospectus at least five business days before tendering your subscription;

· you have read the Important Information for Subscriber(s) on page B-3 of the subscription agreement;

· you acknowledge that an investment in the common units is not a liquid investment;

· you affirm that the partnership may rely on the accuracy of the factual data about yourself that you report in the subscription agreement, including your representation that:

(a)           if you are purchasing common units for an IRA, you have accurately identified the subscriber as such;

(b)            you have accurately identified yourself, or the investing entity, as a U.S. citizen, resident in the U.S. or Puerto Rico (individuals only) or a U.S. resident alien, having determined such status in the manner described below;

(c)            you have accurately reported your social security number or the federal taxpayer identification number of the investing entity;

(d)            you are not subject to backup withholding of federal income taxes; and

(e)            you agree to redeem all of your common units if you are no longer a U.S. citizen with a resident address in the United States or Puerto Rico (individuals only) or a resident alien, or if you otherwise are or become a foreign partner for purposes of Section 1446 of the Code at any point while holding Interests;

· you meet the minimum income and net worth standards established by us; and

· you are purchasing common units for your own account and not with a view to distribution.

The partnership will require that everyone who wishes to purchase the common units make these representations in order to assist FINRA ­registered securities sales representatives, selling dealers and the dealer manager in determining whether this investment is suitable for each subscriber. The partnership will rely upon the accuracy and completeness of your representations in the subscription agreement in complying with its obligations under state and federal securities laws.

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The subscription agreement asks that you acknowledge receipt of this prospectus and of the instruction to rely only on information contained in this prospectus and certain related materials, including supplements to the prospectus and promotional brochures marked as being prepared by the partnership or by the dealer manager for use in connection with this offering, so that the partnership may make an informed judgment as to whether it should accept your offer to subscribe for the common units. While the partnership recognizes that in the sales process a potential investor will usually discuss an investment in the common units with his or her broker, it is possible that you may misunderstand what you are told or that someone might tell you something different from, or contrary to, the information contained in this prospectus. You might also read or hear something that contradicts the information contained in this prospectus.

If you become a limited partner and later make a claim against the partnership, the general partner and/or the dealer manager alleging that you did not receive a prospectus for this offering, or that although you received a prospectus you relied on information that is contradictory to that disclosed in this prospectus, then the partnership and its affiliates anticipate relying on the representations you made in your subscription agreement. Your signature on the subscription agreement is your acknowledgment that you received this prospectus and the instructions to rely exclusively on the information contained in the prospectus in making your investment decision. Do not sign the subscription agreement if you do not understand this section.

Instruction Concerning “Important Information”

The Important Information on page B-3 of the subscription agreement asks you to review the disclosures in this prospectus concerning certain conflicts of interest the partnership faces, certain risks involved in this investment and the management of the general partner.  These disclosures are found in the sections entitled “Risk Factors,” “Conflicts of Interest,” “Management” and “Federal Income Tax Consequences.”

The partnership included this instruction because, as this investment involves inherent conflicts of interest and risks, the partnership does not intend to admit you unless it has reason to believe that you are aware of the risks involved in this investment. If you become a limited partner and later make claims against the partnership, the general partner and/or the dealer manager to the effect that you were not aware that this investment involved the inherent risks described in this prospectus, the partnership, the general partner, and the dealer manager anticipate relying on this instruction as evidence that you were aware of the risks involved in this investment.

Binding Effect of the Limited Partnership Agreement on You

The representation in the subscription agreement that you have agreed to all the terms and conditions of the Partnership Agreement is necessary because the general partner and every limited partner are bound by all of the terms and conditions of that agreement, notwithstanding the fact that investors do not actually sign the partnership agreement. Though you do not actually sign the Partnership Agreement, your signature on the subscription agreement gives the general partner the power of attorney pursuant to which it obligates you to be bound by each of the terms and conditions of the Partnership Agreement. If you become a limited partner and later make claims against the partnership, the general partner and/or the dealer manager that you did not agree to be bound by all of the terms of the Partnership Agreement and the subscription agreement, the partnership, the general partner and/or the dealer manager anticipate relying on your representation and on the power of attorney as evidence of your agreement to be bound by all of the terms of the Partnership Agreement and the subscription agreement.

Your Citizenship and Residency

All investors will be required to represent and warrant that they are either a United States citizen or a resident alien, each with an address in the United States. The partnership will not admit anyone who is either a United States citizen living outside of the United States or a non-resident of the United States. An investor will be required to tender to the partnership for sale, upon demand, all of its common units if such investor is no longer a United States citizen, resident in the United States or Puerto Rico (individuals only), or a resident alien or if an investor otherwise is or becomes a foreign partner for purposes of Section 1446 of the Code at any time while it is holding common units.

You will also be required to represent to us your state of residence.

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Co-Signature By Selling Dealer

Selling dealers must countersign each subscription agreement for subscribers solicited by their firm. By this signature, the selling dealer certifies that it has obtained information from the potential investor sufficient to enable the selling dealer to determine that the investment is suitable for the investor based on the investor’s income, net worth and other characteristics. Since the general partner and the dealer manager will not have had the opportunity to obtain financial and other relevant information directly from you, the general partner and the dealer manager will rely on the selling dealer’s representation to determine whether to admit you as a limited partner (as you designate in your subscription agreement). If you become a limited partner and later make claims against the Partnership, the general partner and/or the dealer manager alleging that the common units were not a suitable investment because you did not meet the financial requirements contained in the investor suitability standards, the partnership, the general partner and the dealer manager anticipate relying upon the selling dealer’s representation (and your representation) as evidence that you did meet the financial requirements for this investment. FINRA’s Conduct Rules require that any person associated with the dealer manager or a selling dealer who sells or offers to sell common units must make every reasonable effort to ensure that a potential subscriber is a suitable investor for this investment in light of such subscriber’s age, education level, knowledge of investments, need for liquidity, net worth and other pertinent factors.

How to Subscribe

If you are an individual investor, you must personally sign the subscription agreement and deliver it, together with a check for all subscription monies payable in connection with your subscription, to a selling dealer. In the case of IRA, the trustee or custodian must also sign the subscription agreement. In the case of donor trusts or other trusts in which the donor is the fiduciary, the donor must sign the subscription agreement. In the case of other fiduciary accounts in which the donor neither exercises control over the account nor is a fiduciary of the account, the plan fiduciary alone may sign the subscription agreement.

Checks for the purchase of common units should be made payable to “David Lerner Associates, Inc.” for deposit in the subscriber’s brokerage account and David Lerner Associates will transmit a subscriber’s funds to the partnership on the next monthly closing date.

SALES MATERIAL

In addition to this prospectus, the Partnership may use sales material in connection with the offering of its common units. In some jurisdictions, sales material may not be available. This material will include information relating to this offering, the general partner and to its affiliates, and may include brochures, articles, presentations for group meetings and publications about the oil and gas industry and oil and gas drilling partnerships. All advertisements of, and oral or written invitations to seminars or other group meetings at which common units are to be described, offered or sold will clearly indicate that the purpose of such meeting is to offer such common units, for sale, the minimum purchase price thereof, the suitability standards to be employed, and the name of the person selling the common units. If required by regulatory agencies, the Partnership will submit supplementary materials, including prepared presentations for group meetings, in advance of use, to such agencies, and will use only sales material that they have approved. The offering of the common units, however, is made only by means of this prospectus and all sales material used must either be preceded by or accompanied with this prospectus. Although the information contained in the sales material does not conflict with any of the information contained in this prospectus, the material does not purport to be complete and should not be considered as a part of this prospectus or the registration statement of which this prospectus is a part, or as incorporated in this prospectus by reference or as forming the basis of this offering of the common units.

LEGAL OPINIONS

Haynes and Boone, LLP will opine on the validity of the issuance of the common units and has provided us with an opinion on certain tax matters set forth under “Material Federal Income Tax Consequences.”

CHANGE IN ACCOUNTING FIRM

The financial statements of Energy 11, L.P. as of December 31, 2013 and July 9, 2013 (initial capitalization) and for the period from July 9, 2013 (initial capitalization) through December 31, 2013 appearing in the Prospectus and the Registration Statement, have been audited by Ernst & Young, LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

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On March 18, 2015, the Partnership replaced Ernst & Young LLP as the Partnership’s independent registered public accounting firm for the year ended December 31, 2014.

Ernst & Young’s audit report on the Partnership’s consolidated financial statements as of December 31, 2013 and for the period from July 9, 2013 through December 31, 2013 did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope or accounting principles.

Since the Partnership’s establishment in June 2013 and through March 18, 2015, (i) there were no disagreements between the Partnership and Ernst & Young on any matters of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Ernst & Young, would have caused Ernst & Young to make reference to the subject matter of the disagreement in its report on the Partnership’s consolidated financial statements, and (ii) there were no “reportable events” as that term is defined in Item 304(a)(1)(v) of Regulation S-K.

The Partnership has provided Ernst & Young with a copy of the foregoing statements and has requested and received from Ernst & Young a letter addressed to the SEC stating that Ernst & Young agrees with the above statements.

The Partnership has not consulted with Grant Thornton LLP during the two most recent fiscal years or during any subsequent interim period prior to its appointment regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that might be rendered on our financial statements, and neither a written report was provided to the Partnership nor oral advice was provided that Grant Thornton LLP concluded was an important factor considered by the Partnership in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a reportable event (within the meaning of Item 304(a)(1)(v) of Regulation S-K).

EXPERTS

 The consolidated financial statements of Energy 11, L.P. at December 31, 2013, and for the period from July 9, 2013 (initial capitalization) through December 31, 2013, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing. On March 18, 2015, the Partnership replaced Ernst & Young LLP as the Partnership’s independent registered public accounting firm for the year ended December 31, 2014.

The audited financial statements of the Partnership as of December 31, 2015 and 2014 and for the years then ended included in this Prospectus and elsewhere in the Registration Statement, have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The combined statements of revenues and direct operating expenses of the Sanish Field Assets for the years ended December 31, 2014, 2013 and 2012 appearing in the prospectus and the Registration Statement, have been audited by HoganTaylor LLP, independent auditor, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

ADDITIONAL INFORMATION

A registration statement on Form S-1 under the Securities Act of 1933, as amended, has been filed with the SEC, Washington, D.C., with respect to the common units. This prospectus, which forms a part of the registration statement, contains information concerning the Partnership and includes a copy of the Partnership Agreement, but it does not contain all the information set forth in the registration statement and its exhibits. The information omitted may be examined at the public reference room of the SEC located at 100 F Street, N.E., Washington, D.C. 20549 (1-800-SEC-3030), without charge, and copies may be obtained from that office upon payment of the fee prescribed by the rules and regulations of the SEC. Additionally, it can be viewed via the website of the SEC at http://www.sec.gov. The Partnership will file periodic reports with the SEC, copies of which will be available on our website at http://www.energyeleven.com.  The information on our website does not constitute a part of this prospectus.

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INFORMATION INCORPORATED BY REFERENCE

The SEC allows us to “incorporate by reference” into this prospectus the information we provide in other documents filed by us with the SEC. The information incorporated by reference is an important part of this prospectus and any prospectus supplement. Any statement contained in a document that is incorporated by reference in this prospectus is automatically updated and superseded if information contained in this prospectus and any prospectus supplement, or information that we later file with the SEC, modifies and replaces this information. We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Periodic Reports on Form 8-K that will be incorporated by reference. We incorporate by reference the documents listed below (unless otherwise stated, other than information furnished under Items 2.02 or 7.01 of any Form 8-K, which is not deemed filed):

· Our Annual Report on Form 10-K for the year ended December 31, 2015 filed on March 28, 2016; and

· Our Current Report on Form 8-K filed on April 7, 2016.

In addition, all documents filed by us with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (other than those furnished pursuant to Item 2.02 or Item 7.01 of Form 8-K, unless otherwise stated therein), including all such filings after the effective date of the registration statement of which this prospectus is a part, until all offerings under the registration statement of which this prospectus is a part are completed or terminated, will be considered to be incorporated by reference into this prospectus and to be a part of this prospectus from the dates of the filing of such documents. Pursuant to General Instruction B of Form 8-K, any information submitted under Item 2.02, Results of Operations and Financial Condition, or Item 7.01, Regulation FD Disclosure, of Form 8-K is not deemed to be “filed” for the purpose of Section 18 of the Exchange Act, and we are not subject to the liabilities of Section 18 with respect to information submitted under Item 2.02 or Item 7.01 of Form 8-K. We are not incorporating by reference any information submitted under Item 2.02 or Item 7.01 of Form 8-K into any filing under the Securities Act or the Exchange Act or into this prospectus, unless otherwise indicated on such Form 8-K.

You may get copies of this prospectus or any of the incorporated documents (excluding exhibits, unless the exhibits are specifically incorporated) at no charge to you by writing to the Corporate Secretary, Energy 11, L.P., 814 East Main Street, Richmond, VA 23219, or calling (804) 344-8121. Copies of the incorporated documents will be available on our website at http://www.energyeleven.com and also at the SEC at the locations described under “Additional Information” above.

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GLOSSARY OF OIL AND GAS TERMS

Completion.  Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Developed oil and gas reserves.  Reserves of any category that can be expected to be recovered:

· through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and

· through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.  An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploration well. A well drilled to find and produce oil or gas in an unproven area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Natural gas liquids. The hydrocarbon liquids contained within natural gas.

Oil. Crude oil and condensate.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

· costs of labor to operate the wells and related equipment and facilities;

· repairs and maintenance;

· materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

· property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

· severance taxes.

Productive well. An exploratory, development or extension well that is not a dry well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Reserve Life. A measurement of the time it will take to produce proved reserves attributable to a property calculated by dividing estimated net proved reserves attributable to the property by production from such property during the preceding 12 months.

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Reserves.  Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Standardized measure.  Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.  Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Undeveloped oil and gas reserves.  Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

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INDEX TO FINANCIAL STATEMENTS

	Page
Energy 11, L.P. Historical Consolidated Financial Statements:
Reports of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014	F-4
Consolidated Statements of Operations for the year ended December 31, 2015, the year ended December 31, 2014 and for the period July 9, 2013 (initial capitalization) through December 31, 2013	F-5
Consolidated Statements of Partners’ Equity (Deficit) for the year ended December 31, 2015, the year ended December 31, 2014 and for the period July 9, 2013 (initial capitalization) through December 31, 2013	F-6
Consolidated Statements of Cash Flows for the year ended December 31, 2015, the year ended December 31, 2014 and for the period July 9, 2013 (initial capitalization) through December 31, 2013	F-7
Notes to Financial Statements	F-8
Combined Statements of Revenues and Direct Operating Expenses of Properties under Contract for Purchase by Energy 11, L.P. from Kaiser-Whiting, LLC under Agreement dated September 15, 2015:
Independent Auditor’s Report	F-21
Combined Statements of Revenues and Direct Operating Expenses	F-23
Notes to Combined Statements of Revenues and Direct Operating Expenses	F-24
Energy 11, L.P. Unaudited Pro Forma Condensed Combined Financial Statement:
Introduction	F-27
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year ended December 31, 2015	F-28
Notes to Unaudited Pro Forma Condensed Combined Financial Statement	F-29

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

General Partner

Energy 11, L.P.

We have audited the accompanying balance sheets of Energy 11, L.P. (a Delaware limited partnership) (the “Partnership”) as of December 31, 2015 and 2014, and the related statements of operations, partners’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy 11, L.P. as of December 31, 2015 and 2014, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/S/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 28, 2016

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Managing General Partner of Energy 11, L.P.

We have audited the accompanying balance sheets of Energy 11, L.P. (the “Partnership”) as of December 31, 2013 and July 9, 2013 (initial capitalization), and the related consolidated statement of operations, partners’ equity and cash flows for the period July 9, 2013 (initial capitalization) through December 31, 2013.  These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above presents fairly, in all material respects, the financial position of Energy 11, L.P. at December 31, 2013 and July 9, 2013 (initial capitalization), and the results of its operations and its cash flows for the period July 9, 2013 (initial capitalization) through December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Richmond, Virginia

April 29, 2014

F-3

Energy 11, L.P.

Consolidated Balance Sheets

	December 31,			December 31,
	2015			2014
Assets
Cash	$	3,287,054		$	94
Accounts Receivable:
Oil, natural gas and natural gas liquids revenues		1,417,751			-
Acquisition post-closing receivable		1,556,530			-
Deferred offering costs and other assets		-			1,449,930
Total Current Assets		6,261,335			1,450,024
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization;  December 31, 2015, $391,624; December 31, 2014, $0		158,895,191			-
Total Assets	$	165,156,526		$	1,450,024
Liabilities and Partners’ Equity (Deficit)
Note payable	$	81,684,758		$	-
Due to general partner member		-			1,232,675
Contingent Consideration		4,743,752			-
Accounts payable and accrued expenses		3,449,442			390,000
Total Current Liabilities		89,877,952			1,622,675
Limited partners' interest (4,486,625 common units and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively)		75,280,301			(170,924	)
General partner's interest		(1,727	)		(1,727	)
Class B Units (100,000 units and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively)		-			-
Total Partners’ Equity (Deficit)		75,278,574			(172,651	)
Total Liabilities and Partners’ Equity (Deficit)	$	165,156,526		$	1,450,024

See accompanying notes to the financial statements.

F-4

Energy 11, L.P.

Consolidated Statements of Operations

	Year Ended December 31, 2015			Year Ended December 31, 2014			For the Period July 9, 2013 (initial capitalization) through December 31, 2013
Revenue
Oil, natural gas and natural gas liquids revenues	$	703,806		$	-		$	-
Expenses
Lease operating expenses		149,072			-			-
Gathering and processing expenses		18,139			-			-
Production taxes		74,460			-			-
Management fees		252,524			-			-
Acquisition related costs		313,366			-			-
General and administrative expenses		745,884			163,595			10,056
Depreciation, depletion and amortization		392,084			-			-
Total expenses		1,945,529			163,595			10,056
Operating loss		(1,241,723	)		(163,595	)		(10,056	)
Interest expense, net		321,093			-			-
Net loss	$	(1,562,816	)	$	(163,595	)	$	(10,056	)
Basic and diluted net loss per common unit	$	(1.70	)	$	-		$	-
Weighted average common units outstanding - basic and diluted		920,668			-			-

See accompanying notes to the financial statements.

F-5

Energy 11, L.P.

Consolidated Statements of Partners' Equity

	Limited Partners'			Class B Units		General Partner			Total Partners'
	Amount			Amount		Amount			Equity/(Deficit)
Initial Capitalization July 9, 2013	$	990		$	-	$	10		$	1,000
2013 Net Loss		(9,955	)		-		(101	)		(10,056	)
Balance December 31, 2013		(8,965	)		-		(91	)		(9,056	)
2014 Net Loss		(161,959	)		-		(1,636	)		(163,595	)
Balance December 31, 2014		(170,924	)		-		(1,727	)		(172,651	)
Net proceeds from issuance of common units		78,286,761			-		-			78,286,761
Distributions to organizational limited partner		(990	)		-		-			(990	)
Distributions declared and to common units paid ($0.510138 per unit)		(1,271,730	)		-		-			(1,271,730	)
2015 Net Loss		(1,562,816	)		-		-			(1,562,816	)
Balance December 31, 2015	$	75,280,301		$	-	$	(1,727	)	$	75,278,574

See accompanying notes to the financial statements.

F-6

Energy 11, L.P.

Consolidated Statements of Cash Flows

	For the Year Ended December 31, 2015			For the Year Ended December 31, 2014			For the Period July 9, 2013 (initial capitalization) through December 31, 2013
Cash flow from operating activities:
Net loss	$	(1,562,816	)	$	(163,595	)	$	(10,056	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization		392,084			-			-
Non-cash fair value adjusted amortization		175,424			-			-
Changes in operating assets and liabilities:
Increase in accounts receivable oil, natural gas and natural gas liquids		(703,806	)		-			-
Accounts payable and accrued expenses		653,106			-			-
Due to general partner member		(158,641	)		163,595			10,046
Net cash flow used in operating activities		(1,204,649	)		-			(10	)
Cash flow from investing activities
Cash paid for acquisition of oil, natural gas and natural gas liquids properties		(60,000,000	)		-			-
Net cash flow used in investing activities		(60,000,000	)		-			-
Cash flow from financing activities
Cash paid for offering costs		-			-			(896	)
Net proceeds related to issuance of units		78,308,749			-			-
Distributions paid to limited partners		(1,271,730	)		-			-
Payments on debt		(12,545,410	)		-			-
Net cash flow provided by (used in) financing activities		64,491,609			-			(896	)
Increase in cash and cash equivalents		3,286,960			-			(906	)
Cash and cash equivalents, beginning of period		94			94			1,000
Cash and cash equivalents, end of period	$	3,287,054		$	94		$	94
Interest paid	$	173,711		$	-		$	-
Supplemental non-cash information:
Accrued deferred offering costs and other assets	$	-		$	1,181,442		$	267,592
Note payable assumed in acquisition		97,545,410			-			-
Contingent consideration in acquisition		4,725,448			-			-
Deferred purchase price of acquisition		1,702,203			-			-
Accounts receivable from seller in acquisition, net of assumed payables		1,395,883			-			-

See accompanying notes to the financial statements.

F-7

Energy 11, L.P.

Notes to Financial Statements

December 31, 2015

(1)   Partnership Organization

Energy 11, L.P., together with its wholly owned subsidiary, (the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership is offering common units of limited partner interest (the “units”) on a “best efforts” basis with the intention of raising up to $2,000,000,000 of capital, consisting of 100,263,158 units. The Partnership’s offering was declared effective by the Securities and Exchange Commission (“SEC”) on January 22, 2015. As of August 19, 2015, the Partnership completed the sale of the minimum offering of 1,315,790 units. The subscribers were admitted as Limited Partners of the Partnership at the initial closing.

The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential, and to enhance the value of the properties through drilling and other development activities, (ii) make distributions to the holders of the units, (iii) engage in a liquidity transaction after five – seven years, in which all properties are sold and the sales proceeds are distributed to the partners, merge with another entity, or list the units on a national securities exchange, and (iv) permit holders of units to invest in oil and gas properties in a tax efficient basis. The proceeds from the sale of the units primarily have been and will be used to acquire producing and non-producing oil and natural gas properties onshore in the United States, and to develop those properties.

The General Partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. Pursuant to the terms of a management agreement, the Partnership has engaged E11 Management, LLC (the “Manager”), to provide management and operating services regarding substantially all aspects of the Partnership’s operations. David Lerner Associates, Inc. (the “Managing Dealer”), is the dealer manager for the offering of the units.

The Partnership’s fiscal year ends on December 31.

(2) Summary of Significant Accounting Policies

Basis of Presentation

The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).

Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Offering Costs

The Partnership is raising capital through an on-going best-efforts offering of units by David Lerner Associates, Inc., the managing underwriter, which receives a selling commission and a marketing expense allowance based on proceeds of the units sold. Additionally, the Partnership has incurred other offering costs including legal, accounting and reporting services. These offering costs are recorded by the Partnership as a reduction of shareholders’ equity. Prior to the commencement of the Partnership’s offering, these costs were deferred and recorded as prepaid expense. As of December 31, 2015, the Partnership had sold 4.5 million units for gross proceeds of $85.2 million and proceeds net of offering costs of $78.3 million.

F-8

Property and Depreciation, Depletion and Amortization

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Partnership’s accounts receivable are due from purchasers of oil, natural gas and NGLs or operators of the oil and natural gas properties. Oil, natural gas and NGL sales receivables are generally unsecured. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties we have an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2015, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. For the year ended December 31, 2015, the Partnership’s oil, natural gas and NGL sales were through two operators. Whiting Petroleum Corporation (“Whiting”) is the operator of 99% the Partnership’s properties. All oil and natural gas producing activities of the Partnership are conducted within the contiguous United States (North Dakota) and represent substantially all of the business activities of the Partnership.

F-9

Asset Retirement Obligation

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

The following table shows the activity for the year ended December 31, 2015, relating to the Partnership’s asset retirement obligations:

	2015
Asset retirement obligations as of beginning of the year	$	-
Liabilities acquired on December 18, 2015 (Acquisition)		105,000
Accretion of discount (December 18, 2015 to December 31, 2015)		459
Asset retirement obligations as of end of the year	$	105,459

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns will be subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

There are two principal accounting practices to account for natural gas imbalances. These methods differ as to whether revenue is recognized based on the actual sale of natural gas (sales method) or an owner’s entitled share of the current period’s production (entitlement method). We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances

F-10

of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2015, there were no such costs accrued.

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of crude oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of crude oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected future crude oil, natural gas and NGL prices as estimated by management are used. Crude oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of crude oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

Revenue Recognition

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Earnings (Loss) Per Common Unit

Basic earnings (loss) per common unit is computed as net loss divided by the weighted average number of common units outstanding during the period. Diluted earnings (loss) per unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no units with a dilutive effect for the three months and twelve months ended December 31, 2015 and 2014. As a result, basic and diluted outstanding units were the same. The Class B Units and Incentive Distribution Rights are not included in earnings (loss) per common unit until such time that it is probable Payout (as discussed in Note 5) would occur.

F-11

Recent Accounting Standard

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard is effective for us on January 1, 2019. Early adoption is not permitted. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We are currently evaluating the transition method that will be elected and the impact, if any, on the Partnership’s financial statements.

In April 2015, the FASB issued an accounting standards update on the presentation of debt issuance costs. The 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. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on the Partnership’s financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. The standard is effective for annual periods beginning after December 15, 2018, and interim periods within those years, with early adoption permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is currently evaluating the impact of adopting the new standard on its consolidated financial statements.

(3) Oil and Gas Investments

On September 15, 2015, the Partnership entered into an Interest Purchase Agreement (“Purchase Agreement”) by and among Kaiser-Whiting, LLC and the owners of all the limited liability company interests therein (the “Sellers”), for the purchase of the Sanish Field Assets.

Pursuant to the Purchase Agreement as amended, the purchase price for the Sanish Field Assets consisted of (i) $60 million in cash, subject to customary adjustments, (ii) an aggregate of $2 million, payable in equal amounts on December 31, 2016 and December 31, 2017, (iii) a promissory note in the amount of $97.5 million payable to Sellers (the “Seller Note”) and (iv) a contingent payment of up to $95 million. The contingent payment will provide for a sharing between The Partnership and Sellers to the extent the NYMEX current five-year strip oil price for WTI at December 31, 2017 is above $56.61 (with a maximum of $89.00) per barrel. The contingent payment will be calculated as follows: if on December 31, 2017 the average of the monthly NYMEX:CL strip prices for future contracts during the delivery period beginning December 31, 2017 and ending December 31, 2022 (the “Measurement Date Average Price”) is greater than $56.61, then the Sellers will be entitled to a contingent payment equal to (a) (i) the lesser of (A) the Measurement Date Average Price and (B) $89.00, minus (ii) $56.61, multiplied by (b) 586,601 bbls per year for each of the five years from 2018 through 2022 represented by the contracts for the entire acquisition. The contingent consideration is capped at $95 million and is to be paid on January 1, 2018. In addition, the First Amendment provides that so long as the Partnership is not in default under the Seller Note, in lieu of the Partnership’s obligation to pay the contingent payment, the Partnership has the one-time right (exercisable between June 15, 2016 through June 30, 2016) to elect to pay Sellers $5 million in full satisfaction of the contingent payment by paying to Sellers $5 million at the time of election or by increasing the amount of the Seller Note by $5 million.

F-12

The following represents the estimated fair values of the assets and liabilities assumed on the acquisition date. The aggregate fair value of consideration transferred was $60.0 million in cash, $94.1 million in seller financed debt, $4.7 million in contingent consideration and $1.7 million in deferred purchase price payments, resulting in no goodwill or bargain purchase gain.

Proved oil, natural gas and NGL properties	$	159,217,000
Total assets acquired		159,217,000
Asset retirement obligations		105,000
Total liabilities assumed		105,000
Total fair value of net assets	$	159,112,000

The table above is based upon the original purchase price allocation and is subject to post-closing adjustments.

The Partnership paid $313,366 in transaction costs associated with acquisition of the Sanish Field Assets. These costs included but were not limited to due diligence, reserve reports, legal and engineering services and site visits.

The Partnership is a non-operator of the Sanish Field Assets, with Whiting, one of the largest producers in this basin, acting as operator.

The following unaudited pro forma financial information for the periods ended December 31, 2015 and 2014, has been prepared as if the acquisition of the Sanish Field Assets had occurred on January 1, 2014.  The unaudited pro forma financial information was derived from the historical Statement of Operations of the Partnership and the historical information provided by the Sellers.  The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisition of the Sanish Field Assets and related financing occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.

	Year Ended December 31,
	2015		2014
	Unaudited
Revenues	$	26,831,257	$	49,827,000
Net income	$	2,336,675	$	21,437,004

(4) Note Payable

As part of the financing for the purchase of the Sanish Field Assets, on December 18, 2015, the Partnership executed a note in favor of the Sellers in the original principal amount of $97.5 million. The note bears interest at 5% per annum and is payable in full no later than September 30, 2016 (“Maturity Date”). The Partnership’s right to extend the Maturity Date to March 31, 2017 is subject to the satisfaction of the following conditions: (i) the Partnership must deliver to Seller written notice of the election to extend the Maturity Date no later than September 1, 2016, (ii) the Partnership must pay to Seller an extension fee equal to 0.5% of the outstanding principal balance outstanding at September 30, 2016, (iii) during the extension period and until the note is paid in full, in cash, the interest rate on the outstanding principal amount of the note will bear interest at the fixed rate of 7.0% per annum, (iv) the outstanding principal amount of the note as of September 1, 2016 shall not be in excess of $60 million, and (v) both at the time of the delivery of the extension notice and as of September 30, 2016, no event of default shall exist under the note or any collateral document. There is no penalty for prepayment of the note. Payment of the note is secured by a mortgage and liens on all of the Sanish Field Assets in customary form. If the Partnership has not fully repaid all amounts outstanding under the note on or before June 30, 2016, the Partnership must also pay a deferred origination fee in an amount equal to $250,000.

Interest is due monthly on the last day of each month while the note remains outstanding. In addition to interest payments on the outstanding principal balance of the note, the Partnership must make mandatory principal payments monthly in an amount equal to 75% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the note is reduced to $60 million and 50% of the net proceeds the Partnership receives from the sale of its equity securities thereafter, until the note is paid in full. In addition, if the Partnership sells any of the property that is collateral for the note, the Partnership must make a mandatory principal payment equal to 100% of the net proceeds of such sale until the principal amount of the note is paid in full.

F-13

As of December 31, 2015, the outstanding balance on the note was $85.0 million, the note has a carrying value of $81.7 million which approximates its fair market value.

(5) Capital Contribution and Partners’ Equity

As of August 19, 2015, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. As of December 31, 2015, the Partnership had completed the sale of a total of 4,486,625 common units at $19.00 per common unit for total gross proceeds of $85.2 million and proceeds net of offering costs including selling commissions and marketing expenses of $78.3 million. On March 4, 2016, the Partnership had received subscriptions for all 5,263,158 common units that the Partnership was offering at $19.00 per common unit. The Partnership is continuing the offering at $20.00 per common unit in accordance with the prospectus. As of December 31, 2015, 95,776,533 common units remained unsold. The Partnership will offer common units until January 22, 2017, unless the offering is extended by the General Partner, provided that the offering will be terminated if all of the common units are sold before then.

The Partnership intends to continue to raise capital through its “best-efforts” offering of units by David Lerner Associates, Inc. (the “Managing Dealer”). Under the agreement with the Managing Dealer, the Managing Dealer will receive a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the units sold. The Managing Dealer will also be paid a contingent incentive fee which is a cash payment of up to an amount equal to 4% of gross proceeds of the units sold (“Incentive Fee”). The General Partner received Incentive Distribution Rights (defined below), and has been and will be reimbursed for its documented third party out-of-pocket expenses incurred in organizing the Partnership and offering the units.

Upon entering into the management agreement with the Manager on August 19, 2015, the Partnership issued 100,000 class B units to an affiliate of the Manager. The class B units provide certain distribution rights described below.

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or with respect to class B units and will not make the contingent, incentive payments to the Managing Dealer, until Payout occurs.

The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per Unit, regardless of the amount paid for the Unit. If at any time the Partnership distributes to holders of units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

· First, 35% to the holders of the Incentive Distribution Rights, 35% to the holders of the class B units and 30% to the Managing Dealer as its contingent, incentive fee until the Managing Dealer receives incentive fees equal to 4% of the gross proceeds of the offering of common units; and then

· Thereafter, 35% to the holders of the Incentive Distribution Rights, 35% to the holders of the class B units and 30% to the holders of the units.

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

Any payments under the Incentive Distribution Rights or Incentive Fee payable to the Managing Dealer will be accounted for as a reduction to Partner’s Equity. If payment becomes probable the Partnership will estimate the value of the class B units and record an expense at that time.

For the year ended December 31, 2015, the Partnership paid distributions of $0.510138 per unit or $1,271,730.

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(6) Fair Value of Financial Instruments

Fair value of the Partnership’s financial instruments approximated carrying value at December 31, 2015.

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

· Level 1: Quoted prices in active markets for identical assets

· Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

· Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the 12 months ended December 31, 2015, there were no transfers in or out of Level 1, Level 2, or Level 3 Assets and liabilities measured on a recurring basis.

The Partnership’s financial instruments exposed to concentrations of credit risk primarily consist of cash and cash equivalents and accounts receivable. The carrying values for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows and current market conditions. See Note 4 – “Note Payable” for the fair value discussion on the debt.

Items required to be measured at fair value on a recurring basis by the Partnership include contingent consideration. Within the valuation hierarchy, the Partnership measures the fair value of contingent consideration using Level 3 inputs. As of December 31, 2015, the fair value of contingent consideration was $4,743,752. The following table presents the contingent consideration required to be measured at fair value on a recurring basis as of December 31, 2015.

	December 31, 2015
	Level 1		Level 2		Level 3		Total
Assets:
	$	-	$	-	$	-	$	-
Liabilities:
Contingent consideration	$	-	$	-	$	4,743,752	$	4,743,752

The contingent consideration as discussed in Note 3 – “Oil and Gas Investments” is a liability that is measured at fair value on a recurring basis for which there is no available quoted market price. The inputs for this instrument are significant and unobservable and therefore classified as Level 3 inputs. Management calculated the fair value of the contingent consideration (absent the $5.0 million option) as of the close date to be $12.5 million. As this is substantially greater than the $5.0 million option, a market participant would likely view the $5.0 million option as highly probable of being exercised and, therefore, value the contingent consideration at $5.0 million, discounted to the expected exercise date. The calculation of this liability is based upon a $5.0 million payment to be made to Kaiser-Whiting between June 15, 2016 and June 30, 2016 and a discount rate that is reflective of the Partnership’s market adjusted borrowing rate of 11.15%.

The contingent consideration would increase with a reduction in the discount rate and decrease with an increase in the discount rate. Adjustments to the fair value of the contingent consideration are recorded in the statements of operations.

(7) Related Parties

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than

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if conducted with non-related parties. The General Partner’s Board of Directors will oversee and review the Partnership’s related party relationships and are required to approve any significant modifications, as well as any new significant related party transactions.

On December 18, 2015 the General Partner, appointed Clifford J. Merritt as its President. Prior to being appointed President Mr. Merritt provided consulting services to the General Partner. For the year ended December 31, 2015 Mr. Merritt was paid $222,099.

Subsequent to completing the minimum offering, the Partnership reimbursed two members of the General Partner approximately $1.8 million in total for offering related costs that had been paid by the members of the General Partner.

During the year ended December 31, 2015, approximately $62,000 of general and administrative costs were incurred by the General Partner and reimbursed by the Partnership.

(8) Management Agreement

At the initial closing of the sale of common units, August 19, 2015, the Partnership entered into a management services agreement (the “Management Agreement”) with E11 Management LLC to provide management and operating services regarding substantially all aspects of the Partnership. The Manager is an indirect, wholly-owned subsidiary of American Energy Partners, L.P. The Manager is not an affiliate of the Partnership or the General Partner.

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

· Identifying producing and non-producing properties that the Partnership may consider acquiring, and assisting in evaluation, contracting for and acquiring these properties and managing the development of these properties;

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

· Overseeing the operations on properties the Partnership acquires that are 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; and

· Assisting in establishing cash management and risk management programs.

The Management Agreement provides that the Partnership will direct the services provided to it under the Management Agreement, and that the Manager will determine the means or method by which those directions are carried out. The Management Agreement provides that the Manager will conduct the day-to-day operations of the Partnership’s business as provided in budgets that the Manager will prepare and the Partnership will have the right to approve. The Management Agreement also contains a list of activities in which the Manager will not engage without the Partnership’s prior approval.

To date, the Partnership has only purchased non-operated interests in oil and gas assets, which as a result may impact the amount and type of duties needed from the Manager.

The Manager will be reimbursed for certain costs directly related to the Partnership and will be paid a monthly general and administrative expense compensation amount (“Monthly G&A Expense Amount”) at an annual rate that will be 1.75% of the net proceeds from the sale of common units, less commissions, marketing fee and offering and organization expense, plus the amount of outstanding indebtedness, which is referred to as the reimbursement base, for the first six months following the initial closing. Thereafter, the Monthly G&A Expense Amount will be at an annual rate of 3.5% of the reimbursement base and will reduce to an annual rate of 2% of the reimbursement base over time. In addition, pursuant to the Partnership Agreement, concurrently with the initial closing of the sale of common units pursuant to the public offering, 100,000 class B units were issued to an affiliate of the Manager.

Subject to certain exceptions, the Management Agreement will remain in effect as long as the Partnership holds any assets.

The Management Agreement is terminable by us if: (i) we sell all or substantially all of our assets; (ii) there is a change in control and the Manager is no longer controlled by Mr. McClendon or his immediate family; (iii) Mr. McClendon, the Manager’s key employee, ceases to be employed by the Manager and we do not approve of a proposed replacement of such key employee; (iv) the Manager becomes subject to bankruptcy proceedings; (v) the Manager materially breaches its

F-16

obligations under the Management Agreement and does not cure the breach within 60 days of its receipt of notice of the breach; or (vi) the Manager or its affiliates defraud us or steal or misappropriate any of our assets and such circumstances have not been cured as provided in the Management Agreement. We may also terminate the Management Agreement if the Manager fails to recommend to us one or more acquisitions of producing or non-producing oil and gas properties that meet our acquisition parameters and are reasonably capable of consummation at any time that we have an aggregate of at least $100 million consisting of capital contributions received by us and which have not been spent by us, and all available borrowings under our credit facility, in each case, that have not been reserved by us for any acquisitions, development operations or other expenses, which we refer to as Unallocated Funds, for a period of 60 consecutive days.

For the year ended December 31, 2015, the Partnership incurred fees of approximately $253,000 and estimated reimbursable costs of approximately $200,000 under the Management Agreement.

See Note 10 – “Subsequent Events” below.

(9) Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2015 is as follows:

	2015
Producing properties	$	90,167,047
Non-producing		69,119,768
		159,286,815
Accumulated depreciation, depletion and amortization		(391,624	)
Net capitalized costs	$	158,895,191

Costs Incurred

For the years ended December 31, the Partnership incurred the following costs in oil and natural gas producing activities:

	2015
Property acquisition costs	$	159,216,768
Development Costs		70,047
	$	159,286,815

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the

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absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2015.

The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2015, have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.

Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are summarized as follows:

	Proved Reserves
	Oil (Barrels)			NGL (Barrels)			Natural Gas (Mcf)			Total (BOE)
January 1, 2015		-			-			-			-
Acquisition		9,089,252			1,866,775			7,705,802			12,240,327
Extensions, discoveries and other additions		-			-			-			-
Production (December 18 - December 31)		(21,937	)		(2,841	)		(18,392	)		(27,843	)
December 31, 2015		9,067,315			1,863,934			7,687,410			12,212,484

In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The oil, natural gas and NGL prices used in computing the Partnership’s reserves as of December 31, 2015 were $50.28 per barrel, $2.59 per MMbtu, and $15.74 per barrel of NGL, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2015 were $41.74 per barrel of oil, $1.46 per MMbtu of natural gas and $9.77 per barrel of NGL.

	Proved Developed Reserves								Proved Undeveloped Reserves
	Oil (Barrels)		NGL (Barrels)		Natural Gas (Mcf)		Total (BOE)		Oil (Barrels)		NGL (Barrels)		Natural Gas (Mcf)		Total (BOE)
December 31, 2015		5,602,387		961,147		3,964,052		7,224,210		3,464,928		902,787		3,723,358		4,988,274

F-18

The following details the changes in proved undeveloped reserves for 2015 (BOE):

Beginning proved undeveloped reserves	-
Acquisition	4,988,274
December 31, 2015	4,988,274

We anticipate that all the Partnership’s current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves will be removed as revisions at the time that determination is made, and in the event that it subsequently appears that any such undrilled PUD locations would not be drilled by the end of such five-year period, then the Partnership would remove the reserves associated with those locations from the its proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2015
Future cash inflows	$	407,928,626
Future production costs		(136,547,001	)
Future development costs		(37,640,024	)
Future net cash flows		233,741,601
10% annual discount		(134,551,759	)
Standardized measure of discounted future net cash flows	$	99,189,842

Changes in the standardized measure of discounted future net cash flows are as follows:

	2015
Beginning of year	$	-
Changes resulting from:
Acquisition of reserves		99,670,116
Sales of oil, natural gas and NGLs, net of production costs		(480,274	)
Net change		99,189,842
End of year	$	99,189,842

F-19

(10) Subsequent Events

In January 2016, the Partnership declared and paid $499,061, or $0.111233 per outstanding common unit, in distributions to its holders of common units.

In January 2016, the Partnership closed on the issuance of approximately 380,645 units through its ongoing best efforts offering, representing gross proceeds to the Partnership of approximately $7.2 million and proceeds net of selling and marketing costs of approximately $6.8 million.

In February 2016, the Partnership declared and paid $522,730, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

In February 2016, the Partnership closed on the issuance of approximately 375,483 units through its ongoing best efforts offering, representing gross proceeds to the Partnership of approximately $7.1 million and proceeds net of selling and marketing costs of approximately $6.7 million.

On March 4, 2016 we had received subscriptions for all of the common units we were offering at $19.00 per common unit, 5,263,158 units and, consequently, all common units offered and sold after that date will be at $20.00 per common unit in accordance with the prospectus.

On March 2, 2016, Aubrey McClendon, who controlled our third party manager E11 Management, LLC was killed in a car accident. We do not believe this will cause any interruption in our existing operations, since as previously disclosed, substantially all of the Partnership’s assets are operated by Whiting Petroleum Corporation, an independent third party.

In March 2016, the Partnership declared and paid $563,056, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

In March 2016, the Partnership closed on the issuance of approximately 343,541 units through its ongoing best efforts offering, representing gross proceeds to the Partnership of approximately $6.9 million and proceeds net of selling and marketing costs of approximately $6.5 million.

F-20

INDEPENDENT AUDITOR’S REPORT

To the Members

Kaiser-Whiting, LLC

Report on the Combined Statements of Revenues and Direct Operating Expenses

We have audited the accompanying combined statements of revenues and direct operating expenses of properties under contract for purchase by Energy 11, L.P. from Kaiser-Whiting, LLC under agreement dated September 15, 2015, (the Properties) for the years ended December 31, 2014, 2013 and 2012, and the related notes to the combined statements of revenues and direct operating expenses.

Management’s Responsibility for the Combined Statements of Revenues and Direct Operating Expenses

Management is responsible for the preparation and fair presentation of the combined statements of revenues and direct operating expenses in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the combined statements of revenues and direct operating expenses that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the combined statements of revenues and direct operating expenses based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined statements of revenues and direct operating expenses are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statement.  The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statement, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statement in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control.  Accordingly, we express no such opinion.  An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statement.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the combined statements of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Properties for the years ended December 31, 2014, 2013 and 2012, in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

As described in Note 1 to the combined statements of revenues and direct operating expenses, the accompanying combined statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission for inclusion in the Post-Effective Amendment No. 4 to the Registration Statement on Form S-1 of Energy 11, L.P. and are not intended to be a complete presentation of the results of the operations of the Properties. Our opinion is not modified with respect to this matter.

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Other Matter

Our audits were conducted for the purpose of forming an opinion on the combined statements of revenues and direct operating expenses of the Properties for the years ended December 31, 2014, 2013 and 2012.  The supplemental oil and natural gas reserve information in Note 5 is presented for purposes of additional analysis and is not a required part of the financial statements.  Such information has not been subjected to the auditing procedures applied in the audit of the financial statements, and accordingly, we do not express an opinion or provide any assurance on it.

/s/ HoganTaylor LLP

October 22, 2015

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COMBINED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

OF PROPERTIES UNDER CONTRACT FOR PURCHASE BY ENERGY 11, L.P. FROM

KAISER-WHITING, LLC UNDER AGREEMENT DATED SEPTEMBER 15, 2015

(Amounts in thousands)

	For the six months ended June 30,				For the years ended December 31,
	2015		2014		2014		2013		2012
	(Unaudited)
Revenues – oil, natural gas, and natural gas liquids sales	$	14,207	$	26,282	$	49,827	$	62,447	$	48,328
Direct operating expenses		3,851		5,831		11,321		12,789		10,221
Excess of revenues over direct operating expenses	$	10,356	$	20,451	$	38,506	$	49,658	$	38,107

See Notes to Combined Statements of Revenues and Direct Operating Expenses

F-23

NOTES TO COMBINED STATEMENTS OF REVENUES AND

DIRECT OPERATING EXPENSES OF PROPERTIES UNDER CONTRACT FOR PURCHASE BY

ENERGY 11, L.P. FROM

KAISER-WHITING, LLC UNDER AGREEMENT DATED SEPTEMBER 15, 2015

Six months ended June 30, 2015 and 2014 (Unaudited), and

years ended December 31, 2014, 2013 and 2012

Note 1 – Basis of Presentation

Kaiser-Whiting, LLC (the Company) is a limited liability company created on June 4, 2009, for the purpose of drilling and producing oil, natural gas and natural gas liquids in Mountrail County, North Dakota.  The Company is primarily owned by George B. Kaiser.  Kaiser Francis Management Company (KFMC), also primarily owned by George B. Kaiser, provides management and administrative service to the Company.  The Company has no employees.  On October 5, 2014, the Company entered into an agreement with Natural Resource Partners L.P. through its subsidiary, NRP Oil and Gas LLC, to sell 40% of the Company’s then-existing membership interests for $340 million in cash, subject to customary purchase price adjustments.  The transaction closed on November 12, 2014.  Effective November 13, 2014, the Buyer withdrew as a member of the Company, and its undivided 40% interest in the Company’s assets was distributed from the Company and assigned directly to the Buyer.

On September 15, 2015, the Company entered into an agreement with Energy 11, L.P. through its subsidiary, Energy 11 Operating Company LLC (the Buyer), to sell 50% of the Company’s remaining membership interests for $162 million in cash plus deferred purchase payments, if future oil prices exceed defined levels, subject to customary purchase price adjustments.  The transaction is scheduled to close in December 2015. The accompanying combined statements of revenues and direct operating expenses reflect the portion of properties applicable to the interests under contract by the Buyer (Properties).

Combined statements of revenues and direct operating expenses are presented because it is not practicable to obtain full historical audited financial statements with respect to the Properties.  A substantial portion of the Properties was contributed to the Company by affiliated individuals on June 1, 2014.  The historical records of the Company do not include the results of operations for contributed properties prior to the contribution date and, therefore, the historical results of Kaiser-Whiting, LLC prior to June 1, 2014 are not indicative of the financial condition or results of operations after the contribution of properties.  The combined statements of revenues and direct operating expenses combine the revenues and direct operating expenses for contributed properties prior to their contribution with the historical financial information of Kaiser-Whiting, LLC for all periods presented. Certain costs such as depletion and depreciation, accretion of asset retirement obligations, as well as general and administrative expenses not directly associated with producing revenues were not included as direct operating expenses.  No portion of general and administrative costs of the Company was included in the combined statements.  Those amounts for the Company were $556,000, $180,000 and $133,000, respectively, for the years ended December 31, 2014, 2013 and 2012, and $288,000 and $438,000, respectively, for the six months ended June 30, 2015 and 2014.  Financial information in accordance with accounting principles generally accepted in the United States of America (US GAAP) has not been prepared for the properties contributed to the Company by affiliated individuals. Consequently, depletion, depreciation and accretion of asset retirement obligations for the Properties are not known for the periods presented.  Since the Company has elected to be taxed as a pass-through entity, with taxable income and expense items allocated directly to the individual members of the Company and the affiliated individuals directly owned the contributed properties, there was no income tax expense for the Properties during the periods presented in accordance with US GAAP.

Revenues in the accompanying combined statements of revenues and direct operating expenses are recognized on the sales method.  Direct operating expenses are recognized on the accrual method and consist of monthly operator overhead and other direct costs of operating the Properties.  Included in direct operating costs are costs associated with field operating expenses, workovers and monthly operator overhead.

Note 2 – Unaudited Interim Financial Information

The accompanying combined statements of revenues and direct operating expenses for the six months ended June 30, 2015 and 2014 are unaudited.  The unaudited combined interim statements of revenues and direct operating expenses were prepared on the same basis as the audited combined statements of revenues and direct operating expense for the years ended

F-24

December 31, 2014, 2013 and 2012.  In the opinion of management, the unaudited combined interim statements reflect all adjustments necessary to state fairly the excess of revenues over direct operating expenses for the properties under contract by the Buyer from the Company under the agreement dated September 15, 2015, for the six-month periods ended June 30, 2015 and 2014.  The combined revenues and direct operating expenses for the interim periods ended June 30, 2015 and 2014, are not necessarily indicative of results that may be expected for the year ended December 31, 2015, or any future periods.

Note 3 – Additional Cash Flow Information

Excess of revenues over direct operating expenses in the combined statements of revenues and direct operating expenses approximates net cash provided by operating activities of the Properties during all of the periods presented.

Cash flows from investing activities during all of the periods presented consist of expenditures for equipment and capitalized intangible drilling costs for the Properties.  These expenditures totaled $24,874,000, $17,505,000 and $41,471,000, respectively, for the years ended December 31, 2014, 2013 and 2012.  For the six months ended June 30, 2015 and 2014, these expenditures were $12,181,000 and $7,747,000, respectively.

During all the periods presented, net cash flows from operating and investing activities were settled monthly with the members of the Company and individual property owners.  There were no other cash flows from financing activities of the Properties.

Note 4 – Subsequent Events

Management has evaluated subsequent events through October 22, 2015, the date the accompanying combined statements of revenue and direct operating expenses were available to be issued.

Note 5 – Supplemental Oil and Natural Gas Reserve Information (Unaudited)

The following reserve estimates present the Company’s estimate of the proven natural gas and oil reserves and net cash flow of the Properties, in accordance with the guidelines established by the Securities and Exchange Commission.  These reserve estimates were prepared by KFMC personnel.  The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing natural gas and oil properties.  Accordingly, the estimates are expected to change as future information becomes available.  All of the oil and natural gas reserves are in North Dakota.

(a)   Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Properties:

	As of December 31,
	2014						2013						2012
	(amounts in thousands)
	Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)			Gas (Mcf)
Proved developed and undeveloped reserves:
Beginning of year		7,920			7,191			7,819			5,544			8,295			5,206
Purchase of mineral in place		-			-			-			-			684			496
Revisions of previous estimates		1,933			1,853			867			2,032			(513	)		70
Production		(639	)		(404	)		(766	)		(385	)		(647	)		(228	)
End of year		9,214			8,640			7,920			7,191			7,819			5,544
Proved developed reserves:
Beginning of year		6,722			6,194			6,775			4,850			4,521			2,924
End of year		6,759			6,594			6,722			6,194			6,775			4,850

F-25

(b)   Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to oil and natural gas reserves and associated changes in standard measure amounts were prepared in accordance with the provision of Financial Accounting Standard Board ASC 932-235-555.  Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production.  Future production and development costs were computed by estimating the expenditures to be incurred in developing the crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions.  Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Properties’ crude oil and natural gas reserves.  Standard measure amounts are:

	2014			2013			2012
	(amounts in thousands)
Future cash inflows	$	704,336		$	603,779		$	609,716
Future production costs		205,751			162,057			162,175
Future development costs		44,700			26,365			26,062
Future net cash flows		453,885			415,356			421,479
10% annual discount for timing of cash flows		(223,732	)		(224,213	)		(224,526	)
Standardized Measure	$	230,153		$	191,144		$	196,953

The 12-month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Properties’ reserves.  The price of other liquids is included in natural gas.  The prices for the Properties’ reserves were as follows:

	2014		2013		2012
Representative NYMEX prices:
Natural gas (MMBtu)	$	4.415	$	3.653	$	2.789
Oil (Bbl)	$	93.00	$	97.98	$	94.19

Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum are as follows:

Sales of oil and gas production	$	(38,506	)	$	(49,658	)	$	(38,107	)
Change in prices and production costs		(5,087	)		(10,003	)		16,339
Purchase of minerals in place		-			-			16,472
Development costs incurred		26,284			20,891			42,709
Changes in estimated development costs		(44,619	)		(23,539	)		(5,100	)
Accretion of discount		19,114			16,268			15,963
Revisions of quantity estimates		57,973			45,386			(12,020	)
Timing and other		23,850			(5,155	)		1,066
Change in standardized measure	$	39,009		$	(5,810	)	$	37,322

Estimates of economically recoverable natural gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results.  Therefore, actual production, revenues, development and operating expenditures may not occur as estimated.  The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters.  Actual quantities of natural gas and oil may differ materially from the amounts estimated.

F-26

Energy 11, L.P.

Unaudited Pro Forma Condensed Combined Financial Statements

Introduction

On September 15, 2015, Energy 11 Operating Company, LLC, a wholly owned subsidiary of Energy 11, L.P. (“the Partnership” entered into an Interest Purchase Agreement by and among Kaiser-Whiting, LLC and the owners of all the limited liability company interests therein (the “Sellers”), for the purchase of the Sanish Field Assets. We completed the purchase transaction on December 18, 2015. Prior to this acquisition, we owned no oil or natural gas assets. The Sanish Field Assets currently constitute all of our oil and gas properties.

Under the Purchase Agreement, the Partnership agreed to pay a cash purchase price for the Sanish Field Assets, consisting of (i) an initial $160 million, payable at closing subject to customary adjustments, (ii) an aggregate of $2 million, payable in equal amounts on December 31, 2016 and December 31, 2017 and (iii) a contingent payment of up to $95 million. The contingent payment was to provide a means for a sharing between the Partnership and the Sellers to the extent the NYMEX current five-year strip oil price for WTI at December 31, 2017 is above $56.61 (with a maximum of $89.00) per barrel.  The contingent payment will be calculated as follows: if on December 31, 2017 the average of the monthly NYMEX:CL strip prices for future contracts during the delivery period beginning December 31, 2017 and ending December 31, 2022 (the “Measurement Date Average Price”) is greater than $56.61, then the Sellers will be entitled to a contingent payment equal to (a) (i) the lesser of (A) the Measurement Date Average Price and (B) $89.00, minus (ii) $56.61, multiplied by (b) 586,601 Bbls per year for each of the five years from 2018 through 2022 represented by the contracts for the entire acquisition.  The contingent consideration is capped at $95 million and is to be paid on January 1, 2018.

In connection with the closing of the acquisition on December 18, 2015, the Partnership entered into a First Amendment to Interest Purchase Agreement, which changed the method of payment of the initial $160 million of the purchase price.  Under the terms of the First Amendment, we paid the Sellers $60 million in cash at the closing, and delivered a secured promissory note payable to the Sellers in the original principal amount of $97.5 million (the “Seller Note”).  The purchase price was also net of estimated operating cash flow of approximately $2.5 million from September 15, 2015 through December 31, 2015.  The First Amendment provides that so long as the Partnership is not in default under the Seller Note, in lieu of our obligation to make the contingent payment, we will have a one-time right (exercisable between June 15, 2016 through June 30, 2016) to elect to pay the Sellers $5 million in full satisfaction of the contingent payment obligation, by either paying to the Sellers $5 million at the time of election or by increasing the amount of the Seller Note by $5 million.

The following unaudited pro forma condensed combined financial statement has been prepared to give pro forma effect to the acquisition, which was accounted for as a business combination, as if the acquisition, the related financing transactions, consisting of proceeds from the Partnership’s ongoing public offering of the Partnership’s common units and the issuance of the borrowings had occurred on the date indicated.

The unaudited pro forma condensed combined financial statement includes the statement of operations for the year ended December 31, 2015.  The pro forma condensed combined statement of operations was derived from the Partnership’s historical audited financial statements for the year ended December 31, 2015.

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2015 gives effect to the acquisition and related financing transactions as if they had occurred on January 1, 2015.

The unaudited pro forma condensed combined financial statement and the accompanying unaudited pro forma notes should be read in conjunction with the Partnership’s historical financial statements and related notes, together with the audited Combined Statements of Revenues and Direct Operating Expenses of Properties Under Contract for Purchase by Energy 11, L.P. from Kaiser-Whiting, LLC by Agreement Dated September 15, 2015, all of which are included in this Amendment.

The unaudited pro forma condensed combined financial statement presented herein is based on the assumptions and adjustments described in the accompanying unaudited pro forma notes.  The unaudited pro forma condensed combined financial statement is presented for illustrative purposes and is not indicative of what results of operations might have been achieved had the acquisition and related transactions occurred as of the date indicated or results of operations that might be achieved for any future periods.

F-27

Energy 11, L.P.

Unaudited Pro Forma Condensed Combined Statement of Operations

Year Ended December 31, 2015

	Energy 11, L.P. Historical Year Ended December 31, 2015			Pro Forma Adjustments				Energy 11, L.P. Pro Forma as Adjusted
		(1)
Revenues
Oil, natural gas and NGL sales	$	703,806		$	26,127,451		(a)	$	26,831,257
Total revenues		703,806			26,127,451				26,831,257
Operating costs and expenses
Operating expenses, excluding depreciation and amortization		241,671			7,198,834		(a)		7,440,505
Acquisition related costs		313,366			-				313,366
Management fees		252,524			3,947,476		(b)		4,200,000
General and administrative expenses		745,884			-				745,884
Depreciation, depletion and amortization		392,084			9,887,775		(c)		10,279,859
Total operating costs and expenses		1,945,529			21,034,085				22,979,614
Other income (expense)
Interest expense		(321,093	)		(2,017,463	)	(d)		(2,338,556	)
Total other expense		(321,093	)		(2,017,463	)			(2,338,556	)
Net income (loss)	$	(1,562,816	)	$	3,075,903			$	1,513,087
Common units outstanding		920,668							4,486,625
Net income (loss) per common unit	$	(1.70	)					$	0.34
(1)	Income statement amounts obtained from Energy 11, L.P. historical financial statements for the year ended December 31, 2015.

See accompanying notes to unaudited pro forma condensed combined financial statement of operations.

F-28

1. Basis of Presentation

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2015 gives effect to the acquisition and related financing transactions as if they occurred on January 1, 2015.

The unaudited pro forma condensed combined financial statement was derived by adjusting the Partnership’s historical financial statements for the acquisition and related transactions.  The unaudited pro forma condensed combined financial statement is provided for informational purposes only and is not indicative of the Partnership’s financial position or results of operations had the transaction been consummated on the date indicated or results of operations for any future period or date.

The unaudited pro forma condensed combined financial statement and the accompanying unaudited pro forma notes should be read in conjunction with the Partnership’s historical financial statements and related notes, together with the audited Combined Statements of Revenues and Direct Operating Expenses of Properties Under Contract for Purchase by Energy 11, L.P. from Kaiser-Whiting, LLC by Agreement Dated September 15, 2015, contained herein.

2. Pro Forma Adjustments

The pro forma adjustments made herein are based upon management’s estimates of the fair value of the oil and gas interests acquired.  These estimates are subject to finalization.

A – Record revenue and operating expenses, excluding depreciation and amortization:  The pro forma adjustments reflect oil, natural gas and NGL sales and the direct operating expenses for the assets acquired from Kaiser-Whiting, LLC.  These pro forma adjustments were derived from statements of revenue and JIB statements obtained from Kaiser-Whiting, LLC for the period January 1, 2015 to December 18, 2015.

B – Record management services fees:  The pro forma adjustments reflect management services fees as described in the prospectus based on assumed amounts of debt and equity outstanding.  The Partnership is contractually obligated to pay 1.75% for the first six-months following the initial closing and 3.5% for the seventh month through the 36th month following the initial closing as a management fee of the reimbursement base which is calculated as net proceeds from the sale of common units, less commissions, marketing fee and offering and organization expense, plus the amount of outstanding indebtedness.

C – Record depletion:  The pro forma adjustments reflect depletion calculated by allocation of the total purchase price to combined estimates of oil and gas reserves acquired based on historical reserve information and production quantities for the period presented provided by Kaiser-Whiting, LLC and accretion of the asset retirement obligations.

D – Record interest expense:  Reflects interest on the Seller Note and estimate of interest expense considering multiple pay off scenarios related to the seller financing provided by Kaiser-Whiting, LLC and the estimated needs for draws/pay downs of a revolver to be in place to carry on the day-to-day operations of the acquired assets.

F-29

Exhibit A to Prospectus

Limited Partnership Agreement

First Amended and Restated

Agreement of Limited Partnership

Energy 11, L.P.

August 19, 2015

TABLE OF CONTENTS

		Page
ARTICLE I. Definitions		1
Section 1.1	Definitions.	1
Section 1.2	Construction.	8
ARTICLE II. Organization		9
Section 2.1	Formation.	9
Section 2.2	Name.	9
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices.	9
Section 2.4	Purpose and Business.	9
Section 2.5	Powers.	9
Section 2.6	Power of Attorney.	10
Section 2.7	Term.	10
Section 2.8	Title to Partnership Assets.	11
ARTICLE III. Rights of Limited Partners		11
Section 3.1	Limitation of Liability.	11
Section 3.2	Management of Business.	11
Section 3.3	Outside Activities of the Limited Partners.	11
Section 3.4	Rights of Limited Partners.	11
ARTICLE IV. Certificates; Record Holders; Transfer of Partnership Interests; Redemption of Partnership Interests		12
Section 4.1	Certificates.	12
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates.	13
Section 4.3	Record Holders.	13
Section 4.4	Transfer Generally.	13
Section 4.5	Registration and Transfer of Limited Partner Interests.	14
Section 4.6	Transfer of the General Partner’s General Partner Interest; Transfer of Ownership of the General Partner.	14
Section 4.7	Transfer of Incentive Distribution Rights or Class B Units.	15
Section 4.8	Restrictions on Transfers.	15
Section 4.9	Citizenship Certificates; Non-citizen Assignees.	16
Section 4.10	Redemption of Partnership Interests of Non-citizen Assignees.	16
ARTICLE V. Capital Contributions and Issuance of Partnership Interests		17
Section 5.1	Organizational Contributions.	17
Section 5.2	Offering of Units.	17
Section 5.3	Subscriptions by Participants.	18
Section 5.4	Effect of Subscription	18
Section 5.5	Maximum and Minimum Number of Units.	18
Section 5.6	Acceptance of Subscriptions.	18
Section 5.7	Capital Contributions of the General Partner; Payment of Subscriptions.	18
Section 5.8	Incentive Rights.	19
Section 5.9	Class B Units.	19
Section 5.10	Profits Interests.	20
Section 5.11	Interest and Withdrawal.	20
Section 5.12	Fully Paid and Non-Assessable Nature of Limited Partner Interests.	20

i

ARTICLE VI. Distributions; Allocations and Capital Accounts		20
Section 6.1	Distributions; Distributions to Record Holders.	20
Section 6.2	Distributions of Available Cash; Payment of Dealer Manager Contingent, Incentive Fee	21
Section 6.3	Restrictions on Distributions.	21
Section 6.4	Capital Accounts.	21
ARTICLE VII. Management and Operation of Business		21
Section 7.1	Management.	21
Section 7.2	Certificate of Limited Partnership.	23
Section 7.3	Restrictions on the General Partner’s Authority; Agreement by Owners of the General Partner.	24
Section 7.4	Reimbursement of the General Partner.	24
Section 7.5	Outside Activities.	24
Section 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.	25
Section 7.7	Indemnification.	26
Section 7.8	Liability of Indemnitees.	27
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.	27
Section 7.10	Other Matters Concerning the General Partner.	28
Section 7.11	Purchase or Sale of Units; Incentive Distribution Rights and Class B Units.	29
Section 7.12	Reliance by Third Parties.	29
ARTICLE VIII. Books, Records, Accounting and Reports		29
Section 8.1	Records and Accounting.	29
Section 8.2	Fiscal Year.	29
Section 8.3	Reports.	30
ARTICLE IX. Tax Matters		30
Section 9.1	Tax Returns and Information.	30
Section 9.2	Tax Elections.	30
Section 9.3	Tax Controversies.	30
Section 9.4	Withholding.	30
ARTICLE X. Admission of Partners		31
Section 10.1	Admission of Limited Partners.	31
Section 10.2	Admission of Successor General Partner.	31
Section 10.3	Amendment of Agreement and Certificate of Limited Partnership.	31

ARTICLE XI. Withdrawal or Removal of Partners		32
Section 11.1	Withdrawal of the General Partner.	32
Section 11.2	Removal of the General Partner.	33
Section 11.3	Interest of Departing General Partner and Successor General Partner.	33
Section 11.4	Withdrawal of Limited Partners.	33
ARTICLE XII. Dissolution and Liquidation		33
Section 12.1	Dissolution.	33
Section 12.2	Continuation of the Business of the Partnership After Dissolution.	33
Section 12.3	Liquidator.	34
Section 12.4	Liquidation.	34
Section 12.5	Cancellation of Certificate of Limited Partnership.	35
Section 12.6	Return of Contributions.	35

ii

Section 12.7	Waiver of Partition.	35
Section 12.8	Capital Account Restoration.	35
ARTICLE XIII. Amendment of Partnership Agreement; Meetings; Record Date		35
Section 13.1	Amendments to be Adopted Solely by the General Partner.	35
Section 13.2	Amendment Procedures.	36
Section 13.3	Amendment Requirements.	36
Section 13.4	Special Meetings.	37
Section 13.5	Notice of a Meeting.	37
Section 13.6	Record Date.	37
Section 13.7	Postponement and Adjournment.	38
Section 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes.	38
Section 13.9	Quorum and Voting.	38
Section 13.10	Conduct of a Meeting.	38
Section 13.11	Action Without a Meeting.	39
Section 13.12	Right to Vote and Related Matters.	39
ARTICLE XIV. Merger, Consolidation or Conversion		39
Section 14.1	Authority.	39
Section 14.2	Procedure for Merger, Consolidation or Conversion.	40
Section 14.3	Approval by Limited Partners.	41
Section 14.4	Certificate of Merger or Certificate of Conversion.	42
Section 14.5	Effect of Merger, Consolidation or Conversion.	42
ARTICLE XV. General Provisions		43
Section 15.1	Addresses and Notices.	43
Section 15.2	Further Action.	43
Section 15.3	Binding Effect.	43
Section 15.4	Integration.	43
Section 15.5	Creditors.	43
Section 15.6	Waiver.	43
Section 15.7	Third-Party Beneficiaries.	44
Section 15.8	Counterparts.	44
Section 15.9	Applicable Law; Forum, Venue and Jurisdiction; Waiver of Jury Trial.	44
Section 15.10	Invalidity of Provisions.	44
Section 15.11	Consent of Partners.	45
Section 15.12	Facsimile Signatures.	45

iii

First Amended and Restated

Agreement of Limited Partnership

of

Energy 11, L.P.

This First Amended and Restated Agreement of Limited Partnership of Energy 11, L.P., dated as of August 19, 2015, is entered into by and between Energy 11 GP, LLC, a Delaware limited liability company, as the General Partner, DMOG, LLC, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein.  In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I.

Definitions

Section 1.1Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question.  As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of Energy 11, L.P., as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Approved Credit Facility” has the meaning set forth in the Management Agreement.

“Available Cash” means the cash of the Partnership and its Subsidiaries available for distribution to the Partners and to pay the Contingent, Incentive Fee determined on a consolidated basis as of the end of each Calendar Month prior to the dissolution of the Partnership and its Subsidiaries, consisting of the cash on hand as of the end of such Month (representing the proceeds from the sale of crude oil, natural gas and other hydrocarbons from the properties of the Partnership and its Subsidiaries, net proceeds from sales of the properties of the Partnership and its Subsidiaries, net proceeds from the hedging activities of the Partnership and its subsidiaries, other receipts from the operations of the Partnership and its Subsidiaries and, if the General Partner so determines, in its sole and absolute discretion, Capital Contributions of the Partners and the proceeds of borrowings by the Partnership or its Subsidiaries), less cash determined by the General Partner, in its sole and absolute discretion, to be used for past and future: operating expenses, capital expenditures and other amounts for acquisitions, exploration and development of oil and gas properties and other assets, debt service, management fees, general and administrative expenses and other obligations of the Partnership and its Subsidiaries, and reserves for future capital (including future acquisitions and exploration and development operations) and operating requirements of the Partnership and its Subsidiaries that the General Partner determines to be necessary or appropriate.  Available Cash for each Month will be determined by the General Partner in its sole and absolute discretion following the end of each Month after the Initial Closing and continuing until the dissolution of the Partnership and its Subsidiaries, and such determination shall be final and binding on the Partners.

“Bankruptcy” means, with respect to any Person, the occurrence of any of the following events, conditions or circumstances:  (i) such Person shall file a voluntary petition in bankruptcy or shall be adjudicated as bankrupt or insolvent, or shall file any petition or answer or consent seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief for itself under the United States Bankruptcy Reform Act of 1978 (the “Bankruptcy Code”) or any present or future applicable federal, state or other statute or Law relating to bankruptcy, insolvency, reorganization or other relief for debtors, or shall seek or consent to, or acquiesce in, the appointment of any trustee, receiver, conservator or liquidator of such Person or of all or any substantial part of its properties (the term “acquiesce,” as used in this definition, includes the failure to file a petition or motion to vacate or discharge any order, judgment or decree within 20 days, after entry of such order, judgment or decree); (ii) an involuntary case or other proceeding shall be commenced against such Person seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief with respect to such Person or its debts under the Bankruptcy Code or any present or future applicable federal, state or other statute or Law relating to bankruptcy, insolvency, reorganization or other relief for debtors, or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of it or any substantial part of its property, and such involuntary case or other proceeding shall remain undismissed or unstayed for a period of 90 consecutive days, (iii) a court of competent jurisdiction shall enter an order, judgment or decree approving a petition filed against such Person seeking a reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under the Bankruptcy Code, or any other present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency, reorganization or other relief for debtors, and such Person shall acquiesce in the entry of such order, judgment or decree or such order, judgment or decree shall remain unvacated and unstayed for an aggregate of 90 days (whether or not consecutive) from the date of entry thereof, or any trustee, receiver, conservator or liquidator of such Person or of all or any substantial part of its property shall be appointed without the consent or acquiescence of such Person and such appointment shall remain unvacated and unstayed for an aggregate of 90 days (whether or not consecutive); (iv) such Person shall admit in writing its inability to pay its debts as they mature or shall generally not be paying its debts as they become due; or (v) such Person shall make a general assignment for the benefit of creditors or take any other similar action for the protection or benefit of creditors.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act.  The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Board of Directors” means, with respect to the General Partner, the following, as applicable: (i) if the General Partner is a member managed limited liability company, the board of directors or similar governing body of the managing member of the General Partner; (ii) if the General Partner is a limited liability company (other than a member managed limited liability company) or a corporation, the board of directors or similar governing body of the General Partner; or (iii) if the General partner is a limited partnership, the board of directors or similar governing body of the general partner of the General Partner.

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Capital Account” has the meaning assigned to such term in Exhibit B.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, or (ii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of the Incentive Distribution Rights or Class B Units.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

2

“Change of Control” means the consummation of any transaction (including without limitation, any merger or consolidation) the result of which is that any “person” (as that term is used in Section 13(d)(3) of the Exchange Act), excluding the Qualifying Owners, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the outstanding membership interests of the General Partner; provided, however, that the Persons who, from time to time, own Equity Interests in the Qualifying Owners will not be deemed Beneficial Owners of the membership interests of the General Partner by reason of the ownership of such Equity Interests and provided further that if an entity ceases to be a Beneficial Owner it shall not be deemed to be a Change of Control if the Beneficial Owners of such entity continue to the Beneficial Owners of a majority of the membership interests in the General Partner previously owned by such entity.

“Citizenship Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

“Class B Distribution Percent” means, as of any date, 35% multiplied by a fraction, the numerator of which is the number of Class B Units Outstanding on such date and the denominator of which is 100,000.

“Class B Holder” means E11 Incentive Holdings, LLC, in its capacity as the holder of the Class B Units.

“Class B Units” means the non-voting Limited Partner Interests issued to the Class B Holder, which Limited Partner Interests will confer upon the holder thereof only the rights and obligations specifically provided for in this Agreement with respect to the Class B Units.

“Code” means the Internal Revenue Code of 1986, as amended.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

“Commission” means the United States Securities and Exchange Commission.

“Contingent, Incentive Fee” has the meaning set forth in the Dealer Manager Agreement.

“Current Market Price” of any class of Limited Partner Interests means the fair value of any Limited Partner Interest as determined by the General Partner in good faith.

“Dealer Manager” means David Lerner Associates, Inc., an unaffiliated broker dealer, or any other unaffiliated broker dealer who enters into a Dealer Manager Agreement with the Partnership and offers and sells Units.

“Dealer Manager Agreement” means the agreement with David Lerner Associates, Inc., filed as an Exhibit to the Registration Statement, and any agreements thereunder with a soliciting dealer to offer and sell Units.

“Dealer Manager Contingent, Incentive Fee” means the Contingent, Incentive Fee payable to the Dealer Manager under the Dealer Manager Agreement.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

“Depository” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Limited Partner the General Partner determines does not or would not subject such Group Member to a significant risk of cancellation or forfeiture under any federal, state or local law or regulation, including any governmental permit, endorsement or other authorization, of any of its properties or any interest therein.

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“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“Full Investment Date” means the date on which the Partnership or Operating Subsidiary has invested, committed for investment or otherwise spent 90% or more of the aggregate Capital Contributions made to the Partnership after deduction of Sales Commissions, Marketing Fee and Offering and Organization Expenses.

“General and Administrative Expenses” means all costs and expenses incurred by the General Partner and its Affiliates in connection with the management and operation of the Partnership’s business, including the direct and indirect costs and expenses of compensation, rental, office supplies, travel and entertainment, printing, legal, accounting, advertising, marketing and overhead.  However, General and Administrative Expenses shall not include any direct or indirect compensation costs or expenses paid to any of the beneficial owners of the General Partner, other than reimbursement of third party costs.

“General Partner” means Energy 11 GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interests held by it), and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Hedge Contract” means any exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of a Group Member to fluctuations in interest rates, the price of hydrocarbons, basis differentials or currency exchange rates in their operations or financing activities and not for speculative purposes.

“Incentive Distribution Rights” means a non-voting Limited Partner Interest issued to the General Partner in connection with the execution of this Agreement, which Limited Partnership Interest will confer upon the holder thereof only the rights and obligations specifically provided for in this Agreement with respect to Incentive Distribution Rights; provided that, so long as the General Partner owns the Incentive Distribution Rights 1% of such Incentive Distribution Rights shall be deemed a General Partner Interest for all purposes of this Agreement.

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a member, manager, managing member, partner, director, officer, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a manager,  officer, director, member, partner, fiduciary or trustee of another Person; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Initial Closing Date” means the date, which shall not be after the Offering Termination Date, after the minimum amount of subscription proceeds required by Section 5.5(b) has been received when subscription proceeds are first withdrawn by the Partnership from the escrow account and deposited into a Partnership account.

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“Interim Closing Date” means those date(s) after the Initial Closing Date, but before the Offering Termination Date, that the General Partner, in its sole discretion, accepts additional subscriptions to purchase Units, and issues Units to the persons who have executed Subscription Agreements in consideration for payment to the Partnership of the subscription price for such Units.

“Key Employees” has the meaning assigned to such term in the Management Agreement.

“Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner prior to its withdrawal from the Partnership, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement, in each case, in such Person’s capacity as a limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right or Class B Units (solely with respect to its Incentive Distribution Rights, or Class B Units and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.

“Limited Partner Interest” means the equity ownership interest of a Limited Partner or Assignee in the Partnership which may be evidenced by Units, Incentive Distribution Rights, Class B Units, or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right or Class B Units except as may otherwise be required by applicable law.

 “Liquidity Event” means any of the following transactions: a sale of all or substantially all of the Partnership’s consolidated assets and distribution of the net proceeds of such sale (after payment of, or reservation for, liabilities of the Partnership and its Subsidiaries), a merger or consolidation of the Partnership with another entity or a listing of the Common Units on a National Securities Exchange or any other transaction approved by the General Partners as a Liquidity Event in which the Limited Partners receive cash, property or marketable securities in exchange for, or as a distribution (other than normal monthly distributions from Available Cash) with respect to their Common Units.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Management Agreement” means the Management Services Agreement dated August 19, 2015, between the Partnership, the Operating Subsidiary and the Manager, as such agreement may be amended from time to time.

“Manager” means E11 Management, LLC, in its capacity as Manager under the Management Agreement.

“Manager Change of Control” has the meaning set forth in the Management Agreement.

“Marketing Fee” means a fee of 1% of the purchase price of Units payable to the Dealer Manager pursuant to the Dealer Manager Agreement with respect to the sale of Units, other than Units purchased by the General Partner, its officers, directors, employees and Affiliates, and its Affiliates’ respective officers, directors and employees.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“Month” means any calendar month.

“Monthly Distribution Date” has the meaning provided in Section 6.1.

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“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act, and any successor to such statute, or the Nasdaq Global Market, Nasdaq Global Select Market, or any successor thereto.

“Net Agreed Value” has the meaning assigned to such term in Exhibit B.

“Net Investment Amount” means for each Unit $20.00 minus the amount previously distributed with respect to such Unit in excess of the Payout Accrual at the time of such distribution.

“Non-citizen Assignee” means a Person whom the General Partner has determined does not constitute an Eligible Citizen and as to whose Partnership Interest the General Partner has become the Substituted Limited Partner, pursuant to Section 4.9.

“Offering and Organization Expenses” has the meaning set forth in the Management Agreement.

“Offering Termination Date” means (i) the date after the minimum amount of subscription proceeds has been received on which the General Partner determines, in its sole discretion, that the Partnership’s subscription period is closed and the acceptance of subscriptions ceases, which may be any date up to and including January 23, 2017 unless this offering is extended by the General Partner until no later than April 24, 2017 pursuant to a supplement to the Prospectus or (ii) January 23, 2017 if the minimum amount of subscription proceeds has not been received by that date.

Notwithstanding the above, the Offering Termination Date may not extend beyond the time that subscriptions for the maximum number of Interests set forth in Section 5.5(a) have been received and accepted by the General Partner.

“Operating Subsidiary” means Energy 11 Operating Company, LLC, a Delaware limited liability company of which the Partnership is the sole member, and any successors thereto.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner or to such other Person selecting such counsel or obtaining such opinion.

“Organizational Limited Partner” means DMOG, LLC in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to any class of Limited Partner Interest, all Limited Partner Interests of such class that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Energy 11, L.P., a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means any equity interest, including any class or series of equity interest, in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“Partnership Register” means a register maintained on behalf of the Partnership by the General Partner, or, if the General Partner so determines, by the Transfer Agent as part of the Transfer Agent’s books and transfer records, with respect to each class of Partnership Interests in which all Record Holders and transfers of such class of Partnership Interests are registered or otherwise recorded.

“Payout” occurs at any time when the aggregate amount of distributions made by the Partnership equals the total Payout Accrual at such time plus $20.00 per Outstanding Common Unit.

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“Payout Accrual” means for each Month and for each Unit, an amount equal to one-twelfth of 7% of the Net Investment Amount of such Unit for such Month, calculated based on a year composed of twelve 30-day months; provided, however, that (a) for the Month in which a Unit is first issued, the Payout Accrual for those units will be the result of multiplying the Payout Accrual for such Month by the ratio (which shall not be greater than 1) of the number of days during the Month during which the Unit was Outstanding divided by 30, (b) for the Month in which the liquidation occurs, the Payout Accrual will be the result of multiplying the Payout Accrual by the ratio (which shall not be greater than 1) of the number of days during the Month prior to the date of the liquidation divided by 30 and (c) Units issued on the last day of any Month shall not be entitled to a Payout Accrual for the Month in which the Unit is issued.

“Percentage Interest” means, as of any date of determination as to any Unitholder with respect to Units, the quotient of the number of Units held by such Unitholder divided by the total number of Outstanding Units.  The Percentage Interest with respect to the Incentive Distribution Rights, and Class B Units shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, group, association, government agency or political subdivision thereof or other entity.

“Plan of Conversion” is defined in Section 14.1.

“Pro Rata” means (a) when used with respect to Units, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners and Assignees or Record Holders, apportioned among all Partners and Assignees or Record Holders in accordance with their relative Percentage Interests, and (c) when used with respect to holders of Incentive Distribution Rights or Class B Units, apportioned equally among all holders of Incentive Distribution Rights or Class B Units in accordance with the relative number or percentage of Incentive Distribution Rights or Class B Units held by each such holder.

“Prospectus” means the prospectus and any supplement filed as part of the Registration Statement.

“Qualifying Owners” means the beneficial owners of the General Partner on the date of this Agreement and the conservators, guardians, executors, administrators, testamentary trustees, legatees or beneficiaries of such a beneficial owner and a partnership, limited liability company, corporation, trust, private foundation or custodianship, the beneficiaries of which include the current beneficial owners of the General Partner, his or her spouse (or ex-spouse) or his or her lineal descendants (including adopted) or, if at any time after any such transfer there shall be no then living spouse or lineal descendants, then to the estate of a deceased beneficiary.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution.

“Record Holder” means (a) with respect to the Units, the Person in whose name a Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on a particular Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

“Registration Statement” means the Registration Statement on Form S-1 (SEC Registration No. 33-197476) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Units.

“Sales Commission” means a commission of 5% of the purchase price of Units payable to the Dealer Manager pursuant to the Dealer Manager Agreement with respect to the sale of Units, other than Units purchased by the General Partner, its officers, directors, employees and Affiliates, and its Affiliates’ respective officers, directors and employees.

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“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time, and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute.

“Subscription Agreement” means the agreement pursuant to which a prospective Limited Partner subscribes to purchase Units, including all riders and exhibits thereto, a form of which is filed as an Exhibit to the Prospectus.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).

“Transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Units; provided, that unless a transfer agent is appointed by the General Partner, the General Partner shall act in such capacity with respect to the Incentive Distribution Rights and Class B Units.

“Unit” means a Limited Partner Interest representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to Units in this Agreement.  Units shall not include the Class B Units.

“Unit Majority” means at least a majority of the Outstanding Units.

“Unitholders” means the holders of Units.

“U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

Section 1.2Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement.  The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.  The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. To the fullest extent permitted by applicable law, any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in good faith shall, in each case, be conclusive and binding on all Record Holders, each other Person who acquires an interest in a Partnership Interest and all other Persons for all purposes.

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ARTICLE II.

Organization

Section 2.1Formation.

The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Energy 11, L.P. in its entirety.  This amendment and restatement shall become effective on the date of this Agreement.  Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.  All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2Name.

The name of the Partnership shall be “Energy 11, L.P.” Subject to applicable law, the Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner.  The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires.  The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company.  The principal office of the Partnership shall be located at 120 W. 3rd Street, Fort Worth, Texas 76102, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.  The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate.  The address of the General Partner shall be 120 W. 3rd Street, Fort Worth, Texas 76102, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4Purpose and Business.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.  To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity and the General Partner in determining whether to propose or approve the conduct by the Partnership of any business shall be permitted to do so in its sole and absolute discretion.

Section 2.5Powers.

The Partnership shall be empowered to do any and all acts and things necessary or appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

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Section 2.6Power of Attorney.

(a)Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(i)execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; and (E) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and

(ii)execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b)The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner and the transfer of all or any portion of such Limited Partner’s Partnership Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives.  Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney.  Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

Section 2.7Term.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII.  The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

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Section 2.8Title to Partnership Assets.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof.  Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine.  The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner.  All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III.

Rights of Limited Partners

Section 3.1Limitation of Liability.

The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2Management of Business.

No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership.  No action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3Outside Activities of the Limited Partners.

Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group.  Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4Rights of Limited Partners.

(a)In addition to other rights provided by this Agreement, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:

(i)to obtain from the General Partner either (A) the Partnership’s most recent filings with the Commission on Form 10-K and any subsequent filings on Form 10-Q and 8-K or (B) if the Partnership is no longer subject to the reporting requirements of the Securities Exchange Act, the information specified in, and meeting the requirements of, Rule 144A(d)(4) under the Securities Act (provided that the foregoing materials shall be deemed to be available to a Limited Partner in satisfaction of the requirements of this Section 3.4(a)(i) if posted on or accessible through the Partnership’s or the Commission’s website);

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(ii)to obtain true and full information regarding the assets, the status of the business and financial condition of the Partnership;

(iii)to obtain a current list of the name and last known business, residence or mailing address of each Partner;

(iv)to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v)to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi)to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b)To the fullest extent permitted by applicable law, the rights to information granted the Limited Partners pursuant to Section 3.4(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners and each other Person who acquires an interest in the Partnership hereby agrees to the fullest extent permitted by applicable law that they do not have any rights as Partners or interest holders to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.4(a).

(c)The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

(d)Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Record Holders, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person.

ARTICLE IV.

Certificates; Record Holders;

Transfer of Partnership Interests;

Redemption of Partnership Interests

Section 4.1Certificates.

Record Holders of Partnership Interests shall be recorded in the Partnership Register and ownership of such interests shall be evidenced by a physical certificate or book entry notation in the Partnership Register.  Upon the Partnership’s issuance of a Unit to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued.  In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its General Partner Interest and (b) upon the request of any Person owning Incentive Distribution Rights or Class B Units, the Partnership shall issue to such Person one or more certificates evidencing such Incentive Distribution Rights or Class B Units.  Certificates shall be executed on behalf of the Partnership by any manager, the Chairman of the Board, President or any Executive Vice President, Senior Vice President or Vice President and the Secretary or any Assistant Secretary of the General Partner.  No Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to issue Units in global form, the Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Units have been duly registered in accordance with the directions of the Partnership.  With respect to any Partnership Interests that are represented by physical certificates (including Unit Certificates), the General Partner may determine that such Partnership Interests will no longer be

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represented by physical certificates and may, upon written notice to the holders of such Partnership Interests and subject to applicable law, take whatever actions it deems necessary or appropriate to cause such Partnership Interests to be registered in book entry or global form and may cause such physical certificates to be cancelled or deemed cancelled.

Section 4.2Mutilated, Destroyed, Lost or Stolen Certificates.

(a)  If any mutilated Certificate is surrendered to the Transfer Agent (for Units) or the General Partner (for Incentive Distribution Rights or Class B Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Units) or the General Partner (for Incentive Distribution Rights or Class B Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of securities as the Certificate so surrendered.

(b)Any Manager or the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Units) shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i)makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii)requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii)if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv)satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c)As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3Record Holders.

The names and addresses of Record Holders of Partnership Interests as they appear in the Partnership Register shall be the official list of Record Holders of the Partnership Interests for all purposes.  The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law.  Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Partnership Interest.

Section 4.4Transfer Generally.

(a)  The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Interest to another Person or by which a holder of Incentive Distribution Rights or Class B Units assigns its Incentive Distribution Rights or Class B Units to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than Incentive Distribution Rights or Class B Units assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner,

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and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b)No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV.  Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void, and the Partnership shall have no obligation to effect any such transfer or purported transfer.

(c)Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner or any Limited Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner or such Limited Partner, and the term “Transfer” shall not include any such disposition.

Section 4.5Registration and Transfer of Limited Partner Interests.

(a)The General Partner shall keep, or cause to be kept on behalf of the Partnership, the Partnership Register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.  The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Units and transfers of such Units as herein provided.  The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5.  Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), a manager or the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b)Upon the receipt of proper transfer instructions from the Record Holder of uncertificated Partnership Interests, such transfer shall be recorded in the Partnership Register.

(c)Except as otherwise provided in Section 4.9, the General Partner shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer.  No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.  Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of this Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered. Upon the proper surrender of a Certificate, such transfer shall be recorded in the Partnership Register.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.4. (iv)  Section 4.8, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests (other than the Incentive Distribution Rights or Class B Units) shall be freely transferable.

Section 4.6Transfer of the General Partner’s General Partner Interest; Transfer of Ownership of the General Partner.

(a)Subject to Section 4.6(b) below, the General Partner shall not transfer all or any part of its General Partner Interest to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Units (excluding Units owned by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

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(b)Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement and (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).  In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

(c)The General Partner shall not permit to occur a General Partner Change of Control unless prior to such General Partner Change of Control the General Partner receives the approval by consent or vote of the holders of a majority of the Outstanding Units, other than Units owned by the General Partner and its Affiliates.

Section 4.7  Transfer of Incentive Distribution Rights or Class B Units.

A holder of Incentive Distribution Rights or Class B Units may transfer any or all of the Incentive Distribution Rights or Class B Units held by such holder without any consent of the Unitholders to (a) an Affiliate of such holder or (b) another Person (other than an individual) in connection with (i) the merger or consolidation of such holder of Incentive Distribution Rights or Class B Units with or into such other Person, (ii) the transfer by such holder of all or substantially all of its assets to such other Person or (iii) the sale of all the ownership interests in such holder.  Any other transfer of the Incentive Distribution Rights or Class B Units prior to the third anniversary of the Offering Termination Date shall require the prior consent or vote of holders of at least a majority of the Outstanding Units other than Units held by the proposed transferee and its Affiliates.  Thereafter, a holder of Incentive Distribution Rights or Class B Units may transfer any or all of the Incentive Distribution Rights or Class B Units held by such owner without consent or vote of the holders of Units. No transfer of Incentive Distribution Rights or Class B Units to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.

Section 4.8Restrictions on Transfers.

(a)Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interest shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).  The Partnership may issue stop transfer instructions to any Transfer Agent in order to implement any restriction on transfer contemplated by this Agreement.

(b)The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes or (ii) preserve the uniformity of the Units.  The General Partner may impose such restrictions by amending this Agreement.

(c)Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY 11, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY 11, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY 11, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED).  ENERGY 11 GP, LLC, THE GENERAL PARTNER OF ENERGY 11, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT

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SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY 11, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES.  AFTER THE DATE THE UNITS EVIDENCED BY THIS CERTIFICATE ARE LISTED ON A NATIONAL SECURITIES EXCHANGE, THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.9Citizenship Certificates; Non-citizen Assignees.

(a)If any Group Member is or becomes subject to any federal, state or local law or regulation that the General Partner determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner, the General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request.  If a Limited Partner fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines, with the advice of counsel, that a Limited Partner is not an Eligible Citizen, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10.  In addition, the General Partner may require that the status of any such Limited Partner be changed to that of a Non-citizen Assignee and, thereupon, the General Partner shall be substituted for such Non-citizen Assignee as the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests and shall have all voting and consent rights attributable to the Non-citizen Assignee’s Limited Partner Interests.

(b)The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-citizen Assignees, distribute the votes in the same ratios as the votes of Partners (including the General Partner) in respect of Limited Partner Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter.

(c)Upon dissolution of the Partnership, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind.  Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Non-citizen Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(d)At any time after a Non-Citizen Assignee can and does certify that he has become an Eligible Citizen, such Non-citizen Assignee may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.10, such Non-citizen Assignee be admitted as a Limited Partner, and upon approval of the General Partner, such Non-citizen Assignee shall be admitted as a Limited Partner and shall no longer constitute a Non-citizen Assignee and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

Section 4.10Redemption of Partnership Interests of Non-citizen Assignees.

(a)If at any time a Limited Partner fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.9(a), or if upon receipt of such Citizenship Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner is not an Eligible Citizen, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is an Eligible Citizen or has transferred his Partnership Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

(i)The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid.  The notice shall be deemed to have been given when so mailed.  The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the

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Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii)The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests.  The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii)Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or his duly authorized representative shall be entitled to receive the payment therefor.

(iv)After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b)The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Citizen.

(c)Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement.  Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Citizen.  If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V.

Capital Contributions and

Issuance of Partnership Interests

Section 5.1Organizational Contributions.

In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $10.00, for a 1% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $990.00 for a 99% Limited Partner Interest in the Partnership and has been admitted as a Limited Partner of the Partnership.  As of the Initial Closing Date, the interest of the Organizational Limited Partner shall be redeemed and the initial Capital Contribution of the Organizational Limited Partner shall thereupon be refunded.  Ninety-nine percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

Section 5.2Offering of Units.

(a)The Partnership is authorized to admit to the Partnership on the Initial Closing Date, any Interim Closing Date(s), and the Offering Termination Date, additional Limited Partners whose Subscription Agreements for Units are accepted by the General Partner if, after the admission of the additional Limited Partners, the total number of Units sold does not exceed the maximum number of Units set forth in Section 5.5(a).

(b)No action or consent by the Limited Partners shall be required for the admission of additional Limited Partners pursuant to this Section 5.2.

(c)All subscribers’ funds shall be held in a non-interest bearing account or accounts by an independent escrow agent and shall not be released to the Partnership until the receipt and acceptance of the minimum amount of subscription proceeds set forth in Section 5.5(b). Thereafter, subscriptions may be paid directly to a Partnership account.

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Section 5.3Subscriptions by Participants.

The subscription price of a Unit shall be $19.00 for Units acquired prior to the issuance of 5,263,158 Units and $20.00 per Unit thereafter.  The aggregate subscription price shall be designated on each prospective Limited Partner’s Subscription Agreement and payable as set forth in Section 5.7(b).  The minimum subscription per prospective Limited Partner shall be for a minimum of $5,000. Subscriptions for fractional Units shall not be accepted.  For the avoidance of doubt, immediately after the issuance of 5,263,158 Units the Net Investment Amount of the Units issued for $19.00 per Unit shall be $20.00 per Unit.

Section 5.4Effect of Subscription

(a)Execution of a Subscription Agreement shall serve as an agreement by the prospective Limited Partner to be bound by each and every term of this Agreement, if such Subscription Agreement is accepted by the General Partner.

(b)In addition to the General Partner’s required Capital Contributions under Section 5.7(a), the General Partner may subscribe for Units, which amount of Units shall not be applied towards the minimum number of Units required to be sold under Section 5.5(b), to the extent of such additional subscriptions, the General Partner shall be deemed to be a Limited Partner in the Partnership for all purposes under this Agreement.

Section 5.5Maximum and Minimum Number of Units.

(a)The maximum number of Units may not exceed 100,263,158 Units, which is $2,000,000,002 of cash subscription proceeds.

(b)The minimum number of Units shall equal at least 1,315,790 Units, but in any event not less than the number of Interests that provides the Partnership with cash subscription proceeds of $25,000,010.

(c)If subscriptions for the minimum number of Units have not been received and accepted at the Offering Termination Date, then all monies deposited by subscribers shall be promptly returned to them, without deduction for any fees.

(d)The Partnership may withdraw subscription proceeds from escrow and begin its activities, in the General Partner’s sole discretion, upon receipt and acceptance of the minimum subscription proceeds stipulated in Section 5.5(b).

Section 5.6Acceptance of Subscriptions.

(a)Acceptance of subscriptions is discretionary with the General Partner. The General Partner may reject any subscription for any reason it deems appropriate.

(b) Subscriptions shall be accepted or rejected by the General Partner within 30 days after their receipt by the General Partner. If a subscription is rejected, then all of the subscriber’s funds shall be returned to the subscriber promptly, without interest and without deduction for any fees.

(c)The Limited Partners shall be admitted to the Partnership as follows:

(i)Once subscriptions for the minimum number of Units have been received and accepted by the General Partner, the General Partner shall set the Initial Closing Date, which shall be no later than 30 days after the receipt and acceptance of minimum subscription proceeds equal to the minimum subscription; or

(ii)if a prospective Limited Partner’s subscription proceeds are received by the Partnership after the Initial Closing Date, the General Partner shall set an Interim Closing Date on the last day of the calendar month in which the General Partner accepted the prospective Limited Partner’s Subscription Agreement.

Section 5.7Capital Contributions of the General Partner; Payment of Subscriptions.

(a)The General Partner shall not be required to make any additional Capital Contributions to the Partnership.  At the Initial Closing, the General Partner shall be issued the Incentive Distribution Rights.

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(b)A prospective Limited Partner shall pay the subscription amount designated on his Subscription Agreement entirely in cash at the time of subscribing. A prospective Limited Partner shall not receive interest on the amount he pays from the time his subscription proceeds are deposited in the escrow account until his subscription proceeds are paid to the Partnership.

Section 5.8Incentive Rights.

On the date of this Agreement, the Partnership shall issue the Incentive Distribution Rights to the General Partner.

Section 5.9Class B Units

(a)At the Initial Closing and in consideration for services rendered or to be rendered to or for the benefit of the Partnership, the Partnership shall issue 100,000 Class B Units to the Class B Holder.  Except as provided in Section 5.9(f), the Partnership shall not issue any additional Class B Units without the consent of the holders of a majority of the Outstanding Class B Units.

(b)  (i)  If (A) the Management Agreement is terminated by the Operating Subsidiary pursuant to Section 10.2(b)(v) or Section 10.2(b)(vii) of the Management Agreement, then concurrently with such termination all of the Class B Units Outstanding shall be forfeited, cancelled and cease to be Outstanding.

(ii)           If (A) the Management Agreement is terminated by the Operating Subsidiary before the Full Investment Date, and (B) such termination by the Operating Subsidiary was made (I) at any time within 30 days after a Manager Change in Control, (II) in accordance with Section 8.2(b) of the Management Agreement because the Key Employees cease to be employed on a full time basis by the Manager or (III) during the Bankruptcy of the Manager, then concurrently with such termination a portion of the Class B Units Outstanding shall be forfeited, cancelled and cease to be Outstanding equal to the sum of (X) 37.5% of the Class B Units Outstanding plus (Y) a portion of the Class B Units Outstanding equal to the product of the Class B Units Outstanding immediately before such forfeiture multiplied by a fraction of which the numerator is (AA) the aggregate Capital Contributions made to the Partnership by the holders of Units that have not been invested, committed for investment or otherwise spent by the Partnership as of the date of such termination, and (BB) the denominator of which is the aggregate Capital Contributions made by holders of Units to the Partnership as of the date of such termination.

(iii)           If the Management Agreement is terminated by the Operating Subsidiary pursuant to Section 10.2(b)(vi) of the Management Agreement, then concurrently with such termination, a number of Class B Units shall be cancelled, forfeited and shall cease to be Outstanding equal to the number Class B Units Outstanding multiplied by a fraction the numerator of which shall be the amount of Unallocated Funds on the date of termination and the denominator of which shall be the total net Capital Contributions made to the Partnership (after deduction of Sales Commissions, Marketing Fees and Offering and Organization Expenses), plus the amount of borrowings outstanding under an Approved Credit Facility plus the amount that is available to be borrowed under an Approved Credit Facility, in each case as of the date of termination.

(iv)           If (A) the Management Agreement is terminated by the Operating Subsidiary  on or after the Full Investment Date, and (B) such termination by the Operating Subsidiary was made (I) at any time within 30 days after a Manager Change in Control, (II) in accordance with Section 8.2(b) of the Management Agreement because the Key Employees cease to be employed on a full time basis by the Manager or (III) during the Bankruptcy of the Manager, then concurrently with such termination 37.5% of the Class B Units Outstanding shall be forfeited, cancelled and cease to be Outstanding.

(c)Except as provided in this Section, the termination of the Management Agreement shall not forfeit, cancel or otherwise affect the Class B Units.  If Class B Units are forfeited, cancelled and cease to be Outstanding pursuant to this Section 5.09, and there is more than one Record Holder of Class B Units, Class B Units will be forfeited, cancelled and cease to be Outstanding on a pro rata basis among the Record Holders, pro rata based on the number of Class B Units owned on the date of termination of the Management Agreement.

(d)The forfeiture and cancellation of the Class B Units will not require the holder of such Class B Units or any former holder to repay any distribution previously made.

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(e)The Class B Units issued and Outstanding as of the date of a Liquidity Event (including any equity interests into which such Class B Units may be converted or exchanged) will cease to be subject to forfeiture and cancellation pursuant to Section 5.9(b) above from and after the date of a Liquidity Event.

(f)The General Partner may cause the Partnership to issue a number of Class B Units equal to the number of Class B Units forfeited under this Section to a Person who performs services to the Partnership or other Group Member for such consideration as the General Partner determines, without the consent of any Limited Partner.

Section 5.10Profits Interests.

The Incentive Distribution Rights and Class B Units are intended to constitute “profits interests” within the meaning of Revenue Procedures 93-27 and 2001-43, and the Partnership and the Dealer Manager, General Partner, and Class B Holder shall file all federal income tax returns consistent with such characterization. By executing this Agreement, each Partner authorizes and directs the Partnership to elect to have the “safe harbor” described in the proposed Revenue Procedure set forth in Internal Revenue Service Notice 2005-43 (the “IRS Notice”), including any similar safe harbor in any finalized revenue procedure, revenue ruling or United States Treasury Regulation, apply to any Incentive Distribution Right, Class B Units or other interests issued by the Partnership for services rendered to or on behalf of the Partnership.  For purposes of making such safe harbor election, the Partner designated as the “tax matters partner” pursuant to this Agreement is hereby designated as the “partner who has responsibility for federal income tax reporting” by the Partnership and, accordingly, execution of such safe harbor election by the “tax matters member” constitutes execution of a “safe harbor election” in accordance with the IRS Notice or any similar provision of any final pronouncement.  The Partnership and each Partner hereby agree to comply with all requirements of any such safe harbor, including any requirement that a Partner prepare and file all federal income tax returns reporting the income tax effects of each interest issued by the Partnership in connection with services in a manner consistent with the requirements of the IRS Notice or other final pronouncement.

Section 5.11Interest and Withdrawal.

No interest shall be paid by the Partnership on Capital Contributions.  No Partner or Assignee shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement.  Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner or Assignee either as to the return of Capital Contributions or as to profits, losses or distributions.  Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.12Fully Paid and Non-Assessable Nature of Limited Partner Interests.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.

ARTICLE VI.

Distributions; Allocations and Capital Accounts

Section 6.1Distributions; Distributions to Record Holders.

(a) Available Cash shall be determined by the General Partner, taking into account the Partnership’s current and anticipated future operating and capital needs.  Each such determination shall be made by the General Partner following the end of each Month after the Initial Closing.  The General Partner shall distribute to the Partners such cash, if any, as the General Partner determines in its sole and absolute discretion constitutes Available Cash, which distribution, if any, shall be made in accordance with Section 6.2 within 30 days following the end of the Month in respect of which such determination of Available Cash is made by the General Partner (the date such distribution is made is referred to as the “Monthly Distribution Date”).  In addition, a portion of Available Cash will be used to pay the Dealer Manager Contingent, Incentive Fee.

(b) Notwithstanding Section 6.1(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Month in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

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(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution.  Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.2 Distributions of Available Cash; Payment of Dealer Manager Contingent, Incentive Fee.

Available Cash for any Month determined pursuant to Section 6.1 shall be distributed, allocated and paid to the Partners and paid to the Dealer Manager as follows:

(a)Until Payout occurs, Available Cash for any Month determined pursuant to Section 6.1 shall be distributed, allocated and paid 100% to the Record Holders of Outstanding Units.  Distributions to holders of Outstanding Units prior to Payout will be allocated and paid (i) first to Record Holders of Outstanding Units in the amount of the Payout Accrual with respect to Outstanding Units owned, Pro Rata based on the amount of such Payout Accrual, and (ii) thereafter Pro Rata based on the number of Outstanding Units owned.

(b) After Payout, Available Cash for any Month determined pursuant to Section 6.1 shall be distributed, allocated and paid to the Partners and paid to the Dealer Manager as follows:

(1)           First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B Units, Pro Rata based on the number of Class B Units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B Units Outstanding and the denominator of which is 100,000; (iii) to the Dealer Manager, as the Dealer Manager Contingent Incentive Fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any, to the Record Holders of Outstanding Units, Pro Rata based on their Percentage Interest until such time as the Dealer Manager receives the full amount of the Dealer Manager Contingent Incentive Fee under the Dealer Manager Agreement;

(2)           Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B Units, Pro Rata based on the number of Class B Units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B Units Outstanding and the denominator of which is 100,000; and (iii) the remaining amount to the Record Holders of Outstanding Units, Pro Rata based on their Percentage Interest.

Section 6.3Restrictions on Distributions.

Prior to the Offering Termination Date, the General Partner shall not make any distributions of Available Cash to the Partners, on any Monthly Distribution Date in excess of the aggregate Payout Accrual as of the end of the most recently completed Month.  All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act and other applicable law, notwithstanding any other provision of this Agreement.

Section 6.4Capital Accounts.

Capital Accounts shall be maintained and all items of income, gain, deduction, loss or credit shall be allocated among the Partners as provided in Exhibit B.

ARTICLE VII.

Management and Operation of Business

Section 7.1Management.

(a)The Operating Subsidiary and the Manager shall enter into the Management Agreement which shall become effective on the Initial Closing Date.  The General Partner shall conduct, direct and manage all activities of the Partnership, including making all decisions for the Partnership under the Management Agreement.  Except as otherwise expressly

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provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership.  In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i)cause the Partnership to enter into and perform pursuant to the Management Agreement with the Manager, including causing the Partnership to approve or reject any acquisitions, operations or other activities or transactions recommended by the Manager as contemplated by the Management Agreement, supervising the activities of the Manager under the Management Agreement, and to otherwise cause the Partnership and Operating Subsidiary to enforce its rights under, and perform its obligations pursuant to, the Management Agreement;

(ii)cause the Partnership to enter into the Dealer Manager Agreement with the Dealer Manager and to perform its obligations thereunder;

(iii)cause the Partnership and Operating Subsidiary to acquire interests in oil and gas properties having the attributes described in the Registration Statement, provided that the General Partner may cause the Partnership to acquire interests in properties that do not have such attributes if the General Partner determines, in good faith, that the acquisition of such properties is in the best interest of the Partnership;

(iv)the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness and the incurring of any other obligations;

(v)the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(vi)the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iv) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

(vii)the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(viii)the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(ix)the distribution of Partnership cash and the payment of the Contingent, Incentive Fee pursuant to the Dealer Manager Agreement;

(x)the selection and dismissal of employees and officers and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(xi)the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(xii)the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

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(xiii)the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xiv)the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xv)if the General Partner determines that the Units may be eligible for listing on a National Securities Exchange, and that such listing would be in the best interests of other holders of Units, the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to Section 7.3(c) and any prior approval that may be required under Section 4.8);

(xvi) the purchase, sale or other acquisition of Units, Incentive Distribution Rights or Class B Units;

(xvii)the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

(xviii)the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and the Assignees and each other Person who may acquire an interest in the Units, Incentive Distribution Rights or Class B Units hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Management Agreement, the Dealer Manager Agreement and the Group Member Agreement of each other Group Member, and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the Assignees or the other Persons who may acquire an interest in the Units, Incentive Distribution Rights or Class B Units; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

(c) The General Partner shall conduct the Partnership’s business so that an amount equal to at least 65% of the gross proceeds from the sale of Common Units are invested in the acquisition, development, exploration, exploitation of oil and gas properties and related capital assets.

Section 7.2Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act.  The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property.  To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property.  Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

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Section 7.3Restrictions on the General Partner’s Authority; Agreement by Owners of the General Partner.

(a)Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.  Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6, Section 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

(b)The General Partner will not cause the Partnership to acquire an interest in an oil and gas property located offshore or located outside of the United States without the approval of a Unit Majority.

(c)The General Partner may not cause the Units to be listed on a National Securities Exchange without the approval of a Unit Majority.

(d) Each beneficial owner (“GP Owner”) of the General Partner who has executed a counterpart of this Agreement agrees that, until the Full Investment Date, the GP Owner will not acquire, directly or indirectly through any entity formed or controlled by such GP Owner, a working interest in an oil and gas property (a “Business Opportunity”) where the Business Opportunity was referred to the GP Owner or an entity formed or controlled by the GP Owner by the Manager (or an Affiliate of the Manager).  

Section 7.4Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed from time to time for all of the Offering and Organization Expenses incurred by the General Partner.

(c) The General Partner shall be reimbursed for all of its and its Affiliates’ General and Administrative Expenses incurred in connection with the Partnership’s business. If the General Partner or any of its Affiliates engages in any business activities other than acting as the General Partner of the Partnership, the General Partner shall allocate its and its Affiliates’ General and Administrative Expenses to the Partnership and such other activities in any manner deemed reasonable by the General Partner.

(d) The General Partner shall be reimbursed on a Monthly basis for all of the allocable portion of third-party expenses it incurs or payments it makes on behalf of the Partnership Group.  The General Partner shall determine the expenses that are allocable to the Partnership Group.  All reimbursements under this Section 7.4(b) shall be supported by appropriate invoices or other documentation.  Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

Section 7.5Outside Activities.

(a)After the Initial Closing Date, the General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.

(b)Each Indemnitee (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently

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or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner or Assignee.  None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee.

(c)Notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of any Indemnitee for the Indemnitees (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Indemnitees shall have no obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Partnership.  Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner).  No Indemnitee (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership.

(d) The General Partner and each of its Affiliates may acquire Units, Incentive Distribution Rights or Class B Units in addition to those acquired on the Initial Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units, Incentive Distribution Rights or Class B Units acquired by them.  The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e)The Partners (and the General Partner on behalf of the Partnership) hereby:

(i)agree that (A) the terms of this section, to the extent that they modify or limit a duty, if any, that a Partner may have to the Partnership or another Partner, are reasonable in form, scope and content; and (B) the terms of this section shall control to the fullest extent possible if it is in conflict with a duty, if any, that a Partner may have to the Partnership or another Partner, the Act or any other applicable law, rule or regulation; and

(ii)waive a duty, if any, that a Partner may have to the Partnership or another Partner, under the Act or any other applicable law, rule or regulation to the extent necessary to give effect to the terms of this section;

it being expressly acknowledged and affirmed by the Partners (and the General Partner on behalf of the Partnership) that the execution and delivery of this Agreement by the Partners are of material benefit to the Partnership and the Partners and that the Partners would not be willing to execute and deliver this Agreement without the benefit of this section.

Section 7.6Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a)The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner.  The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds.  For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b)The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner.  No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

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(c)No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the amount that would have been distributed to the General Partner of such Affiliate without such borrowing.

Section 7.7Indemnification.

(a)To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful.  Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b)To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c)The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Dealer Manager Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d)The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e)For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f)In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g)An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h)The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

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(i)No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Units, Incentive Distribution Rights or Class B Units, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b)Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c)To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d)Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a)Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates or an Indemnitee, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates or an Indemnitee in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by the vote of a majority of the Units (excluding Units owned by the General Partner and its Affiliates), (ii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iii) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership).  If the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (ii) or (iii) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption that the Board of Directors acted in good faith.  Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

(b)Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any

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other or different duties (including fiduciary duty) or standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, subject to the implied covenant of good faith and fair dealing imposed under Delaware law.  In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c)Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other duty or standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, subject to the implied covenant of good faith and fair dealing imposed under Delaware law. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a limited partnership.

(d)The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its member(s), if the General Partner is a limited liability company, stockholder(s), if the General Partner is a corporation, or the member(s) or stockholder(s) of the General Partner’s general partner, if the General Partner is a partnership.

(e)Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates or any Indemnitee, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates or any Indemnitee to enter into such contracts shall be at its option.

(f)Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(g)The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10Other Matters Concerning the General Partner.

(a)The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b)The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel or fairness opinion of an investment banker) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.  Without limiting the forgoing, if the General Partner receives a fairness opinion from an investment banker regarding the fairness, from a

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financial point of view, of a transaction or the consideration paid or payable in a transaction, including a purchase or sale of property or in connection with the listing of the Units on an National Securities Exchange, and the General Partner relies on such opinion in taking or omitting to take an action, such action shall be conclusively presumed to have been taken or not taken in good faith.

(c)The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership.

Section 7.11 Purchase or Sale of Units, Incentive Distribution Rights or Class B Units.

The General Partner may cause the Partnership to purchase or otherwise acquire Units, Incentive Distribution Rights or Class B Units.  Such Units, Incentive Distribution Rights, or Class B Units shall be held by the Partnership as treasury securities unless they are expressly cancelled by action of an appropriate officer of the General Partner.  As long as Units, Incentive Distribution Rights or Class B Units are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein.  The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Units, Incentive Distribution Rights or Class B Units for its own account, subject to the provisions of Articles IV and X.

Section 7.12Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and manager or any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such manager or officer as if it were the Partnership’s sole party in interest, both legally and beneficially.  Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such manager or officer in connection with any such dealing.  In no event shall any Person dealing with the General Partner or any such manager or officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such manager or officer or its representatives.  Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII.

Books, Records, Accounting and Reports

Section 8.1Records and Accounting.

The General Partner shall keep, or cause to be kept by the Manager under the Management Agreement, at the principal office of the Partnership or Manager appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a).  Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time.  The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2Fiscal Year.

The fiscal year of the Partnership shall be a fiscal year ending December 31.

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Section 8.3Reports.

(a)As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall use its best efforts to cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b)As soon as practicable, but in no event later than 90 days after the close of each quarter except the last quarter of each fiscal year, the General Partner shall use its best efforts to cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX.

Tax Matters

Section 9.1Tax Returns and Information.

The Partnership shall timely (taking into account applicable extensions) file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable year or years that it is required by law to adopt, from time to time, as determined by the General Partner.  In the event the Partnership is required to use a taxable year other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable year of the Partnership to a year ending on December 31.  The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them as soon as available.  The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2Tax Elections.

Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any elections permitted by the Code.

Section 9.3Tax Controversies.

Subject to the provisions hereof, the General Partner is designated as the “tax matters partner” (as defined in Section 6231(a)(7) of the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith.  Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4Withholding.

Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code.  To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner or Assignee (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.2 and B1.2 of Exhibit B in the amount of such withholding from such Partner.

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ARTICLE X.

Admission of Partners

Section 10.1Admission of Limited Partners.

(a)By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger consolidation pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) grants the powers of attorney set forth in this Agreement and (v) makes the consents and waivers contained in this Agreement, all with or without execution of this Agreement by such Person.  The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.  A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners.  A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest.  The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.9.

(b)The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent.  The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable).  A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(c)With respect to any Limited Partner that holds Units representing Limited Partner Interests for another Person’s account (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such Limited Partner shall, in exercising the rights of a Limited Partner in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, take all action as a Limited Partner by virtue of being the Record Holder of such Units at the direction of the Person who is the beneficial owner, and the Partnership shall be entitled to assume such Limited Partner is so acting without further inquiry.

(d)Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

Section 10.2Admission of Successor General Partner.

A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission.  Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3Amendment of Agreement and Certificate of Limited Partnership.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

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ARTICLE XI.

Withdrawal or Removal of Partners

Section 11.1Withdrawal of the General Partner.

(a)The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i)The General Partner voluntarily withdraws from the Partnership as provided in Section 11.1(b)(i);

(ii)The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii)The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iii); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(iv)A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(v)(A) If the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) if the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise, in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iii), Section 11.1(a)(iv), or Section 11.1(a)(v)(A), Section 11.1(a)(v)(B), Section 11.1(a)(v)(C) or Section 11.1(a)(v)(E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence.  The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b)Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances:  (i) the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Units (excluding Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); or (ii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii).  The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members.  If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner.  The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member.  If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1.  Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.

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Section 11.2Removal of the General Partner.

The General Partner may not be removed as General Partner of the Partnership.

Section 11.3Interest of Departing General Partner and Successor General Partner.

(a)In the event of withdrawal of the General Partner, if the successor General Partner is elected in accordance with the terms of Section 11.1, the Departing General Partner shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner, to require its successor to purchase its General Partner Interest and its general partner interest (or equivalent interest), if any, in the other Group Members (collectively, the “Combined Interest”) in exchange for $100.00 in cash.

(b)If a successor General Partner is elected in accordance with the terms of Section 11.1 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount of $100.00.

Section 11.4Withdrawal of Limited Partners.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII.

Dissolution and Liquidation

Section 12.1Dissolution.

The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement.  Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership.  The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a)an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) and such successor is admitted to the Partnership pursuant to Section 10.3;

(b)an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(c)the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act;

(d)at any time after the Full Investment Date, the election of the General Partner to cause the Partnership to dissolve if, at the time such election is made, the present value, discounted at 10%, of the estimate net after-tax cash flow attributable to the Partnership’s consolidated oil and gas proved reserves as reflected in the most recent annual audited financial statements (or if not included in such financial statements, as determined by the General Partner) is less than 20% of the aggregate Capital Contributions received by the Partnership (after the deduction of Sales Commissions, Marketing Fees and Offering and Organization Expenses); or

(e)at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2Continuation of the Business of the Partnership After Dissolution.

Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal of the General Partner as provided in Section 11.1(a)(i) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iii), Section 11.1(a)(iv) or Section 11.1(a)(v), then, to the maximum extent permitted by applicable law, within 180 days thereafter, the holders of a Unit Majority may elect to

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continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority.  Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs.  If such an election is so made, then:

(i)the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii)if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii)the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3Liquidator.

Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall act as, or shall select one or more Persons to act as, Liquidator.  The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Units.  The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Units.  Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Units.  The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided.  Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4Liquidation.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a)The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree.  If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners.  The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners.  The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b)Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI.  With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash

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or other assets to provide for its payment.  When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c)All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with Section 6.2.

Section 12.5Cancellation of Certificate of Limited Partnership.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6Return of Contributions.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7Waiver of Partition.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8Capital Account Restoration.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership.  The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII.

Amendment of Partnership Agreement;

Meetings; Record Date

Section 13.1Amendments to be Adopted Solely by the General Partner.

Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a)a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b)admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c)a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d)a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be

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listed or admitted to trading or (iii)  is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e)a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Month” and the dates on which distributions are to be made by the Partnership;

(f)an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g)any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(h)an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(i)an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

(j)any merger, conveyance or conversion pursuant to Section 14.3(d); or

(k)any other amendments substantially similar to the foregoing.

Section 13.2Amendment Procedures.

Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the following requirements.  Amendments to this Agreement may be proposed only by the General Partner; provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.  A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law.  Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment.  If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment.  The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3Amendment Requirements.

(a)Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of (i) in the case of any provision of this Agreement other than Section 13.4, reducing such percentage or (ii) in the case of Section 13.4, increasing such percentages, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute in the case of a reduction as described in sub-clause (a)(i) hereof, not less than the voting requirement sought to be reduced, or in the case of an increase in the percentage in Section 13.4, not less than a majority of the Outstanding Units.

(b)Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

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(c) Without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners or Assignees as contemplated in Section 13.1, (i) any amendment that affects only the Class B Units or the duties, responsibilities, rights and preferences of the holders of the Class B Units maybe proposed only by the General Partner as contemplated by Section 13.2, and shall be effective upon its approval by the General Partner and the holders of a majority of the Outstanding Class B Units and shall not require the approval of the holders of Units, (ii) any amendment that affects only the Incentive Distribution Rights or the duties, responsibilities, rights and preferences of the holders of the Incentive Distribution Rights maybe proposed only by the General Partner as contemplated by Section 13.2, and shall be effective upon its approval by the General Partner and the holders of the Incentive Distribution Rights and shall not require the approval of the holders of Units and (iii) any amendment that would have a material adverse effect on the rights or preferences of the Incentive Distribution Rights or Class B Units must be approved by the holders of  the Outstanding Incentive Distribution Rights or the holders of not less than a majority of Class B Units, as applicable; provided that for an amendment made in connection with a Liquidity Event, the owners of such Incentive Distribution Rights or Class B Units may not unreasonably withhold such approval. Any amendment of this Section 13.3(c) shall require the approval of the General Partner and the holders of a majority of the Outstanding Incentive Distribution Rights and Class B Units.

(d)Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

Section 13.4Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII.  Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units.  Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called.  Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent.  A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting.  Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business, and if any such vote were to take place, to the fullest extent permitted by law, it shall be deemed null and void to the extent necessary so as not to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written in accordance with Section 15.1.  The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6Record Date.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals.  If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of

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business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7Postponement and Adjournment.

Prior to the date upon which any meeting of Limited Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be fixed unless such postponement shall be for more than 45 days.  When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days.  At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting.  If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8Waiver of Notice; Approval of Meeting; Approval of Minutes.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy.  Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9Quorum and Voting.

The holders of a majority of the Outstanding Units (including Outstanding Units deemed owned by the General Partner), present in person or represented by proxy, shall constitute a quorum at a meeting of Unitholders unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage.  At any meeting of the Unitholders duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required.  The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner).  In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10Conduct of a Meeting.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting.  The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting.  All minutes shall be kept with the records of the Partnership maintained by the General Partner.  The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes

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and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11Action Without a Meeting.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern).  Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing.  The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner.  If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted.  If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12Right to Vote and Related Matters.

(a)Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act.  All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b)With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry.  The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

(c) Notwithstanding anything in this Agreement to the contrary, except as specifically provided in Sections 13.3 and 14.3 (and subject to the limitations set forth in such Sections) the owners of an Incentive Distribution Rights and Class B Units shall not be entitled to vote such Incentive Distribution Rights or Class B Units on the amendment of this Agreement or any other Partnership matter.

ARTICLE XIV.

Merger, Consolidation or Conversion

Section 14.1Authority.

The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

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Section 14.2Procedure for Merger, Consolidation or Conversion.

(a)Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Act or any other law, rule or regulation or at equity, subject to the implied covenant of good faith and fair dealing imposed under Delaware law.

(b)If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i)name and state of domicile of each of the business entities proposing to merge or consolidate;

(ii)the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii)the terms and conditions of the proposed merger or consolidation;

(iv)the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v)a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi)the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii)such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c)If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i)the name of the converting entity and the converted entity;

(ii)a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii)a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

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(iv)the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity;

(v)in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

(vi)in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii)the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such articles of conversion and stated therein); and

(viii)such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3Approval by Limited Partners.

(a)Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII.  A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b)Except as provided in Section 14.3(d), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, effects an amendment to any provision of this Agreement that, if contained in an amendment to this Agreement adopted pursuant to Article XIII, would require for its approval the vote, approval or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote, approval or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

(c)Except as provided in Section 14.3(d) or Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or articles of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d)Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

(e)Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another limited liability entity if (i) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1,

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(iii) the Partnership is the Surviving Business Entity in such merger or consolidation, (iv) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (v) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests (other than Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.

(f)Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity.  Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4Certificate of Merger or Certificate of Conversion.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or articles of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5Effect of Merger, Consolidation or Conversion.

(a)At the effective time of the certificate of merger:

(i)all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii)the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii)all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv)all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b)At the effective time of the articles of conversion:

(i)the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii)all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii)all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv)all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v)a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

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(vi)the Partnership Units that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV.

General Provisions

Section 15.1Addresses and Notices.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below.  Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interest at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interest by reason of any assignment or otherwise.  An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 15.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report.  If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners.  Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3.  The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

Section 15.2Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 15.3Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 15.4Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 15.5Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 15.6Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

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Section 15.7Third-Party Beneficiaries.

Each Partner agrees that any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.

Section 15.8Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.  Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereto.

Section 15.9Applicable Law; Forum, Venue and Jurisdiction; Waiver of Jury Trial.

(a)This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b)Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims; provided, however, that any claims, suits, actions or proceedings over which the Court of Chancery of the State of Delaware does not have jurisdiction shall be brought in any other court in the State of Delaware having jurisdiction;

(ii) irrevocably submits to the exclusive jurisdiction of the courts of the State of Delaware in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the courts of the State of Delaware or of any other court to which proceedings in the courts of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, however, that nothing in this clause (v) shall affect or limit any right to serve process in any other manner permitted by law.

Section 15.10Invalidity of Provisions.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

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Section 15.11Consent of Partners.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 15.12Facsimile Signatures.

The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Units is expressly permitted by this Agreement.

Remainder of Page Intentionally Left Blank.

Signature Page Follows.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

Energy 11 GP, LLC

By:  /s/ David S. McKenney

David S. McKenney                                  

Manager

LIMITED PARTNERS:

All Limited Partners now and hereafter admitted as Limited Partners of the Partnership, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to the General Partner, or without execution hereof pursuant to Section 10.1(a).

Energy 11 GP, LLC

By:  /s/ David S. McKenney 

David S. McKenney                                  

Manager

EXHIBIT A

to the

First Amended and Restated

Agreement of Limited Partnership

of

Energy 11, L.P.

Certificate Evidencing Units

Representing Limited Partner Interests

in

Energy 11, L.P.

No.  [         ] [         ] Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of Energy 11, L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), Energy 11, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that                               (the “Holder”) is the registered owner of Units representing limited partner interests in the Partnership (the “Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed.  The rights, preferences and limitations of the Units are set forth in, and this Certificate and the Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement.  Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 120 W. 3rd Street, Fort Worth, Texas 76102.  Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY 11, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY 11, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY 11, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED).  ENERGY 11 GP, LLC, THE GENERAL PARTNER OF ENERGY 11, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY 11, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES.  THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

Dated:    Countersigned and Registered by:     By:  as Transfer Agent and Registrar Energy 11, L.P.   By:         ENERGY 11 GP, LLC     By: 

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[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

TEN COM — as tenants in common   TEN ENT — as tenants by the entireties   JT TEN — as joint tenants with right of survivorship and not as tenants in common UNIF GIFT/TRANSFERS MIN ACT                        Custodian                                 (Cust)                     (Minor) under Uniform Gifts/Transfers to CD Minors Act (state)

Additional abbreviations, though not in the above list, may also be used.

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ASSIGNMENT OF UNITS

Energy 11, L.P.

FOR VALUE RECEIVED, _______________________________ hereby assigns, conveys, sells and transfers unto

                                                                                       (Please print or typewrite name and address of Assignee)                                                                                            (Please insert Social Security or other identifying number of Assignee)

Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint ______________________ as its attorney-in-fact with full power of substitution to transfer the same on the books of Energy 11, L.P.

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Date:    SIGNATURES MUST BE GUARANTEED BY A MEMBER OF THE FIRM OF THE NATIONAL ASSOCIATION OF SECURITIES DEALER, INC. OR BY A COMMERCIAL BANK OR TRUST COMPANY SIGNATURE(S) GUARANTEED NOTE: This signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.                                                                                  (Signature)                                                                                   (Signature)

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EXHIBIT B

ALLOCATIONS AND TAX PROCEDURES

B1.1           Definitions.  In addition to the capitalized terms used in the Agreement, as used in this Exhibit B, the following terms shall be defined as follows:

“Adjusted Capital Account” means the Capital Account, with respect to each Partner, maintained for such Partner as of the end of each taxable year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation sections 1.704-2(g) and 1.704-2(i)(5)), and (b) decreased by (i) adjustments that, as of the end of such taxable year, are reasonably expected to be made to such Partner’s Capital Account under Treasury Regulation section 1.704-1(b)(2)(iv)(k), (ii) the amount of all losses and deductions that, as of the end of such taxable year, are reasonably expected to be allocated to such Partner in subsequent years under sections 704(e)(2) and 706(d) of the Code and Treasury Regulation section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such taxable year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section B1.3(c)(i) or Section B1.3(c)(ii)).  The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section B1.2(d).

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section B1.3.

“Agreed Value” of any Contributed Property or Adjusted Property means the fair market value of such property at the time of contribution or adjustment as determined by the General Partner.  The General Partner shall use such method as it determines appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date.

“Carrying Value” means (a) with respect to Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all Depreciation and Simulated Depletion charged to the Partners’ Capital Accounts in respect of such Contributed Property or Adjusted Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination.  The Carrying Value of any property shall be adjusted from time to time in accordance with Section B1.2(d) to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Contributed Property” means each property or other asset, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted hereunder, such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Depreciation” means, for any Fiscal Year or other period, except as provided in Treasury Regulation section 1.704-3(d)(2), an amount equal to the depreciation, amortization, or other cost recovery deduction (other than depletion or Simulated Depletion) allowable with respect to an asset for such year or other period, except that, if the Carrying Value of an asset differs from its adjusted basis for federal income tax purposes at the beginning of such year or other period, Depreciation will be an amount that bears the same ratio to such beginning Carrying Value as the federal income tax depreciation, amortization, or other cost recovery deduction for such year or other period bears to such beginning adjusted tax basis; except that if the federal income tax depreciation, amortization, or other cost recovery deduction for such year

is zero, Depreciation will be determined with reference to such beginning Carrying Value using any reasonable method selected by the General Partner.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation section 1.752-2(a).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in section 705(a)(2)(b) of the Code), Simulated Depletion or Simulated Loss, that, in accordance with the principles of Treasury Regulation section 1.704- 2(b)(1), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning assigned to such term in Treasury Regulation section 1.704-2(b)(3).

“Partner Nonrecourse Debt” has the meaning set forth for “partner nonrecourse debt” in Treasury Regulation section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth for the term “partner nonrecourse debt minimum gain” in Treasury Regulation section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation section 1.704-2(i), are attributable to Partner Nonrecourse Debt.

“Partnership Minimum Gain” has the meaning given the term “partnership minimum gain” in Treasury Regulation section 1.704-2(b)(2) and the amount of which shall be determined in accordance with the principles of Treasury Regulation section 1.704-2(d).

“Percentage Interest in Partnership Capital” means, at any time of determination and as to any Partner, the percentage of the total distributions that would be made to such Partner if the assets of the Partnership were sold for their Carrying Values, all liabilities of the Partnership were paid in accordance with their terms, all items of Partnership income, gain, loss and deduction were allocated to the Partners in accordance with this Exhibit B, and the resulting net proceeds were distributed to the Partners in accordance with the terms of this Agreement.  The foregoing definition of Percentage Interest in Partnership Capital is intended to result in a percentage that corresponds with that defined as “partner’s proportionate interest in partnership capital” in Treasury Regulation sections 1.613A-3(e)(2)(ii) and 1.704-1(b)(4)(v), and Percentage Interest in Partnership Capital shall be interpreted consistently therewith.

“Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Section B1.3(c)(i), Section B1.3(c)(ii), Section B1.3(c)(iii), Section B1.3(c)(iv), Section B1.3(c)(v), Section B1.3(c)(vi), Section B1.3(c)(vii) or Section B1.3(c)(ix).

“Simulated Basis” means, with respect to each oil and gas property, the Carrying Value of such property.  For purposes of such computation, the Simulated Basis of each oil and gas property shall be allocated to each Partner in accordance with such Partner’s Percentage Interest in Partnership Capital as of the time such oil and gas property is acquired by the Partnership and shall be reallocated among the Partners in accordance with the Partners’ Percentage Interest in Partnership Capital as determined immediately following the occurrence of an event giving rise to any adjustment to the Carrying Values of the Partnership’s oil and gas properties pursuant to the terms of this Agreement.

“Simulated Depletion” means a depletion allowance computed for each oil and gas property pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2), taking into account Section B1.2(b)(ii) of this Agreement, provided, however, that such Simulated Depletion shall not exceed such oil and gas property’s Simulated Basis prior to the adjustment that is caused by such depletion allowance.

“Simulated Gain or Loss” means the simulated gain or loss computed with respect to a sale or other disposition of an oil and gas property pursuant to Treasury Regulation section 1.704-1(b)(2)(iv)(k)(2) as more specifically set forth in Section B1.2(b)(ii) of this Agreement.

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“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section B1.2(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section B1.2(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section B1.2(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section B1.2(d)).

B1.2           Capital Accounts.  The Partnership shall maintain for each Partner a separate Capital Account with respect to the Partnership Interest owned by the Partner in accordance with the rules of Treasury Regulation section 1.704-1(b)(2)(iv) and in accordance with the following provisions:

(a)           Each Partner’s Capital Account shall be increased by (i) the amount of all cash and the Agreed Value of any property contributed to the Partnership by such Partner pursuant to this Agreement, (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section B1.2(b) and allocated with respect to such Partner pursuant to Section B1.3, and (iii) the amount of any Partnership liabilities assumed by such Partner or that are secured by any Partnership property distributed to such Partner, and decreased by (x) the amount of cash or fair market value of property actually or deemed distributed to such Partner pursuant to this Agreement, (y) all items of Partnership deduction and loss (including Simulated Loss and Simulated Depletion) computed in accordance with Section B1.2(b) and allocated to such Partner pursuant to Section B1.3 and (z) the amount of any liabilities of such Partner assumed by the Partnership or that are secured by any property contributed by such Partner to the Partnership.

(b)           For purposes of computing the amount of any item of income, gain, loss or deduction which is to be allocated pursuant to this Exhibit B and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes, provided, however, that:

(i)           All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section B1.3.

(ii)           Except as otherwise provided in Treasury Regulation section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under section 754 of the Code which may be made by the Partnership and, as to those items described in section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes.  To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss, as the case may be.

(iii)           In lieu of the depreciation, amortization and other cost recovery deductions taken into account in computing such items, there shall be taken into account Depreciation and Simulated Depletion.

(iv)           For purposes of determining income, gain, loss, and deduction, or any other item allocable to any period, such items will be determined on a daily, monthly or other basis, as reasonably determined by the General Partner using any permissible method under Code section 706 and the related Treasury Regulation.

(c)           A transferee of a Partnership Interest pursuant to a Transfer shall succeed to the pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.  Except as otherwise provided herein, all items of income, gain, expense, loss, deduction, and credit allocable to any Partnership Interest that may have been transferred during any calendar year shall, if permitted by law, be allocated between the

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transferor and the transferee based on the portion of the calendar year during which each was recognized as owning that Partnership Interest, based upon the interim closing of the books method or such other method as agreed between the transferor and the transferee; provided, however, that this allocation must be made in accordance with a method permissible under section 706 of the Code and the Treasury Regulation thereunder.

(d)           In accordance with Treasury Regulation section 1.704-1(b)(2)(iv)(f), (i) on an issuance of additional Partnership Interests for cash or Contributed Property (including an Interim Closing Date), (ii) immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), (iii) upon the issuance of Partnership Interests as consideration for the provision of services or (iv) upon the occurrence of any other event provided in such Treasury Regulation, the Capital Accounts of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance or adjustment shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance or adjustment and had been allocated to the Partners at such time pursuant to Section B1.3 in the same manner as any item of gain or loss actually recognized during such period would have been allocated, provided, however, that such adjustments shall be made only if the General Partner reasonably determines that such adjustments are necessary or appropriate to reflect the relative economic interests of the Partners in the Partnership.  In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash and cash equivalents) immediately prior to the event triggering such adjustment shall be determined by the General Partner using such method of valuation as it may adopt.  The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

B1.3           Allocations for Capital Account Purposes.  For purposes of maintaining the Capital Accounts, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section B1.2(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

(a)           General.  Except as otherwise provided in this Agreement, all items of income, gain, loss and deduction (including items of gross income and income and gain exempt from tax) shall be allocated among the Partners in a manner such that, after giving effect to the special allocations set forth in Section B1.3(c), the Capital Account of each Partner, immediately after making such allocation, is, as nearly as possible, equal (proportionately) to (i) the distributions that would be made to such Partner pursuant to Section 5.2 if the Partnership were dissolved, its affairs wound up and its assets sold for cash equal to their Carrying Value, all Partnership liabilities were satisfied (limited with respect to each Nonrecourse Liability to the Carrying Value of the assets securing such liability), and the net assets of the Partnership were distributed in accordance with Section 5.2 to the Partners immediately after making such allocation, minus (ii) such Partner’s share of Partnership Minimum Gain and Partner Nonrecourse Debt Minimum Gain, computed immediately prior to the hypothetical sale of assets.  The Partners acknowledge that allocations like those described in Proposed Treasury Regulation Section 1.704-1(b)(4)(vii)(c) (“Forfeiture Allocations”) may result from the allocations of income, gain, loss and deduction provided for in this Agreement.  For the avoidance of doubt, the Partnership is entitled to make Forfeiture Allocations and, once required by applicable final or temporary guidance, allocations of income, gain, loss and deduction will be made in accordance with Proposed Treasury Regulation Section 1.704-1(b)(4)(xii)(c) or any successor provision or guidance.

(b)           Reserved.

(c)           Special Allocations.  Notwithstanding any other provision of this Section B1.3, the following special allocations shall be made for such taxable period in the following order and priority:

(i)           Partnership Minimum Gain Chargeback.  Notwithstanding the other provisions of this Section B1.3, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such taxable period (and, if necessary, subsequent taxable periods) in the manner and amounts provided in Treasury Regulation sections 1.704-2(f)(6) and (g)(2) and section 1.704-2(j)(2)(i), or any successor provisions.  This Section B1.3(c)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation section 1.704-2(f) and shall be interpreted consistently therewith.

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(ii)           Chargeback of Minimum Gain Attributable to Partner Nonrecourse Debt.  Notwithstanding the other provisions of this Section B1.3 (other than Section B1.3(c)(i)), except as provided in Treasury Regulation section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such taxable period (and, if necessary, subsequent taxable periods) in the manner and amounts provided in Treasury Regulation sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions.  This Section B1.3(c)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii)           Qualified Income Offset.  In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation section 1.704-1(b)(2)(ii)(d)(4) through (6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulation promulgated under section 704(b) of the Code, the deficit balance, if any, in each Partner’s Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, however, that, an allocation pursuant to this Section B1.3(c)(iii) shall be made only if and to the extent that such Partner would have a deficit in such Partner’s Adjusted Capital Account after all other allocations provided in this Exhibit B have been tentatively made as if this Section B1.3(c)(iii) were not a part of this Agreement.  This Section B1.3(c)(iii) is intended to be a “qualified income offset” as that term is used in Treasury Regulation section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith.

(iv)           Stop Loss.  No amount of loss or deduction shall be allocated pursuant to Section B1.3(a) to the extent that such allocation would cause any Partner to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account).  All loss and deductions in excess of the limitation set forth in the preceding sentence shall be allocated among such other Partners, who have positive Adjusted Capital Account balances, in proportion to their respective Partnership Interests until each Partner’s Adjusted Capital Account balance is reduced to zero.

(v)           Gross Income Allocations.  In the event any Partner has a deficit balance in its Adjusted Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is obligated to restore pursuant to any provision of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, however, that, an allocation pursuant to this Section B1.3(c)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account after all other allocations provided in this Section B1.3 have been tentatively made as if this Section B1.3(c)(v) and Section B1.3(c)(iii) were not in the Agreement.

(vi)           Nonrecourse Deductions.  Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests.

(vii)           Partner Nonrecourse Deductions.  Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to such Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation section 1.704-2(i).  If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii)           Nonrecourse Liabilities.  For purposes of Treasury Regulation section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

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(ix)           Code Section 754 Adjustments.  To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such section of the Treasury Regulation.

(x)           Simulated Depletion and Simulated Loss.  Simulated Depletion and Simulated Loss with respect to any oil and gas property shall be allocated among the Partners in proportion to their shares of the Simulated Basis in such property.  Each Partner’s share of the Simulated Basis in each of the Partnership’s oil and gas properties shall be determined in accordance with such Partner’s Percentage Interest in Partnership Capital.

(xi)           Simulated Gain.  Simulated gain with respect to any oil and gas property shall be allocated among the Partners as provided in Section B1.3(a).

B1.4           Allocations for Tax Purposes.

(a)           Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section B1.3.

(b)           Notwithstanding any provisions to the contrary, allocations of depletion with respect to each oil and gas property and gain and losses therefrom shall be governed by the following:

(i)           For purposes of such computations, the federal income tax basis of each oil and gas property shall be allocated to each Partner in accordance with such Partner’s Percentage Interest in Partnership Capital as of the time such oil and gas property is acquired by the Partnership, and shall be reallocated among the Partners in accordance with the Partners’ Percentage Interest in Partnership Capital as determined immediately following the occurrence of an event giving rise to an adjustment to the Carrying Values of the Partnership’s oil and gas properties pursuant to the terms of this Agreement (or at the time of any material additions to the federal income tax basis of such oil and gas property).  Such allocations are intended to be applied in accordance with the “partners’ interests in partnership capital” under section 613A(c)(7)(D) of the Code and Treasury Regulation sections 1.613A-3(e)(2)(ii) and 1.704-1(b)(4)(v); provided, however, that the Partners understand and agree that the General Partner may authorize special allocations of tax basis, income, gain, deduction or loss, as computed for federal income tax purposes, in order to eliminate differences between Simulated Basis and adjusted federal income tax basis with respect to any oil and gas properties, in such manner as determined consistent with the principles of section 704(c) of the Code and Section B1.4(c) hereof.

(ii)           For purposes of the separate computation of gain or loss by each Partner on the taxable sale or other disposition of an oil and gas property, the amount realized from such sale or disposition shall be allocated (i) first, to the Partners in an amount equal to the Simulated Basis in such oil and gas property and in the same proportion as their shares thereof were allocated, and (ii) second, any remaining amount realized shall be allocated consistent with the allocation of Simulated Gains; provided, however, that the Partners understand and agree that the General Partner may authorize special allocations of tax basis and amount realized, as computed for federal income tax purposes, in order to eliminate differences between Simulated Basis and adjusted federal income tax basis with respect to any oil and gas properties, in such manner as determined consistent with the principles of section 704(c) of the Code and Section B1.4(c) hereof.

(iii)           Each Partner shall separately keep records of its share of the adjusted tax basis in each oil and gas property, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property and use such adjusted tax basis in the computation of its cost depletion or in the computation of its gain or loss on the disposition of such property by the Partnership. Upon the request of the Partnership, each Partner shall advise the Partnership of its adjusted tax basis in each oil and gas property and any depletion computed with respect thereto, both as computed in accordance

6

with the provisions of this subsection.  The Partnership may rely on such information and, if it is not provided by the Partner, may make such reasonable assumptions as it shall determine with respect thereto.

(c)           Notwithstanding any provisions contained herein to the contrary, solely for federal (and applicable state and local) income tax purposes, items of income, gain, depreciation, depletion, amortization, gain, loss or amount realized with respect to property for which a Book-Tax Disparity exists shall be allocated so as to take into account the variation between the Partnership’s tax basis in such property and its Carrying Value consistent with Treasury Regulation sections 1.704-1(b)(4)(i) and 1.704-3(d).

(d)           For the proper administration of the Partnership, the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income or deductions); and (iii) amend the provisions of this Agreement as appropriate to reflect the proposal or promulgation of Treasury Regulation under section 704(b) or section 704(c) of the Code.  The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section B1.4(d) only if such conventions, allocations or amendments are consistent with the principles of section 704 of the Code and would not have a material adverse effect on any Partner.

(e)           All recapture of income tax deductions resulting from the taxable sale or other disposition of Partnership property shall, to the maximum extent possible, be allocated to the Partner to whom the deduction that gave rise to such recapture was allocated hereunder to the extent that such Partner is allocated any gain from the disposition of such property.

(f)           All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under section 754 of the Code; provided, however, that in the event such an election is made under section 754 of the Code, such allocations, once made, shall be adjusted (in any manner determined by the General Partner as necessary or appropriate to take into account those adjustments permitted or required by sections 734 and 743 of the Code.

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Exhibit B to Prospectus

Form of Subscription Agreement

To: Energy 11, L.P. 120 W 3rd Street, Suite 220 Fort Worth, Texas 76102

Gentlemen:

By executing or having executed on my (our) behalf this Subscription Agreement and submitting payment, I (we) hereby subscribe for the number of common units of limited partnership interest (the “Units”) set forth on the signature page hereof in Energy 11, L.P. (the “Partnership”) at the purchase price set forth on the signature page hereof.  

INVESTOR SUITABILITY

_____ Initial to indicate you have carefully reviewed the following:

By executing or having executed on my (our) behalf this Subscription Agreement and submitting payment, I (we) further:

(a)           acknowledge receipt of a copy of the prospectus of Energy 11, L.P., of which this Subscription Agreement is a part, and understand that the shares being acquired will be governed by the terms of such prospectus and any amendments and supplements thereto;

(b)           represent that I am (we are) of majority age;

(c)           represent that I (we) have adequate means of providing for my (our) current needs and personal contingencies; and have no need for liquidity from this investment;

(d)           represent that I (we) have either: (i) a net worth (excluding home, home furnishings and automobiles) of at least $45,000 and estimate that (without regard to investment in the Partnership) I (we) will have gross income during the current year of $45,000, or (ii) a net worth (excluding home, home furnishings and automobiles) of at least $150,000;

(e)           represent (if purchasing in a fiduciary or other representative capacity) that I (we) have due authority to execute the Subscription Agreement and to thereby legally bind the trust or other entity of which I am (we are) trustee(s), legal representative(s) or authorized agent(s); and agree to fully indemnify and hold the Partnership, its officers and directors, its affiliates and employees, harmless from any and all claims, actions and causes of action whatsoever which may result by a breach or an alleged breach of the representations contained in this paragraph;

(f)            certify, under penalties of perjury, (i) that the taxpayer identification number shown on the signature page of this Subscription Agreement is true, correct and complete (or I am (we are) waiting for a number to be issued to me (us)), and (ii) that I am (we are) not subject to backup withholding either because (a) I am (we are) exempt from backup withholding, or (b) I (we) have not been notified by the Internal Revenue Service that I am (we are) subject to backup withholding as a result of a failure to report all interest or distributions, or (c) the Internal Revenue Service has notified me (us) that I am (we are) no longer subject to backup withholding; and

(g)           The Partnership shall have the right to accept or reject this subscription in whole or in part in its sole and absolute discretion. The Partnership will either accept or reject this subscription within four business days from the receipt of the subscription by the Dealer Manager or Selected Dealer.

To the extent permitted by applicable law, the Partnership intends to assert the foregoing representations as a defense to any claim based on factual assertions contrary to those set forth above.

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(h)           PRE-DISPUTE ARBITRATION CLAUSE. THIS AGREEMENT CONTAINS A PRE-DISPUTE ARBITRATION CLAUSE. BY SIGNING THIS SUBSCRIPTION AGREEMENT THE INVESTOR(S)/CUSTOMER(S) AND DAVID LERNER ASSOCIATES, INC. (REFERRED TO IN THIS SECTION “(h)” AS THE “PARTIES”) AGREE AS FOLLOWS:

1.   ALL PARTIES TO THIS AGREEMENT ARE GIVING UP THE RIGHT TO SUE EACH OTHER IN COURT, INCLUDING THE RIGHT TO A TRIAL BY JURY, EXCEPT AS PROVIDED BY THE RULES OF THE ARBITRATION FORUM IN WHICH A CLAIM IS FILED.

2.   ARBITRATION AWARDS ARE GENERALLY FINAL AND BINDING; A PARTY’S ABILITY TO HAVE A COURT REVERSE OR MODIFY AN ARBITRATION AWARD IS VERY LIMITED.

3.   THE ABILITY OF THE PARTIES TO OBTAIN DOCUMENTS, WITNESS STATEMENTS AND OTHER DISCOVERY IS GENERALLY MORE LIMITED IN ARBITRATION THAN IN COURT PROCEEDINGS.

4.   THE ARBITRATORS DO NOT HAVE TO EXPLAIN THE REASON(S) FOR THEIR AWARD.

5.   THE PANEL OF ARBITRATORS WILL TYPICALLY INCLUDE A MINORITY OF ARBITRATORS WHO WERE OR ARE AFFILIATED WITH THE SECURITIES INDUSTRY.

6.   THE RULES OF SOME ARBITRATION FORUMS MAY IMPOSE TIME LIMITS FOR BRINGING A CLAIM IN ARBITRATION. IN SOME CASES, A CLAIM THAT IS INELIGIBLE FOR ARBITRATION MAY BE BROUGHT IN COURT.

7.   THE RULES OF THE ARBITRATION FORUM IN WHICH THE CLAIM IS FILED, AND ANY AMENDMENTS THERETO, SHALL BE INCORPORATED INTO THIS AGREEMENT.

8.   NO PERSON SHALL BRING A PUTATIVE OR CERTIFIED CLASS ACTION TO ARBITRATION, NOR SEEK TO ENFORCE ANY PREDISPUTE ARBITRATION AGREEMENT AGAINST ANY PERSON WHO HAS INITIATED IN COURT A PUTATIVE CLASS ACTON; OR WHO IS A MEMBER OF A PUTATIVE CLASS ACTION WHO HAS NOT OPTED OUT OF THE CLASS WITH RESPECT TO ANY CLAIMS ENCOMPASSED BY THE PUTATIVE CLASS ACTION UNTIL: (i) THE CLASS CERTIFICATION IS DENIED; OR (ii) THE CLASS IS DECERTIFIED; OR (iii) THE CUSTOMER IS EXCLUDED FROM THE CLASS BY THE COURT. SUCH FORBEARANCE TO ENFORCE AN AGREEMENT TO ARBITRATE SHALL NOT CONSTITUTE A WAIVER OF ANY RIGHTS UNDER THIS AGREEMENT EXCEPT TO THE EXTENT STATED HEREIN.

THE CUSTOMER AGREES TO SETTLE BY ARBITRATION ANY CONTROVERSY BETWEEN HIM/HER AND THE BROKER CONCERNING THIS AGREEMENT, HIS/HER ACCOUNT(S), OR ACCOUNT TRANSACTIONS, OR IN ANY WAY ARISING FROM HIS/HER RELATIONSHIP WITH BROKER WHETHER ENTERED INTO PRIOR, ON, OR SUBSEQUENT TO THIS DATE. SUCH ARBITRATION WILL BE CONDUCTED BEFORE AND ACCORDING TO THE ARBITRATION RULES OF THE FINANCIAL INDUSTRY REGULATORY AUTHORITY (FINRA) OR ANY OTHER SELF-REGULATORY ORGANIZATION OF WHICH BROKER IS A MEMBER. EITHER THE BROKER OR THE CUSTOMER MAY INITIATE ARBITRATION BY MAILING A WRITTEN NOTICE. IF THE CUSTOMER DOES NOT DESIGNATE THE ARBITRATION FORUM IN HIS/HER NOTICE, OR RESPOND IN WRITING WITHIN 5 DAYS AFTER RECEIPT OF BROKER’S NOTICE, CUSTOMER AUTHORIZES BROKER TO DESIGNATE THE ARBITRATION FORUM ON CUSTOMER’S BEHALF. JUDGMENT ON ANY ARBITRATION AWARD MAY BE ENTERED IN ANY COURT HAVING JURISDICTION, AND CUSTOMER SUBMITS HIMSELF/HERSELF AND PERSONAL REPRESENTATIVES TO THE JURISDICTION OF SUCH COURT.

NOTHING CONTAINED IN THIS AGREEMENT SHALL BE CONSTRUED AS REQUIRING ARBITRATION FOR ALLEGATIONS INVOLVING BREACH OF CONTRACT, NEGLIGENCE, VIOLATION OF STATE OR FEDERAL SECURITIES LAWS, BREACH OF FIDUCIARY DUTY OR OTHER MISCONDUCT BY THE GENERAL PARTNER OF THE PARTNERSHIP.

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New Jersey Investors

_____ If you are resident of New Jersey, initial to indicate you have carefully reviewed the following:

Investments in us by New Jersey investors must meet the following requirements:

New Jersey investors must have either (a) a minimum liquid net worth of at least $100,000 and a minimum annual gross income of not less than $85,000, or (b) a minimum liquid net worth of $350,000. For these purposes, "liquid net worth" is defined as that portion of net worth (total assets exclusive of home, home furnishings, and automobiles, minus total liabilities) that consists of cash, cash equivalents and readily marketable securities. In addition, a New Jersey investor's investment in us, our affiliates, and other non-publicly traded direct investment programs (including real estate investment trusts, business development companies, oil and gas programs, equipment leasing programs and commodity pools, but excluding unregistered, federally and state exempt private offerings) may not exceed ten percent (10%) of his or her liquid net worth.

Important Information for Subscriber(s)

The subscriber is instructed to review the disclosures in the prospectus concerning certain conflicts of interest the partnership faces, certain risks involved in this investment and the management of the general partner.  These disclosures are found in the sections entitled “Risk Factors,” “Conflicts of Interest,” “Management” and “Material Federal Income Tax Consequences” of the prospectus.

Execution of a Subscription Agreement shall serve as an agreement by the subscriber to be bound by each and every term of the First Amended and Restated Agreement of Limited Partnership of the Partnership attached as Exhibit A to the prospectus, if such Subscription Agreement is accepted by the General Partner.

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Energy 11, L.P.—Signature Page of the Subscription Agreement

Acct. #: Date: Doc #       1127     

IC Name/Code:    Track #: 

Social Security or Tax ID Number(s):_______________________________________________

1.	Name(s) in which Units are to be registered:
2.	Manner in which title is to be held (Please check one).
	o Individual  o Joint Tenants WROS  o Corporation  o Community Property  o Tenants in Common  o Partnership  o Trust
	o As Custodian for
	o For Estate of
	o Other
3.	Address for correspondence
4.	Are you a non-resident alien individual (other than a non-resident alien who has elected to be taxed as a resident), a foreign corporation, a foreign partnership, a foreign trust, a foreign estate, or otherwise not qualified as a United States person? If so, transaction will not be executed without a completed W-8BEN Form.  o  Yes  o  No
5.	Amount of Investment $for Units (Investment must be for a minimum of $5,000 in Units). Prior to the initial closing, please make check payable to: “Branch Banking and Trust Company, as escrow agent for Energy 11”.  Following the initial closing and after we break escrow, please make your checks payable to “David Lerner Associates, Inc.”
6.	o Liquidate funds from money market  o Check Enclosed
7.	I (WE) UNDERSTAND THAT THIS AGREEMENT CONTAINS A PRE-DISPUTE ARBITRATION CLAUSE AT PARAGRAPH (h).
8.	Signature(s) of Investor(s) (Please sign in same manner in which shares are to be registered. Read Subscription Agreement, an important legal document, before signing.)
	By executing this Subscription Agreement, the Investor is not waiving any rights under the Securities Act of 1933.

X
Signature	Date
X
Signature	Date
X
Signature	Date

9.	Broker/Dealer Information:
	X
	Registered Representative’s Name and Number	Second Registered Representative’s Name and Number
	X
	Broker/Dealer Firm	Registered Representative’s Office Address
	X
	City/State/Zip	Telephone Number
10.	To substantiate compliance with Rule 2810 of the FINRA Conduct Rules, the undersigned Registered Representative hereby certifies: I have reasonable grounds to believe, based on information obtained from the investor(s) concerning investment objectives, other investments, financial situation and needs and any other information known by me, that investment in the Partnership is suitable for such investor(s) in light of financial position, net worth and other suitability characteristics.
	Registered Representative	Date
	General Securities Principal	Date

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ENERGY 11, L.P.

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13.  Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than selling commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby assuming the Maximum Offering is reached. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee, the amounts set forth below are estimates and assume that all of the Common Units offered in the offering will be sold.

SEC registration fee	$	257,600
FINRA filing fee		225,500
Printing expense		3,250,000
Accounting fees and expenses		850,000
Legal fees and expenses		3,250,000
Blue sky fees and expenses		200,000
Marketing fee*		20,000,000
Miscellaneous		77,200
Total	$	28,110,300

*  The marketing fee is the only item in this list that that constitutes FINRA underwriting compensation and that is payable to a FINRA member.

Item 14.  Indemnification of Officers and Members of the Board of Directors.

The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify our general partner and officers and directors of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Subject to any terms, conditions or restrictions set forth in the Partnership Agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15.  Recent Sales of Unregistered Securities

On June 27, 2013, in connection with the formation of Energy 11, L.P. (the “Partnership”), the Partnership issued to (i) its general partner a 1% general partner interest in the Partnership for $10 and (ii) DMOG, LLC the 99% limited partner interest in the Partnership for $990. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

Item 16.  Exhibits and Financial Statement Schedules.

(a)   The following exhibits are filed as part of this Registration Statement:

Exhibit Number	Description
1.1	Exclusive Dealer Manager Agreement with David Lerner Associates, Inc. (incorporated by reference from Exhibit 1.1 to Amendment No. 7 to this Registration Statement filed on December 31, 2014).
2.1	Interest Purchase Agreement dated September 15, 2015 among Energy 11 Operating Company, LLC, Kaiser-Whiting, LLC, and the owners of all the limited liability company interests in Kaiser-Whiting, LLC (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on September 18, 2015).
2.2	First Amendment to Interest Purchase Agreement dated December 18, 2015, by and among Energy 11 Operating Company, LLC, a Delaware limited liability company, Kaiser-Whiting, LLC, an Oklahoma limited liability company and Don P. Millican as attorney-in-fact on behalf of all Sellers (incorporated by reference from Exhibit 2.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on December 21, 2015).

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3.1	Certificate of limited partnership of Energy 11, L.P. (incorporated by reference from Exhibit 3.1 to Amendment No. 4 to this Registration Statement filed on November 21, 2014).
3.2	First Amended and Restated Limited Partnership Agreement of Energy 11, L.P. dated as of August 19, 2015 (Exhibit A to the Prospectus included as part of this Registration Statement).
5.1	Form of Opinion of Haynes and Boone, LLP as to legality of securities being issued (Previously filed in Amendment No. 8 to this Registration Statement on January 20, 2015.)
8.1	Form of Opinion of Haynes and Boone, LLP as to tax matters (Previously filed in Amendment No. 8 to this Registration Statement on January 20, 2015.)
10.1	Escrow Agreement ( incorporated by reference from Exhibit 10.1 to Amendment No. 6 to this Registration Statement filed on December 12, 2014).
10.2	Form of Management Services Agreement by and among E11 Management, LLC, E11 Incentive Holdings, LLC, Energy 11, L.P. and Energy 11 Operating Company, LLC, dated August 19, 2015 (incorporated by reference from Exhibit 10.2 to Amendment No. 4 to this Registration Statement filed on November 21, 2014).
10.3	Form of Subscription Agreement (Exhibit B to the Prospectus included as part of this Registration Statement)
10.4	Consulting Agreement with Clifford Merritt (incorporated by reference from Exhibit 10.4 to Amendment No. 4 to this Registration Statement filed on November 21, 2014).
10.5	Secured Promissory Note dated December 18, 2015 executed by Energy 11 Operating Company LLC in favor of Kaiser-Francis Management Company, L.L.C. (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on December 21, 2015).
10.6	Letter Agreement between Energy 11 GP, LLC and Clifford Merritt (incorporated by reference from Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on December 21, 2015).
10.7	Termination of Management Services Agreement by and among E11 Management, LLC, E11 Incentive Holdings, LLC, Energy 11, L.P. and Energy 11 Operating Company, LLC dated August 19, 2015 (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on April 7, 2016)
16.1	Letter Agreement from Ernst & Young LLP to the Securities and Exchange Commission dated March 18, 2015 (incorporated by reference from Exhibit 16.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on March 19, 2015).
21.1	Subsidiaries of the Partnership (incorporated by reference from Exhibit 21.1 to the Partnership’s Annual Report on Form 10-K filed on March 28, 2016)
23.1	Consent of Grant Thornton LLP *
23.2	Consent of HoganTaylor LLP *
23.3	Consent of Ernst & Young LLP*
23.4	Consent of Pinnacle Energy Services, LLC*
23.5	Consent of Haynes and Boone, LLP (included in their opinion filed as Exhibit 5.1)
24.1	Power of Attorney (see page II-4 to the original filing of this Registration Statement on Form S-1)
99.1	Report of Pinnacle Energy Services, LLC, Independent Petroleum Consultants. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Annual Report on Form 10-K filed on March 28, 2016.)
101.1	Interactive Data Files *

_________________________

* Filed herewith.

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Item 17.  Undertakings.

(a)           The undersigned registrant hereby undertakes:

(1)           To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i)           To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

(ii)           To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

Provided, however, that paragraphs (1)(i), (1)(ii) and (1)(iii) do not apply if the information required to be included in a post-effective amendment by those paragraphs is contained in reports filed with or furnished to the Commission by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement, or is contained in a form of prospectus filed pursuant to Rule 424(b) that is part of the registration statement.

(2)           That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3)           To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4)           That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5)           That, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities: The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this Registration Statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i)            Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii)           Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii)          The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

II-3

(iv)          Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b)           The undersigned registrant hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

(c)           Insofar as indemnification for liability arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

(d)           That, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant's annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Post-Effective Amendment No. 4 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Richmond, State of Virginia on May 6, 2016.

ENERGY 11, L.P.,

By:  Energy 11 GP, LLC, its general partner

By:          /s/ David S. McKenney                                         

Name:  David S. McKenney

Title:    Manager

Pursuant to the requirements of the Securities Act of 1933, as amended, this Post-Effective Amendment No. 4 to the Registrant’s Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title with the general partner	Date
*	Manager, Chief Executive Officer (principal operating officer)	May 6, 2016
Glade M. Knight
/s/ David S. McKenney	Manager, Chief Financial Officer (principal financial and accounting officer)	May 6, 2016
David S. McKenney
*	Manager, Co-Chief Operating Officer	May 6, 2016
Anthony F. Keating III
*	Manager, Co-Chief Operating Officer	May 6, 2016
Michael J. Mallick

* By:    /s/ David S. McKenney                             

   Name:  David S. McKenney

   As Attorney in Fact

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Exhibit Number	Description
1.1	Exclusive Dealer Manager Agreement with David Lerner Associates, Inc. (incorporated by reference from Exhibit 1.1 to Amendment No. 7 to this Registration Statement filed on December 31, 2014).
2.1	Interest Purchase Agreement dated September 15, 2015 among Energy 11 Operating Company, LLC, Kaiser-Whiting, LLC, and the owners of all the limited liability company interests in Kaiser-Whiting, LLC (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on September 18, 2015).
2.2	First Amendment to Interest Purchase Agreement dated December 18, 2015, by and among Energy 11 Operating Company, LLC, a Delaware limited liability company, Kaiser-Whiting, LLC, an Oklahoma limited liability company and Don P. Millican as attorney-in-fact on behalf of all Sellers (incorporated by reference from Exhibit 2.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on December 21, 2015).
3.1	Certificate of limited partnership of Energy 11, L.P. (incorporated by reference from Exhibit 3.1 to Amendment No. 4 to this Registration Statement filed on November 21, 2014).
3.2	First Amended and Restated Limited Partnership Agreement of Energy 11, L.P. dated as of August 19, 2015 (Exhibit A to the Prospectus included as part of this Registration Statement).
5.1	Form of Opinion of Haynes and Boone, LLP as to legality of securities being issued (Previously filed in Amendment No. 8 to this Registration Statement on January 20, 2015.)
8.1	Form of Opinion of Haynes and Boone, LLP as to tax matters (Previously filed in Amendment No. 8 to this Registration Statement on January 20, 2015.)
10.1	Escrow Agreement ( incorporated by reference from Exhibit 10.1 to Amendment No. 6 to this Registration Statement filed on December 12, 2014).
10.2	Form of Management Services Agreement by and among E11 Management, LLC, E11 Incentive Holdings, LLC, Energy 11, L.P. and Energy 11 Operating Company, LLC, dated August 19, 2015 (incorporated by reference from Exhibit 10.2 to Amendment No. 4 to this Registration Statement filed on November 21, 2014).
10.3	Form of Subscription Agreement (Exhibit B to the Prospectus included as part of this Registration Statement)
10.4	Consulting Agreement with Clifford Merritt (incorporated by reference from Exhibit 10.4 to Amendment No. 4 to this Registration Statement filed on November 21, 2014).
10.5	Secured Promissory Note dated December 18, 2015 executed by Energy 11 Operating Company LLC in favor of Kaiser-Francis Management Company, L.L.C. (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on December 21, 2015).
10.6	Letter Agreement between Energy 11 GP, LLC and Clifford Merritt (incorporated by reference from Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed with the SEC on December 21, 2015).
10.7	Termination of Management Services Agreement by and among E11 Management, LLC, E11 Incentive Holdings, LLC, Energy 11, L.P. and Energy 11 Operating Company, LLC dated August 19, 2015 (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on April 7, 2016)
16.1	Letter Agreement from Ernst & Young LLP to the Securities and Exchange Commission dated March 18, 2015 (incorporated by reference from Exhibit 16.1 to the Partnership’s Current Report on Form 8-K filed with the SEC on March 19, 2015).
21.1	Subsidiaries of the Partnership (incorporated by reference from Exhibit 21.1 to the Partnership’s Annual Report on Form 10-K filed on March 28, 2016)
23.1	Consent of Grant Thornton LLP *
23.2	Consent of HoganTaylor LLP *
23.3	Consent of Ernst & Young LLP*
23.4	Consent of Pinnacle Energy Services, LLC*
23.5	Consent of Haynes and Boone, LLP (included in their opinion filed as Exhibit 5.1)
24.1	Power of Attorney (see page II-4 to the original filing of this Registration Statement on Form S-1)
99.1	Report of Pinnacle Energy Services, LLC, Independent Petroleum Consultants. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Annual Report on Form 10-K filed on March 28, 2016.)
101.1	Interactive Data Files *

_________________________

* Filed herewith.

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