Mid-Con Energy Partners, LP (Form: S-1, Received: 08/12/2011 15:05:36)

Proposed Maximum

Amount of

Title of Each Class of

Aggregate

Registration

Securities to be Registered

Offering Price(1)(2)

Common units representing limited partner interests

$140,000,000

As filed with the Securities and Exchange Commission on August 12, 2011

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Mid-Con Energy Partners, LP

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		45-2842469 (I.R.S. Employer Identification Number)

2431 E. 61st Street, Suite 850

Tulsa, Oklahoma 74136

(918) 743-7575

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

Charles R. Olmstead

Mid-Con Energy GP, LLC

2431 E. 61st Street, Suite 850

Tulsa, Oklahoma 74136

(918) 743-7575

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

Copies to:


Richard M. Carson GableGotwals 1100 ONEOK Plaza 100 W. Fifth Street Tulsa, Oklahoma 74103 (918) 595-4800		William J. Cooper Andrews Kurth LLP 1350 I Street, NW Suite 1100 Washington, DC 20005 (202) 662-2700		J. Michael Chambers Brett E. Braden Latham & Watkins LLP 717 Texas Avenue, Suite 1600 Houston, Texas 77002 (713) 546-5400

Approximate date of commencement of proposed sale to the public: As soon as practicable after this 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. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please 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 þ	Smaller reporting company o

(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE


(1)	Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

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 Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2011 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk Factors” and the historical and unaudited pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes that the underwriters do not exercise their option to purchase up to an additional common units, unless otherwise indicated. As used in this prospectus, unless we indicate otherwise:


	•	“Contributing Parties” collectively refers to the Founders, Yorktown, our executive officers, employees and other individuals and entities who hold membership interests in our predecessor;

	•	“Founders” collectively refers to Charles R. Olmstead, S. Craig George and Jeffrey R. Olmstead;

	•	“our general partner” refers to Mid-Con Energy GP, LLC;

	•	“Mid-Con Affiliates” collectively refers to Mid-Con Energy III, LLC and Mid-Con Energy IV, LLC, which are affiliates of our general partner;

	•	“Mid-Con Energy Partners,” the “partnership,” “we,” “our,” “us” or like terms when used in a historical context refer to our predecessor, which will be merged with and into Mid-Con Energy Properties, LLC, our wholly owned subsidiary, in connection with this offering. When used in the present tense or prospectively, those terms refer to Mid-Con Energy Partners, LP, a Delaware limited partnership, and its subsidiaries;

	•	“Mid-Con Energy Operating” refers to Mid-Con Energy Operating, Inc., an affiliate of our general partner;

	•	“Mid-Con Energy Properties” refers to Mid-Con Energy Properties, LLC, our wholly owned subsidiary;

	•	“our predecessor” collectively refers to Mid-Con Energy Corporation, prior to June 30, 2009, and to Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, on a combined basis, thereafter, our respective predecessors for accounting purposes; and

	•	“Yorktown” collectively refers to Yorktown Partners LLC, Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., and/or Yorktown Energy Partners VIII, L.P.

We include a glossary of some of the oil and natural gas terms used in this prospectus in Appendix B. Our estimated proved reserve information as of December 31, 2010 and June 30, 2011 is based on a report prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. A summary of our estimated proved reserve information as of June 30, 2011 prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc. is included in this prospectus in Appendix C.

Mid-Con Energy Partners, LP

Overview

We are a Delaware limited partnership formed in July 2011 to own, operate, acquire, exploit and develop producing oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our management team has significant industry experience, especially with waterflood projects and, as a result, our operations focus primarily on enhancing the development of producing oil properties through waterflooding. Through the continued development of our existing properties and through future acquisitions, we will seek to increase our reserves and production in order to maintain and, over time, increase distributions

to our unitholders. Also, in order to enhance the stability of our cash flow for the benefit of our unitholders, we will seek to hedge a significant portion of our production volumes through various commodity derivative contracts.

As of June 30, 2011, our total estimated proved reserves were 7.9 MMBoe, of which approximately 98% were oil and 71% were proved developed, both on a Boe basis. As of June 30, 2011, we operated 98% of our properties and 92% were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended June 30, 2011 was approximately 1,248 Boe per day and our total estimated proved reserves had a reserve-to-production ratio of approximately 17 years. Our management team developed approximately two-thirds of our total reserves through new waterflood projects.

Our Properties

Our properties are located in the Mid-Continent region of the United States and primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates. Our core areas of operation are located in Southern Oklahoma, Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. As of June 30, 2011, approximately 91% of the properties associated with our estimated reserves, on a Boe basis, have been producing continuously since 1982 or earlier. Through the application of waterflooding, we believe these mature properties have attractive upside potential. Waterflooding, a form of secondary oil recovery, works by repressuring a reservoir through water injection and pushing or “sweeping” oil to producing wellbores. Based on the production estimates from our June 30, 2011 reserve report, the average estimated decline rate for our proved developed producing reserves is approximately 4% for 2011 and, on a compounded average decline basis, approximately 11% for the subsequent five years and approximately 10% thereafter. Additionally, based on production estimates from this reserve report, we believe that we have the ability to increase our average net production from our existing proved reserves to approximately 1,700 Boe per day during the next three years.

The following table summarizes information by core area regarding our estimated oil and natural gas reserves as of June 30, 2011 and our average net production for the month ended June 30, 2011.


												Average
												Net
	Estimated											Production
	Net Proved Reserves											for the Month Ended
	as of June 30, 2011											June 30, 2011				Average		Gross Active Wells
																Reserve-to-		Oil and
									% Proved			Boe/d		Boe/d		Production		Natural		Injection
	(MBoe)		% Operated			% Oil			Developed			Gross		Net		Ratio(1)		Gas Wells		Wells

Southern Oklahoma		4,783		100	%		99	%		58	%		1,892		700		19		65		42
Northeastern Oklahoma		2,043		100	%		99	%		91	%		593		340		16		154		59
Hugoton Basin		720		100	%		99	%		85	%		234		141		14		43		18
Other		361		77	%		60	%		100	%		231		67		15		13		4

Total		7,907		99	%		98	%		71	%		2,950		1,248		17		275		123


(1)	The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of June 30, 2011 by average net production for the month ended June 30, 2011.

The following chart summarizes our pro forma total average net Boe production volumes on a monthly basis, and illustrates the 100% increase in our production volumes over the twelve months ended June 30, 2011. We achieved this increase primarily through ongoing waterflood response from existing development activities and to a lesser extent, workovers and acquisitions.

Our Hedging Strategy

Our hedging strategy seeks to reduce the impact to our cash flow from commodity price volatility. We intend to enter into commodity derivative contracts at times and on terms designed to maintain, over the long term, a portfolio covering approximately 50% to 80% of our estimated oil production from proved reserves over a three-to-five year period at any given point in time. For the years ending December 31, 2011, 2012 and 2013, we have commodity derivative contracts covering approximately 43%, 44% and 24%, respectively, of our estimated oil production from proved reserves as of June 30, 2011. All of our commodity derivative contracts for 2012 and 2013 contain price floors of at least $100 per Bbl.

We intend to enter into additional commodity derivative contracts in connection with material increases in our estimated production and at times when we believe market conditions or other circumstances suggest that it is prudent to do so as opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes or the duration of our hedge contracts when circumstances suggest that it is prudent to do so.

By removing a significant portion of price volatility associated with our estimated future oil production, we have mitigated, but not eliminated, the potential effects of changing oil prices on our cash flow from operations for those periods. For a further description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”

Our Business Strategies

Our primary business objective is to generate stable cash flow, which will allow us to make quarterly cash distributions to our unitholders at the minimum quarterly distribution rate and, over time, to increase our quarterly cash distributions. To achieve our objective, we intend to execute the following business strategies:


	•	Continue exploitation of our existing properties to maximize production;

	•	Pursue acquisitions of long-lived, low-risk producing properties with upside potential;

	•	Capitalize on our relationship with the Mid-Con Affiliates for favorable acquisition opportunities;

	•	Maintain operational control and a focus on cost-effectiveness in all our operations;

	•	Reduce the impact of commodity price volatility on our cash flow through a disciplined commodity hedging strategy;

	•	Maintain a balanced capital structure to allow for financial flexibility to execute our business strategies; and

	•	Utilize compensation programs that align the interests of our management team with our unitholders.

For a more detailed description of our business strategies, please read “Business and Properties—Our Business Strategies.”

Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:


	•	An asset portfolio largely consisting of properties with existing waterflood projects that have relatively predictable production profiles, that provide growth potential through ongoing response to waterflooding and that have modest capital requirements;

	•	The ability to further exploit existing mature properties by utilizing our waterflooding expertise;

	•	Acquisition opportunities that are consistent with our criteria of predictable production profiles with upside potential that may arise as a result of our relationship with the Mid-Con Affiliates;

	•	Access to the collective expertise of Yorktown’s employees and their extensive network of industry relationships through our relationship with Yorktown;

	•	The ability to better manage our operating costs, capital expenditures and development schedule because of our high level of operational control;

	•	An enhanced ability to pursue acquisition opportunities arising from our competitive cost of capital and balanced capital structure; and


	•	The range and depth of our technical and operational expertise will allow us to expand both geographically and operationally to achieve our goals.

For a more detailed discussion of our competitive strengths, please read “Business and Properties—Our Competitive Strengths.”

Our Principal Business Relationships

Our Relationship with the Mid-Con Affiliates

In June 2011, management and Yorktown formed two limited liability companies, which we refer to collectively as the Mid-Con Affiliates, to acquire and develop oil and natural gas properties that are either undeveloped or that may require significant capital investment and development efforts before they meet our criteria for ownership. As these development projects mature, we expect to have the opportunity to acquire certain of these properties from the Mid-Con Affiliates. Through this relationship with the Mid-Con Affiliates, we plan to avoid much of the capital, engineering and geological risks associated with the early development of any of these properties we may acquire. However, the Mid-Con Affiliates may not be successful in indentifying or consummating acquisitions or in successfully developing the new properties they acquire. Further, the Mid-Con Affiliates are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Please read “Certain Relationships and Related Party Transactions—Review, Approval or Ratification of Transactions with Related Persons.”

Our Relationship with Yorktown

We have a valuable relationship with Yorktown, a private equity firm founded in 1991 and focused on investments in the energy sector. Since 2004, Yorktown has made several equity investments in our predecessor. Immediately following the consummation of this offering, Yorktown will own an approximate % limited partner interest in us, making it our largest unitholder, and will own a separate class of non-voting member interests in our general partner that will entitle it to receive % of the distributions we make to our general partner on the 2.0% general partner interest and our incentive distribution rights. Also, Peter A. Leidel, a principal of Yorktown, will serve on our board of directors.

Yorktown currently has more than $3.0 billion in assets under management and Yorktown’s employees have extensive investment experience in the oil and natural gas industry. Yorktown’s employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Yorktown owns interests. With their extensive investment experience in the oil and natural gas industry and their extensive network of industry relationships, we believe that Yorktown’s employees are well positioned to assist us in identifying and evaluating acquisition opportunities and in making strategic decisions. Yorktown is not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Investment funds managed by Yorktown manage numerous other portfolio companies that are engaged in the oil and natural gas industry and, as a result, Yorktown may present acquisition opportunities to other Yorktown portfolio companies that compete with us.

Risk Factors

An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under “Risk Factors.”

Risks Related to Our Business


	•	We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

	•	We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended June 30, 2011.

	•	Unless we replace the oil reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

	•	A decline in oil prices, or an increase in the differential between the NYMEX or other benchmark prices of oil and the wellhead price we receive for our production, will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

	•	We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders at the minimum quarterly distribution rate.

Risks Inherent in an Investment in Us


	•	Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

	•	The Mid-Con Affiliates, Yorktown and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets.

	•	Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage and operate our business. The management team of Mid-Con Energy Operating, which includes the individuals who will manage us, will also provide substantially similar services to the Mid-Con Affiliates, and thus will not be solely focused on our business.

	•	Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution.

	•	Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

	•	Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors, which could reduce the price at which our common units will trade.

	•	Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our units. This may result in lower distributions to holders of our common units in certain situations.

	•	Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

	•	Control of our general partner may be transferred to a third party without unitholder consent.

Formation Transactions and Partnership Structure

At the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:


	•	We will enter into a merger agreement pursuant to which Mid-Con Energy I, LLC and Mid-Con Energy II, LLC will merge with and into our wholly owned subsidiary, Mid-Con Energy Properties;

	•	We will enter into a new $ million credit facility under which we expect to borrow approximately $ million at the closing of this offering to distribute approximately $ million to the Contributing Parties as the cash portion of the consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing, and to repay in full the outstanding borrowings under our existing credit facilities;

	•	We will issue common units to the public, representing a % limited partner interest in us;

	•	We will issue common units and subordinated units to the Contributing Parties as additional consideration for the merger;

	•	We will issue general partner units to our general partner, representing a 2.0% general partner interest in us, and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $ per unit per quarter;

	•	We will enter into a services agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us; and

	•	We will enter into an omnibus agreement with our general partner that will address certain indemnification matters.

The number of common units that we will issue to the public and the Contributing Parties, as reflected in the third and fourth bullet points above, assume that the underwriters do not exercise their option to purchase up to an additional common units. To the extent the underwriters exercise this option, the number of common units issued to the public (as reflected in the third bullet above) will increase by the aggregate number of common units purchased by the underwriters pursuant to such exercise, and the number of common units issued to the Contributing Parties (as reflected in the fourth bullet above) will decrease by the aggregate number of common units purchased by the underwriters pursuant to such exercise.

Ownership and Organizational Structure of Mid-Con Energy Partners, LP

The diagram below depicts our organization and ownership after giving effect to the offering and the related formation transactions and assumes that the underwriters do not exercise their option to purchase additional common units.


Common units held by the public		%
Common units held by the Contributing Parties:
Common units held by the Founders		%
Common units held by Yorktown		%
Common units held by the other Contributing Parties		%
Subordinated units:
Subordinated units held by the Founders		%
Subordinated units held by Yorktown		%
General partner units	2.0	%

Total	100.0	%


*		The additional Contributing Parties (other than the Founders and Yorktown) are not reflected in the chart above. Certain of such additional Contributing Parties also hold membership interests in the Mid-Con Affiliates.

Management of Mid-Con Energy Partners, LP

We are managed and operated by the board of directors and executive officers of our general partner, Mid-Con Energy GP, LLC. Our unitholders will not be entitled to elect our general partner or its directors or otherwise participate in our management or operation. All of the executive officers of our general partner are also officers and/or directors of the Mid-Con Affiliates. For information about the executive officers and directors of our general partner, please read “Management.”

Our general partner has two classes of member interests. S. Craig George, the Executive Chairman of the board of directors of our general partner, Charles R. Olmstead, the Chief Executive Officer and a director of our general partner, Jeffrey R. Olmstead, the President and Chief Financial Officer and a director of our general partner, or collectively, the “Founders,” will each own one-third of the Class A member interests in our general partner. Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., and Yorktown Energy Partners VIII, L.P.,

will own %, % and %, respectively, of the Class B member interests in our general partner. The Class B member interests have no voting rights. As a result, the Founders, as holders of all of the Class A member interests, control our general partner and will be entitled to appoint its entire board of directors. The Class A member interests and the Class B member interests, each in the aggregate, are entitled to receive 50% of the distributions made by our general partner, which will include proceeds from the distributions our general partner receives in respect of its 2.0% general partner interest in us and the incentive distribution rights. Please see “Security Ownership of Certain Beneficial Owners and Management.”

Neither we, our general partner, nor our subsidiary have any employees. Immediately prior to the closing of this offering, we and our general partner will enter into a services agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will provide management, administrative and operating services to us. Although all of the employees that conduct our business are employed by Mid-Con Energy Operating, we sometimes refer to these individuals in this prospectus as our employees.

We will initially have one subsidiary, Mid-Con Energy Properties, that will hold title to our properties.

Principal Executive Offices and Internet Address

Our headquarters are located in Dallas, Texas at . Our principal operating office is located at 2431 East 61st Street, Suite 850, Tulsa, Oklahoma 74136, and our telephone number is (918) 743-7575. Our website address is and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

Under our partnership agreement, our general partner has a legal duty to manage us in a manner that is in, or not opposed to, the best interests of the holders of our common and subordinated units. This legal duty, as modified by our partnership agreement, originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owners, the Founders and Yorktown. All of the executive officers of our general partner are also officers and/or directors of the Mid-Con Affiliates and will have economic interests in the Mid-Con Affiliates. In addition, Peter A. Leidel, a principal of Yorktown, will serve on our board of directors. Mr. Leidel has economic interests in Yorktown and its affiliates that manage, hold and own investments in other funds and companies that may compete with us. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its owners and affiliates, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flow necessary to make cash distributions to our unitholders, including determinations related to:


	•	purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that may also be suitable for the Mid-Con Affiliates, Yorktown or any Yorktown portfolio company;

	•	the manner in which our business is operated;


	•	the level of our borrowings;

	•	the amount, nature and timing of our capital expenditures; and

	•	the amount of cash reserves necessary or appropriate to satisfy our general, administrative and other expenses and debt service requirements and to otherwise provide for the proper conduct of our business.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”

Except for certain amendments that our general partner may adopt at any time without unitholder approval, our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including any common units held by affiliates of our general partner) after the subordination period has ended. Upon consummation of this offering, our general partner will continue to be owned by the Founders and Yorktown, who collectively will own and control the voting of an aggregate of approximately % of our outstanding common units and all of our subordinated units. Assuming that we do not issue any additional common units and the Founders and Yorktown do not transfer their units, they will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholders. Please see “Risk Factors—Risks Inherent in an Investment in Us” and “The Partnership Agreement—Amendment of the Partnership Agreement.”

Partnership Agreement Modification of Fiduciary Duties

Our partnership agreement limits the liability of our general partner and reduces the fiduciary duties it owes to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of the fiduciary duties that our general partner owes to our unitholders. By purchasing a common unit, our unitholders agree to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, are treated as having consented to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.

The Offering


Common units offered by us		common units, or common units if the underwriters exercise in full their option to purchase additional common units.

Units outstanding after this offering		common units and subordinated units, representing % and %, respectively, limited partner interests in us.

		If the underwriters do not exercise their option to purchase additional common units, we will issue that number of units to the Contributing Parties at the expiration of the option period as additional consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into Mid-Con Energy Properties at closing. To the extent the underwriters exercise their option to purchase up to an additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder of the common units that are subject to the option, if any, will be issued to the Contributing Parties. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all outstanding units.

		In addition, our general partner will own general partner units representing a 2.0% general partner interest in us.

Use of proceeds		We intend to use the expected net proceeds of approximately $ million from this offering, based upon the assumed initial public offering price of $ per common unit, after deducting underwriting discounts, a structuring fee and estimated expenses, together with borrowings of approximately $ million under our new revolving credit facility, to:

		• distribute approximately $ million to the Contributing Parties as the cash portion of the consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing; and

		• repay in full $ million of indebtedness outstanding under our existing revolving credit facilities.

		If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $ million. The net proceeds from any exercise of such option will be used to distribute additional cash consideration in respect of the merger to the Contributing Parties. Please read “Use of Proceeds.”

Cash distributions		We intend to pay a minimum quarterly distribution of $ per unit per quarter on all common, subordinated and


		general partner units ($ per unit on an annualized basis) to the extent we have sufficient cash from operations, after the establishment of cash reserves and the payment of fees and expenses.

		Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will prorate the minimum quarterly distribution payable for the period from the closing of this offering through December 31, 2011, based on the actual length of that period.

		Assuming our general partner maintains its 2.0% general partner interest in us, our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:

		• first , 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $ , plus any arrearages from prior quarters;

		• second , 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $ ; and

		• third , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $ .

		If cash distributions to our unitholders exceed $ per common unit and subordinated unit in any quarter, our unitholders and our general partner will receive distributions according to the following allocations:


Total Quarterly		Marginal Percentage
Distribution Target Amount		Interest in Distributions
		Unitholders			General Partner

above $	up to $		85.0	%		15.0	%
above $			75.0	%		25.0	%


		The percentage interests shown above for our general partner include its 2% general partner interest. We refer to the additional increasing distributions to our general partner in excess of its 2.0% general partner interest as “incentive distributions.”

		Pro forma cash available for distribution generated during the year ended December 31, 2010 and the twelve months ended June 30, 2011 was approximately $ million and $ million, respectively. The amount of available cash we will need to pay the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering and the corresponding distributions on our general partner’s 2.0% interest will be approximately $ million (or an average of


		approximately $ million per quarter). As a result, for the year ended December 31, 2010, we would have generated available cash sufficient to pay a cash distribution of $ per unit per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution on our common units during that period, and we would not have been able to pay any distributions on our subordinated units during that period. For the twelve months ended June 30, 2011, we would have generated available cash sufficient to pay a cash distribution of $ per unit per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution on our common units during that period, and we would not have been able to pay any distributions on our subordinated units during that period. For a calculation of our ability to pay distributions to our unitholders based on our pro forma results for the year ended December 31, 2010 and the twelve months ended June 30, 2011, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended June 30, 2011.”

		We believe, based on our financial forecast and the related assumptions included under “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA for the Year Ending December 31, 2012,” that we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $ per unit on all common, subordinated and general partner units for the four quarters ending December 31, 2012.

Subordinated units		The Founders and Yorktown will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Subordination period		The subordination period will end on the first business day after we have earned and paid at least (i) $ (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2014 or (ii) $ (125% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and the incentive distribution rights for any four-quarter period and we have paid at


		least the minimum quarterly distribution on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest for each quarter in such four-quarter period, in each case, provided that there are no arrearages on our common units at that time.

		In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Issuance of additional units		We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

Limited voting rights		Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2 / 3 % of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, the Founders and Yorktown will own an aggregate of approximately % of our common and 100% of our subordinated units and, therefore, will be able to prevent the removal of our general partner. Please read “The Partnership Agreement—Limited Voting Rights.”

Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon consummation of this offering, the Founders and Yorktown will own an aggregate of approximately % of our common and 100% of our subordinated units. Please read “The Partnership Agreement—Limited Call Right.”


Eligible Holders and redemption		Units held by persons who our general partner determines are not Eligible Holders will be subject to redemption. As used herein, an Eligible Holder means any person or entity qualified to hold an interest in oil and natural gas leases on federal lands. If, following a request by our general partner, a transferee or unitholder, as the case may be, does not properly complete a recertification for any reason, we will have the right to redeem the units held by such person at the then-current market price of the units held by such person. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units—Transfer Agent and Registrar—Transfer of Common Units” and “The Partnership Agreement—Non-Citizen Unitholders; Redemption.”

Estimated ratio of taxable income to distributions		We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the period ending , such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for the basis of this estimate.

Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Listing and trading symbol		We intend to apply to list our common units on the NASDAQ Global Market, subject to official notice of issuance, under the symbol “MCEP.”

Summary Historical and Pro Forma Financial Data

We were formed in July 2011 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor, which consist of the consolidated historical financial statements of Mid-Con Energy Corporation through June 30, 2009 and the combined historical financial statements of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, thereafter. The following table presents summary historical financial data of our predecessor and summary pro forma financial data of Mid-Con Energy Partners, LP as of the dates and for the periods indicated. The summary historical financial data as of December 31, 2009 and 2010 and for the years ended June 30, 2008 and 2009, the six months ended December 31, 2009 and the year ended December 31, 2010 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data as of June 30, 2011 and for the six months ended June 30, 2010 and 2011 are derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma financial data as of June 30, 2011 and for the six months ended June 30, 2011 and the year ended December 31, 2010 are derived from the unaudited pro forma condensed financial statements of our predecessor included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:


	•	the sale by Mid-Con Energy I, LLC and Mid-Con Energy II, LLC of certain oil and natural gas properties representing approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011, and certain subsidiaries that do not own oil and natural gas reserves, including Mid-Con Energy Operating, to the Mid-Con Affiliates for aggregate consideration of $7.5 million;

	•	the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC with our wholly owned subsidiary in exchange for aggregate consideration of common units, subordinated units and $ million in cash;

	•	the issuance to our general partner of general partner units, representing a 2.0% general partner interest in us, and the incentive distribution rights;

	•	the issuance and sale by us to the public of common units in this offering and the application of the net proceeds as described in “Use of Proceeds;” and

	•	our borrowing of approximately $ million under our new credit facility and the application of the proceeds as described in “Use of Proceeds.”

The unaudited pro forma balance sheet data assume the events listed above occurred as of June 30, 2011. The unaudited pro forma statement of operations data for the six months ended June 30, 2011 and the year ended December 31, 2010 assume the items listed above occurred as of January 1, 2010. We have not given pro forma effect to incremental general and administrative expenses of approximately $3.0 million that we expect to incur annually as a result of being a publicly traded partnership.

You should read the following table in conjunction with “—Formation Transactions and Partnership Structure,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of our predecessor and the unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP and the notes thereto included elsewhere in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not

calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.


																			Mid-Con Energy
																			Partners, LP
							Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (combined)												Pro Forma
	Mid-Con Energy Corporation						Six Months												Year			Six Months
	(consolidated)						Ended			Year Ended			Six Months Ended						Ended			Ended
	Year Ended June 30,						December 31,			December 31,			June 30,						December 31,			June 30,
Statement of Operations Data:	2008			2009			2009			2010			2010			2011			2010			2011
													(unaudited)			(unaudited)			(unaudited)			(unaudited)
	(in thousands)
Revenues:
Oil sales	$	13,667		$	10,246		$	5,729		$	16,853		$	7,482		$	15,609		$	15,516		$	14,888
Natural gas sales		618			2,172			743			1,418			803			657			1,392			657
Realized loss on derivatives, net		(804	)		(669	)		(350	)		(90	)		(91	)		(714	)		(90	)		(714	)
Unrealized gain (loss) on derivatives, net		(2,035	)		1,679			(147	)		(707	)		545			1,046			(707	)		984

Total revenues		11,446			13,428			5,975			17,474			8,739			16,598			16,111			15,815

Operating costs and expenses:
Lease operating expenses		5,005			5,369			2,431			6,237			3,038			3,550			4,788			2,967
Oil and gas production taxes		946			631			269			822			384			655			741			609
Dry holes and abandonments of unproved properties		—			—			—			1,418			44			772			514			772
Geological and geophysical		1,296			507			979			394			287			58			—			—
Depreciation, depletion and amortization		1,786			2,802			2,503			6,217			3,629			2,419			3,277			2,081
Accretion of discount on asset retirement obligations		56			78			58			127			64			32			63			32
General and administrative		1,871			1,767			704			982			587			476			982			476
Impairment of proved oil and gas properties		—			—			7,785			1,831			—			—			1,234			—

Total operating costs and expenses		10,960			11,154			14,729			18,028			8,033			7,962			11,599			6,937

Income (loss) from operations		486			2,274			(8,754	)		(554	)		706			8,636			4,512			8,878

Other income (expenses):
Interest income and other		115			119			35			218			151			62			126			4
Interest expense		(3	)		(93	)		(2	)		(98	)		(17	)		(237	)		(1,200	)		(600	)
Gain on sale of assets		—			—			—			354			353			1,209			—			—
Other revenue and expenses, net		108			298			118			847			299			576			—			—
Income tax expense—current		—			(625	)		—			—			—			—			—			—
Income tax (expense) benefit—deferred		(194	)		686			—			—			—			—			—			—

Net income (loss)	$	512		$	2,659		$	(8,603	)	$	767		$	1,492		$	10,246		$	3,438		$	8,282

Net income per limited partner unit (basic and diluted)																			$			$

Weighted average number of limited partner units outstanding (basic and diluted)

Other Financial Data:
Adjusted EBITDA	$	4,471		$	3,773		$	1,857		$	10,593		$	4,197		$	11,389			10,307			10,779
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	4,221		$	10,935		$	(14	)	$	11,798		$	6,685		$	5,192
Investing activities		(7,646	)		(12,448	)		(4,039	)		(22,726	)		(8,284	)		(13,351	)
Financing activities		147			4,841			(1,164	)		10,387			1,058			8,377


							Mid-Con Energy I, LLC and															Mid-Con
							Mid-Con Energy II, LLC															Energy Partners, LP
							(combined)															Pro Forma
							As of December 31,									As of June 30,						As of June 30,
Balance Sheet Data:							2009			2010						2011						2011
							(in thousands)															(unaudited)
Working capital(1)							$	2,420		$	(1,256	)				$	4,383					$	4,383
Total assets								40,999			57,059						72,582						72,342
Total debt								337			5,513						13,310						30,000
Partners’ capital								37,282			43,264						56,290						39,360


(1)		For 2010, excludes $5.3 million of current maturities under our predecessor’s credit facilities. The maturity date for these facilities was subsequently extended to December 2013.

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):


	•	Plus:


	•	income tax expense (benefit), if any;

	•	interest expense;

	•	depreciation, depletion and amortization;

	•	accretion of discount on asset retirement obligations;

	•	unrealized losses on commodity derivative contracts;

	•	impairment expenses;

	•	dry hole costs and abandonments of unproved properties; and

	•	loss on sale of assets;


	•	Less:


	•	interest income;

	•	unrealized gains on commodity derivative contracts; and

	•	gain on sale of assets.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess:


	•	the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and

	•	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil properties.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our reconciliation of Adjusted EBITDA to Net Income. The table below further presents a reconciliation of Adjusted EBITDA to cash flow from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.

Reconciliation of Adjusted EBITDA to Net Income


							Mid-Con Energy I, LLC and												Mid-Con Energy
							Mid-Con Energy II, LLC												Partners, LP
	Mid-Con Energy						(combined)												Pro Forma
	Corporation						Six Months			Year			Six Months			Six Months			Year			Six Months
	(consolidated)						Ended			Ended			Ended			Ended			Ended			Ended
	Year Ended June 30,						December 31,			December 31,			June 30,			June 30,			December 31,			June 30,
	2008			2009			2009			2010			2010			2011			2010			2011
													(unaudited)			(unaudited)			(unaudited)			(unaudited)
	(in thousands)
Net income (loss)	$	512		$	2,659		$	(8,603	)	$	767		$	1,492		$	10,246		$	3,438		$	8,282
Income tax expense (benefit)—deferred		194			(686	)		—			—			—			—			—			—
Income tax expense—current		—			625			—			—			—			—			—			—
Interest expense		3			93			2			98			17			237			1,200			600
Depreciation, depletion and amortization		1,786			2,802			2,503			6,217			3,629			2,419			3,277			2,081
Accretion of discount on asset retirement obligations		56			78			58			127			64			32			63			32
Unrealized (gain) loss on derivatives, net		2,035			(1,679	)		147			707			(545	)		(1,046	)		707			(984	)
Impairment of proved oil and gas properties		—			—			7,785			1,831			—			—			1,234			—
Dry holes and abandonments of unproved properties		—			—			—			1,418			44			772			514			772
Gain on sales of assets		—			—			—			(354	)		(353	)		(1,209	)		—			—
Interest income		(115	)		(119	)		(35	)		(218	)		(151	)		(62	)		(126	)		(4	)

Adjusted EBITDA	$	4,471		$	3,773		$	1,857		$	10,593		$	4,197		$	11,389		$	10,307		$	10,779



*Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities*



							Mid-Con Energy I, LLC and
	Mid-Con						Mid-Con Energy II, LLC
	Energy						(combined)
	Corporation						Six Months			Year			Six Months			Six Months
	(consolidated)						Ended			Ended			Ended			Ended
	Year Ended June 30,						December 31,			December 31,			June 30,			June 30,
	2008			2009			2009			2010			2010			2011
													(unaudited)			(unaudited)
	(in thousands)
Net cash provided by (used in) operating activities	$	4,221		$	10,935		$	(14	)	$	11,798		$	6,685		$	5,192
Change in working capital		521			(7,761	)		1,904			(1,085	)		(2,354	)		6,022
Income tax expense—current		—			625			—			—			—			—
Bad debt expense		(159	)		—			—			—			—			—
Interest expense		3			93			2			98			17			237
Interest income		(115	)		(119	)		(35	)		(218	)		(151	)		(62	)

Adjusted EBITDA	$	4,471		$	3,773		$	1,857		$	10,593		$	4,197		$	11,389

Summary Pro Forma and Historical Reserve and Operating Data

The following table presents summary data with respect to the estimated net proved oil and natural gas reserves that we will own at the closing of this offering and the standardized measure amounts associated with those estimated proved reserves as of December 31, 2010 and as of June 30, 2011, both based on reserve reports prepared by our internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. Our estimated proved reserves as of December 31, 2010 are presented on a pro forma basis and exclude certain properties of our predecessor that were sold to the Mid-Con Affiliates on June 30, 2011. The properties we sold represented approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of that date.

These reserve estimates were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect.

For a discussion of risks associated with internal reserve estimates, please read “Risk Factors—Risks Related to Our Business—Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.” Please also read “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business and Properties—Oil and Natural Gas Reserves and Production—Estimated Proved Reserves,” and the summary of our reserve reports dated December 31, 2010 and June 30, 2011 included in this prospectus in evaluating the material presented below.


	Pro Forma as of		As of
	December 31,		June 30,
	2010(2)		2011

Reserve Data(1):
Estimated proved reserves (MBoe)		7,116		7,907
Estimated proved developed reserves (MBoe)		3,710		5,605
Estimated proved undeveloped reserves (MBoe)		3,406		2,302
Standardized Measure (in millions)(3)	$	182.1	$	233.1


(1)		Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $79.43 per Bbl for oil and $4.37 per MMBtu for natural gas at December 31, 2010 and $89.96 per Bbl for oil and $4.20 per MMBtu for natural gas at June 30, 2011. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For the year ended December 31, 2010, the relevant average realized prices for oil and natural gas were $74.15 per Bbl and $7.56 per Mcf, respectively, on a pro forma basis. For the six months ended June 30, 2011, the relevant average realized prices for oil and natural gas were $93.55 per Bbl and $8.84 per Mcf, respectively, on a pro forma basis. Realized natural gas sales price per Mcf includes the sale of natural gas liquids for both the year ended December 31, 2010 and the six months ended June 30, 2011.

(2)		Excludes certain properties, which represented approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011, that were sold to the Mid-Con Affiliates on June 30, 2011.

(3)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas . Because we were not subject to federal or state income taxes for the periods presented, we make no provision for federal or state income taxes in the calculation of our standardized measure. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”


	Pro Forma(1)
			Six Months
	Year Ended		Ended
	December 31,		June 30,
	2010		2011

Production and operating data:
Net production volumes:
Oil (MBbls)		209		159
Natural gas (MMcf)		184		74
Total (MBoe)		240		172
Average net production (Boe/d)		657		950
Average sales price:(2)
Oil (per Bbl)	$	74.15	$	93.55
Natural gas (per Mcf)(3)	$	7.56	$	8.84
Average price per Boe	$	67.15	$	92.19
Average unit costs per Boe:
Oil and natural gas production expenses	$	19.95	$	17.29
Production taxes	$	3.09	$	3.56
General and administrative and other(4)	$	4.06	$	2.49
Depreciation, depletion and amortization	$	13.66	$	12.13


(1)		Excludes production from certain properties, which represent approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011, that were sold to the Mid-Con Affiliates on June 30, 2011.

(2)		Prices do not include the effects of derivative cash settlements.

(3)		Realized natural gas sales price per Mcf includes the sale of natural gas liquids.

(4)		Pro forma general and administrative expenses do not include the additional expenses we would have incurred as a publicly traded partnership. We estimate these additional expenses would have been $3.0 million, or $12.50 per Boe, for the year ended December 31, 2010 and $1.5 million, or $8.72 per Boe, for the six months ended June 30, 2011 on a pro forma basis.

RISK FACTORS

Limited partner interests are inherently different from the 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 a similar business. Prospective unitholders should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.

Risks Related to Our Business

We may not have sufficient cash to pay the minimum quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $ (or $ million in the aggregate), or any distribution at all, on our units. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development of our oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of cash that we distribute to our unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:


	•	the amount of oil and natural gas we produce;

	•	the prices at which we sell our oil and natural gas production;

	•	the amount and timing of settlements on our commodity derivative contracts;

	•	the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;

	•	the level of our operating costs, including payments to our general partner; and

	•	the level of our interest expenses, which will depend on the amount of our outstanding indebtedness and the applicable interest rate.

Further, the amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended June 30, 2011.

On a pro forma historical basis, assuming we had completed our formation transactions on July 1, 2010, our unaudited pro forma available cash generated during the twelve months ended June 30, 2011 would have been approximately $ million, which would have been sufficient to pay only % of the aggregate minimum quarterly distribution on our common units and no distributions on our subordinated units during that period. For a calculation of our ability to

have made distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2010 and the twelve months ended June 30, 2011, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended June 30, 2011.”

The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results.

Our management’s forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2012. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted. If our actual results are significantly below forecasted results, we may not generate enough cash available for distribution to pay the minimum quarterly distribution or any amount on our common units, which may cause the market price of our common units to decline materially. For prospective financial information regarding our ability to pay the minimum quarterly distribution on our common units and general partner units for the twelve months ending December 31, 2012, please read “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA for the Year Ending December 31, 2012.”

Unless we replace the oil reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders at the minimum quarterly distribution rate.

We may be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. Producing oil reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil reserves and production and, therefore, our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.

Our operations may require substantial capital expenditures, which could reduce our cash available for distribution and could materially affect our ability to make distributions to our unitholders.

We may be required to make substantial capital expenditures from time to time in connection with the production of our oil reserves. Further, if the borrowing base under our new credit facility or our revenues decrease as a result of lower oil prices, declines in estimated reserves or production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at the expected levels so as to generate an amount of cash necessary to make distributions to our unitholders.

Developing and producing oil is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

The cost of developing and operating oil properties, particularly under a waterflood, is often uncertain, and cost and timing factors can adversely affect the economics of a well. Our efforts may be uneconomical if our properties are productive but do not produce as much oil as we had

estimated. Furthermore, our producing operations may be curtailed, delayed or canceled as a result of other factors, including:


	•	high costs, shortages or delivery delays of equipment, labor or other services;

	•	unexpected operational events and conditions;

	•	adverse weather conditions and natural disasters;

	•	injection plant or other facility or equipment malfunctions and equipment failures or accidents;

	•	unitization difficulties;

	•	pipe or cement failures, casing collapses or other downhole failures;

	•	lost or damaged oilfield service tools;

	•	unusual or unexpected geological formations and reservoir pressure;

	•	loss of injection fluid circulation;

	•	fires, blowouts, surface craterings, explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations; and

	•	uncontrollable flows of oil well fluids.

If any of these factors were to occur with respect to a particular property, we could lose all or a part of our investment in the property, or we could fail to realize the expected benefits from the property, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.

We inject water into most of our properties to maintain and, in some instances, to increase the production of oil. We may in the future employ other secondary or tertiary recovery methods in our operations. The additional production and reserves attributable to the use of secondary recovery methods and of tertiary recovery methods are inherently difficult to predict. If our recovery methods do not result in expected production levels, we may not realize an acceptable return on the investments we make to use such methods.

A decline in oil prices, or an increase in the differential between the NYMEX or other benchmark prices of oil and the wellhead price we receive for our production, will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Lower oil prices may decrease our revenues and, therefore, our cash available for distribution to our unitholders. Historically, oil prices have been extremely volatile. For example, for the five years ended December 31, 2010, the NYMEX—WTI oil price ranged from a high of $145.29 per Bbl to a low of $31.41 per Bbl. A significant decrease in commodity prices may cause us to reduce the distributions we pay to our unitholders or to cease paying distributions altogether.

Also, the prices that we receive for our oil production often reflect a regional discount, based on the location of the production, to the relevant benchmark prices that are used for calculating hedge positions, such as NYMEX. These discounts, if significant, could similarly reduce our cash available for distribution to our unitholders and adversely affect our financial condition.

If commodity prices decline and remain depressed for a prolonged period, production from a significant portion of our oil properties may become uneconomic and cause write downs of the value of such oil properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.

Significantly lower oil prices may render many of our development projects uneconomic and result in a downward adjustment of our reserve estimates, which would negatively impact our

borrowing base and ability to borrow to fund our operations or make distributions to our unitholders. As a result, we may reduce the amount of distributions paid to our unitholders or cease paying distributions. In addition, a significant or sustained decline in oil prices could hinder our ability to effectively execute our hedging strategy. For example, during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our borrowing base upon a redetermination.

Further, deteriorating commodity prices may cause us to recognize impairments in the value of our oil properties. In addition, if our estimates of drilling 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 properties as impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Our hedging strategy may be ineffective in removing the impact of commodity price volatility from our cash flow, which could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

We expect to enter into commodity derivative contracts at times and on terms designed to maintain, over the long term, a portfolio covering approximately 50% to 80% of our estimated oil production from total proved developed producing reserves over a three-to-five year period at any given point of time, although we may from time to time hedge more or less than this approximate range. The prices at which we are able to enter into commodity derivative contracts covering our production in the future will be dependent upon oil prices at the time we enter into these transactions, which may be substantially higher or lower than current oil prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil prices received for our future production.

In addition, our new credit facility may hinder our ability to effectively execute our hedging strategy. To the extent our new credit facility limits the maximum percentage of our production that we can hedge or the duration of those hedges, we may be unable to enter into additional commodity derivative contracts during favorable market conditions and, thus, unable to lock in attractive future prices for our product sales. Conversely, while we do not expect that our new credit facility will require us to hedge a minimum percentage of our production, it may cause us to enter into commodity derivative contracts at inopportune times. For example, during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our borrowing base upon a redetermination.

Our hedging activities could result in cash losses, could reduce our cash available for distribution and may limit the prices we would otherwise realize for our production.

Many of the derivative contracts that we will be a party to will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays), we might be forced to satisfy all or a portion of our hedging

obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity and our cash available for distribution to our unitholders.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions 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 decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil in an exact way. Oil reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and assumptions concerning future oil prices, future production levels and operating and development costs.

As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove inaccurate. For example, if the prices used in our December 31, 2010 reserve reports had been $10.00 less per barrel for oil, the standardized measure of our estimated proved reserves as of that date on a pro forma basis would have decreased by $36.7 million, from $183.2 million to $146.5 million.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could affect our business, results of operations and financial condition and our ability to make distributions to our unitholders.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards Codification 932, “ Extractive Activities—Oil and Gas ,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

A significant portion of total proved reserves as of June 30, 2011 are undeveloped, and those reserves may not ultimately be developed.

As of June 30, 2011, of our total estimated proved reserves, approximately 29% on a Boe basis, or 24% as calculated using the standardized measure, were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and waterflood operations. The reserve data assumes that we can and will make these expenditures and

conduct these operations, successfully. These assumptions may not prove correct and we may ultimately determine the development of all, or any portion of, such proved but undeveloped reserves is not economically feasible.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:


	•	unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;

	•	unable to obtain financing for these acquisitions on economically acceptable terms; or

	•	outbid by competitors.

If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil reserves. Even if we make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:


	•	the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, operating expenses and costs;

	•	an inability to successfully integrate the assets we acquire;

	•	a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

	•	a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

	•	the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

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

	•	an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and

	•	facts and circumstances that could give rise to significant cash and certain non-cash charges, such as the impairment of oil properties, goodwill or other intangible assets, asset devaluations or restructuring charges.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of properties acquired from third parties (as opposed to from the Mid-Con Affiliates) may be incomplete because it generally is not feasible to perform an in-depth review of such properties, given the time constraints imposed by most sellers. Even a detailed review of the records associated with properties owned by third parties may not reveal existing or potential

problems, nor will such a review permit us to become sufficiently familiar with such properties to assess fully the deficiencies and potential issues associated with such properties. We may not always be able to inspect every well on properties owned by third parties, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

We only own oil and natural gas properties and related assets, all of which are currently located in Oklahoma and Colorado. An adverse development in the oil and natural gas business in these geographic areas could have an impact on our results of operations and cash available for distribution to our unitholders.

We are primarily dependent upon one customer for our production sales and we may experience a temporary decline in revenues and production if we lose that customer.

Sunoco Logistics Partners L.P., or Sunoco Logistics, accounted for approximately 76% of our total sales revenues for the year ended December 31, 2010. Our production is marketed to Sunoco Logistics under renewable six-month marketing contracts with Mid-Con Energy Operating. By selling a substantial majority of our production to Sunoco Logistics under these contracts, we believe that we receive more favorable pricing than would otherwise be available to us if smaller amounts had been sold to several purchasers based on posted prices. To the extent Sunoco Logistics or any other significant customer reduces the volume of oil they purchase from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our oil production, and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders at the then-current distribution rate or at all.

In addition, a failure by Sunoco Logistics or any of our other significant customers, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.

Unitization difficulties may prevent us from developing certain properties or greatly increase the cost of their development.

Regulation of waterflood unit formation is typically governed by state law. In Oklahoma, where most of our properties are located, 63% of the leasehold and mineral owners in a proposed unit area must consent to a unitization plan before the Oklahoma Corporation Commission (the regulatory body which oversees issues related to unitization and well spacing) will issue a unitization order. We may be required to dedicate significant amounts of time and financial resources to obtaining consents from other owners and the necessary approvals from the Oklahoma Corporation Commission and similar regulatory agencies in other states. Obtaining these consents and approvals may also delay our ability to begin developing our new waterflood projects and may prevent us from developing our properties in the way we desire.

Other owners of mineral rights may object to our waterfloods.

It is difficult to predict the movement of the injection fluids that we use in connection with waterflooding. It is possible that certain of these fluids may migrate out of our areas of operations and into neighboring properties, including properties whose mineral rights owners have not

consented to participate in our operations. This may result in litigation in which the owners of these neighboring properties may allege, among other things, a trespass and may seek monetary damages and possibly injunctive relief, which could delay or even permanently halt our development of certain of our oil properties.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders at the minimum quarterly distribution rate.

The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ financial, technical and personnel resources substantially greater than ours. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas 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 properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining our interests could take actions, such as drilling additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

We may incur additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to pay future distributions or execute our business plan.

We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our new credit facility. If we use borrowings under our new credit facility to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.

We expect that our new credit facility will have restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

We expect that our new credit facility will restrict, among other things, our ability to incur debt and pay distributions under certain circumstances, and will require us to comply with

customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our new credit facility that are not cured or waived within specific time periods, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our new credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our new credit facility, the lenders could seek to foreclose on our assets.

The total amount we will be able to borrow under our new credit facility will be limited by a borrowing base, which will be primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts, as determined by our lenders in their sole discretion. The borrowing base will be subject to redetermination on a semi-annual basis. Any substantial or sustained decline in commodity prices would likely lead to a decrease in our borrowing base upon redetermination. In the future, we may be unable to access sufficient capital under our new credit facility as a result of a decrease in our borrowing base due to a subsequent borrowing base redetermination.

Our business depends in part on transportation, pipelines and refining facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our production and could harm our business.

The marketability of our production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems, tanker truck availability and extreme weather conditions. Our access to transportation options can also be affected by U.S. federal and state regulation of oil production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or refining facility capacity could reduce our ability to market our oil production and harm our business.

The third parties on whom we rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, tribal and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised

or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and Properties—Environmental Matters and Regulation” and “Business and Properties—Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

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

Our oil production operations are subject to complex and stringent laws and regulations. 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. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Our business is subject to federal, tribal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of oil production. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and Properties—Environmental Matters and Regulation” and “Business and Properties—Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA adopted two sets of regulations under the existing Clean Air Act requiring a reduction in emissions of GHGs from motor vehicles that became effective on January 2, 2011. The EPA also determined that a permit review for GHG emissions from certain stationary sources was triggered under the federal air permit programs. EPA adopted a tiered approach to implementing the permitting of GHG emissions from stationary sources in May 2010. The so-called “tailoring rule” only requires the stationary sources with the largest emissions to undergo an assessment of GHG emissions under the best available control technology under the federal permitting programs. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHGs emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published mandatory reporting rules for certain oil and gas facilities requiring reporting starting in 2012 for emissions in 2011. The adoption and implementation of any regulations 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 and natural gas that we produce.

In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane, which are understood to contribute to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by

Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to emissions of GHGs. In addition, almost half of the states in the United States have begun to address GHG emissions, primarily through the planned development of GHG emission inventories or regional GHG cap and trade programs.

Any future laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs or reduce emissions of and could adversely affect demand for the oil that we produce. Please read “Business and Properties—Environmental Matters and Regulation.”

Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil development and production activities. These costs and liabilities could arise under a wide range of federal, state, tribal and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. Claims for damages to persons or property from private parties and governmental authorities may result from environmental and other impacts of our operations.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues. For example, on July 28, 2011, the EPA proposed four sets of new rules which, if adopted, will impose stringent new standards for air emissions from oil and natural gas development and production operations, including crude oil storage tanks with a throughput of at least 20 barrels per day, condensate storage tanks with a throughput of at least one barrel per day, completions of new hydraulically fractured natural gas wells, and recompletions of existing natural gas wells that are fractured or refractured. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If adopted, these rules may require us to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. If we were not able to recover the resulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected.

In addition, we may be required to establish reserves against these liabilities. Although we believe we have established appropriate reserves for known liabilities, we could be required to set aside additional reserves in the future if additional liabilities arise, which could have an adverse effect on our operating results.

Please read “Business and Properties—Environmental Matters and Regulation” for more information.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) establishes a new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted (commonly referred to as “margin”). The Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. Since the Act mandates the Commodities Futures Trading Commission (the “CFTC”) to promulgate rules to define these terms, we do not know the definitions the CFTC will actually adopt or how these definitions will apply to us. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalent. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict if and when the CFTC will finalize these regulations.

Although we currently do not, and do not anticipate that we will in the future, voluntarily enter into derivative transactions that require an initial deposit of cash collateral, depending on the rules and definitions ultimately adopted by the CFTC, we might in the future be required to post cash collateral for our commodities derivative transactions. Posting of cash collateral could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other partnership purposes. Also, if commodity prices move in a manner adverse to us, we may be required to meet margin calls. A requirement to post cash collateral could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flow. Although the CFTC has issued proposed rules under the Act, we are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as us are not required to post cash collateral for our derivative hedging contracts. In addition, even if we are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Act’s new requirements, and the costs of their compliance will likely be passed on to customers, including us, thus decreasing the benefits to us of hedging transactions and reducing the profitability of our cash flow.

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

The U.S. Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is a commonly used process in the completion of unconventional wells in shale formations, as well as tight conventional formations including many of those that we complete and produce. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level, and could make it easier for third parties to initiate legal proceedings based on allegations that chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil and surface water. In addition, the EPA has recently asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act’s Underground Injection Program and has begun the process of drafting guidance documents on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel fuel. In addition, a number of other federal agencies are also analyzing a variety of environmental issues associated with hydraulic fracturing and could potentially take regulatory actions that impair our ability to conduct hydraulic fracturing operations. Some

states, including Texas, and various local governments have adopted, and others are considering, regulations to restrict and regulate hydraulic fracturing. Any additional level of regulation could lead to operational delays or increased operating costs which could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and would increase our costs of compliance and doing business, resulting in a decrease of cash available for distribution to our unitholders.

Shortages of rigs, equipment and crews could delay our operations and reduce our cash available for distribution to our unitholders.

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders.

We depend on a limited number of key personnel who would be difficult to replace.

Our operations are dependent on the continued efforts of our executive officers, senior management and key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy.

Competition for experienced technical personnel may negatively impact our operations or financial results.

Our continued success will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for these professionals is strong and will likely intensify as a significant portion of today’s engineers, geologists and other professionals working within the oil and natural gas industry will reach the age of retirement in the coming years. We are likely to continue to experience increased costs to attract and retain these professionals.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease funds available for servicing our debt obligations and other operating expenses.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Risks Inherent in an Investment in Us

Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, our general partner will be owned by the Founders and Yorktown. The Founders and Yorktown will own an aggregate of approximately % of our outstanding

common units and all of our subordinated units. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. All of the executive officers and non-independent directors of our general partner are also officers and/or directors of the Mid-Con Affiliates and will continue to have economic interests in, as well as management and fiduciary duties to, the Mid-Con Affiliates. Additionally, one of the directors of our general partner is a principal with Yorktown. As a result of these relationships, conflicts of interest may arise in the future between the Mid-Con Affiliates and Yorktown and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These potential conflicts include, among others:


	•	Our partnership agreement limits our general partner’s liability, reduces its fiduciary duties and also restricts the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

	•	Neither our partnership agreement nor any other agreement requires the Mid-Con Affiliates and Yorktown or their respective affiliates (other than our general partner) to pursue a business strategy that favors us. The officers and directors of the Mid-Con Affiliates and Yorktown and their respective affiliates (other than our general partner) have a fiduciary duty to make these decisions in the best interests of their respective equity holders, which may be contrary to our interests;

	•	The Mid-Con Affiliates and Yorktown and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;

	•	All of the executive officers of our general partner who will provide services to us will also devote a significant amount of time to the Mid-Con Affiliates and will be compensated for those services rendered;

	•	Our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

	•	We will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us, and Mid-Con Energy Operating will also provide these services to the Mid-Con Affiliates;

	•	Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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

	•	Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

	•	Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;


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

	•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

	•	Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to the common unitholders in certain situations.

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”

The Mid-Con Affiliates, Yorktown and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets.

Neither our partnership agreement nor the omnibus agreement will prohibit the Mid-Con Affiliates, Yorktown and their affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. The Mid-Con Affiliates, Yorktown and their affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage and operate our business. The management team of Mid-Con Energy Operating, which includes the individuals who will manage us, will also provide substantially similar services to the Mid-Con Affiliates, and thus will not be solely focused on our business.

Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage us and operate our assets. Upon consummation of this offering, we will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us.

Mid-Con Energy Operating will also continue to provide substantially similar services and personnel to the Mid-Con Affiliates and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Mid-Con Energy Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Mid-Con Affiliates or other affiliates of our general partner. There is no requirement that Mid-Con Energy Operating favor us over these other entities in providing its services. If the employees of Mid-Con Energy Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution.

Under the services agreement, we will reimburse Mid-Con Energy Operating for the provision of various services and personnel for our benefit. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement.”

In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. In addition, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. This implied distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt.

Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:


	•	a citizen of the United States;

	•	a corporation organized under the laws of the United States or of any state thereof;

	•	a public body, including a municipality; or

	•	an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder run the risk of having their common units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units —Transfer Agent and Registrar—Transfer of Common Units” and “The Partnership Agreement—Non-Citizen Unitholders; Redemption.”

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have no right on an annual or ongoing

basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by the Founders, as a result of their ownership of our general partner, and not by our unitholders. Please read “Management—Management of Mid-Con Energy Partners, LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production levels and asset base, including over the long term. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, which allows our general partner to consider only the interests and factors that it desires, without a duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must either be (i) on terms no less favorable to us than those generally being provided to or available from unrelated third


		parties or (ii) must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;


	•	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 any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors 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; and

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our units. This may result in lower distributions to holders of our common units in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and we have paid incentive distributions at the highest level to which the holders are entitled (23%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received for the two quarters prior to the reset event as compared to the average cash distribution per common unit during that two-quarter period. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time of actual or expected declines in the cash distributions on our incentive distribution rights. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Right to Reset Incentive Distribution Levels.”

Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

The public unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon completion of this offering to be able to prevent the removal of our general partner. The vote of the holders of at least 66 2 / 3 % of all outstanding units voting together as a single class is required to remove our general partner. Following consummation of this offering, the Founders and Yorktown will own approximately % of our outstanding voting units, which will enable those holders, collectively, to prevent the removal of our general partner.

Also, if our general partner is removed without cause during the subordination period and units held by our general partner, if any, and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor business management, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Control of our general partner may be transferred to a third party without unitholder consent.

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

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:


	•	our unitholders’ proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;


	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•	the ratio of taxable income to distributions may increase;

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of our common units may decline.

Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Once our common units are publicly traded, the Founders, Yorktown and the other Contributing Parties may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, the Founders, Yorktown and the other Contributing Parties will own common units and subordinated units, or approximately % of our limited partner interests. The subordinated units owned will automatically convert into an equivalent number of common units at the end of the subordination period. Once our common units are publicly traded, the sale of these units, including common units issued upon the conversion of the subordinated units, in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. For additional information about this call right, please read “The Partnership Agreement—Limited Call Right.”

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long-term. Capital surplus is defined in the glossary and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98.0% to our unitholders and 2.0% to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our unitholders’ liability may not be limited if a court finds that 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 conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:


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

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

Please read “The Partnership Agreement—Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

Our unitholders may have liability to repay distributions.

Under certain circumstances, 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 distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may not be able to resell their common units at the initial public offering price.

Prior to this offering, there has been no public market for the common units. After this offering, there will be publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:


	•	changes in commodity prices;

	•	changes in securities analysts’ recommendations and their estimates of our financial performance;

	•	public reaction to our press releases, announcements and filings with the SEC;

	•	fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

	•	changes in market valuations of similar companies;

	•	departures of key personnel;

	•	commencement of or involvement in litigation;

	•	variations in our quarterly results of operations or those of other oil and natural gas companies;

	•	variations in the amount of our quarterly cash distributions to our unitholders;

	•	future issuances and sales of our common units; and

	•	changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Our unitholders will experience immediate and substantial dilution of $ per unit.

The initial offering price of $ per common unit exceeds our pro forma net tangible book value after this offering of $ per common unit. Based on the initial offering price of $ per common unit, our unitholders will incur immediate and substantial dilution of $ per common unit. This dilution will occur primarily because the assets contributed by affiliates of our general partner are recorded, in accordance with GAAP at their historical cost, and not their fair value.

The impact of such dilution would be magnified upon any conversion of the incentive distribution rights into common units. Please read “Dilution.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and make acquisitions.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:


	•	general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

	•	conditions in the oil and gas industry;

	•	the market price of, and demand for, our common units;

	•	our results of operations and financial condition; and

	•	prices for oil and natural gas.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Tax Risks to Unitholders

In addition to reading the following risk factors, prospective unitholders should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

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

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for 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 would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions

would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. 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. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in our units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution may be adjusted to reflect the impact of that law on us.

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

The Obama Administration’s budget proposal for fiscal year 2012 includes potential legislation that would, if enacted, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. 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 some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

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

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

If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their adjusted tax basis in those units. Because prior distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion, amortization and IDC recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, they may incur a tax liability in excess of the amount of cash they receive from the sale. Please read “Material Tax Consequences—Disposition of Units—Recognition of Gain or Loss.”

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.

We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation, depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audits of and adjustments to a unitholder’s tax returns. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation, depletion and amortization positions we will adopt.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Andrews Kurth LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Andrews Kurth LLP has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to effect a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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 our partnership for federal income tax purposes.

We will be considered to have technically terminated for 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 purposes of determining whether the 50% threshold has been met,

multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if special relief from the IRS is not available) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. A technical termination should not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. Please read “Material Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in Oklahoma and Colorado, each of which currently imposes a personal income tax on individuals. These states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all

USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $ million from this offering, based upon the assumed initial public offering price of $ per common unit, after deducting underwriting discounts, a structuring fee and estimated offering expenses, together with borrowings of approximately $ million under our new revolving credit facility, to:


	•	distribute approximately $ million to the Contributing Parties as the cash portion of the consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing; and

	•	repay in full $ million of indebtedness outstanding under our existing credit facilities.

As of June 30, 2011, the interest rate on our two existing credit facilities was 4% for each facility, and the credit facilities mature on December 31, 2013. Borrowings made under these facilities within the last twelve months were used for acquisitions and development activities.

The following table illustrates our use of proceeds from this offering and our borrowings under our new credit facility:


Sources of Cash (in millions)		Uses of Cash (in millions)

Gross proceeds from this offering(1)	$	Distribution to Contributing Parties(1)	$
Borrowings under our new credit facility	$	Repayment of indebtedness under our existing credit facilities	$
		Underwriting discounts, a structuring fee and estimated offering expenses payable by us	$
Total	$	Total	$


(1)		If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $ million, and the total distribution to the Contributing Parties would be approximately $ million.

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $ million. The net proceeds from any exercise of such option will be used to distribute additional cash consideration to the Contributing Parties in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing. If the underwriters do not exercise their option to purchase additional common units in full, we will issue the number of remaining common units to the Contributing Parties upon the expiration of the option ( common units if the option is not exercised at all) as additional consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing. We will not receive any additional consideration from the Contributing Parties in connection with such issuance. The exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”

A $1.00 increase or decrease in the assumed initial public offering price of $ per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, a structuring fee and estimated offering expenses payable by us, to increase or decrease, respectively, by approximately $ million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $ per common unit, would increase net proceeds to us from this offering by approximately $ million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $ per common unit, would decrease the net proceeds to us from this offering by approximately $ million.

CAPITALIZATION

The following table shows:


	•	historical capitalization as of June 30, 2011; and

	•	our as adjusted capitalization as of June 30, 2011, which gives effect to the formation transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure” on and the application of the net proceeds from this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please read our Unaudited Pro Forma Condensed Financial Statements.


	As of June 30, 2011
			Mid-Con
	Our		Energy
	Predecessor		Partners, LP
	Historical		As Adjusted
	(in thousands)

Cash and cash equivalents	$	440	$	440

Long-term debt	$	13,310	$	30,000
Members’/partners’ capital/net equity:
Predecessor members’ capital	$	56,290	$	39,360
Common units held by purchasers in this offering		—
Common units held by the Contributing Parties		—
Subordinated units		—
General partner interest		—

Total members’/partners’ capital/net equity		56,290

Total capitalization	$	69,600	$

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial offering price of $ per common unit (the midpoint of the price range set forth on the cover of this prospectus), on a pro forma basis as of June 30, 2011, after giving effect to the transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure,” including this offering of common units and the application of the related net proceeds, our net tangible book value would have been $ million, or $ per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit		$
Pro forma net tangible book value per unit before this offering(1)	$
Decrease in net tangible book value per unit attributable to purchasers in the offering

Less: Pro forma net tangible book value per unit after this offering(2)

Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)(4)		$


(1)		Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of units ( common units, subordinated units to be issued to the Contributing Parties and the issuance of general partner units) to be issued to the Contributing Parties and our general partner.

(2)		Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of this offering, by the total number of units to be outstanding after this offering ( common units, subordinated units and general partner units).

(3)		If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $ and $ , respectively.

(4)		Because the total number of units outstanding following the consummation of this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the underwriters’ option to purchase additional common units.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates, including the Founders and Yorktown, and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:


	Units Acquired				Total Consideration
	Number	Percent			Amount	Percent
					(in thousands)

General partner and affiliates(1)(2)				%	$			%
Purchasers in the offering(3)				%				%

Total			100.0	%	$		100.0	%


(1)		Upon the consummation of the transactions contemplated by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner, its owners and their affiliates will own common units, subordinated units and general partner units.

(2)		The assets we will own as a result of the merger of our affiliates into our wholly owned subsidiary were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of our general partner is equal to the net tangible book value of such assets as of June 30, 2011.

(3)		Total consideration is after deducting underwriting discounts, a structuring fee and estimated offering expenses.

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our audited historical financial statements for the years ended June 30, 2008 and 2009, the six months ended December 31, 2009 and the year ended December 31, 2010, our unaudited historical financial statements for the six months ended June 30, 2011 and our unaudited pro forma financial statements for the year ended December 31, 2010 and six months ended June 30, 2011 included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects a basic judgment that our unitholders generally will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Our available cash is the sum of our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to such federal income tax.

Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is or may become subject to certain restrictions, including the following:


	•	Our cash distribution policy will be subject to restrictions on distributions under our new credit facility or other debt agreements that we may enter into in the future. Specifically, we anticipate that our new credit facility will contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility.” Should we be unable to satisfy these restrictions, or if a default occurs under our new credit facility, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.

	•	Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement does not set a


		limit on the amount of cash reserves that our general partner may establish, other than with respect to reserves for future cash distributions. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must believe that the determination is in, or not opposed to, our best interests. We intend to reserve a sufficient portion of our cash generated from operations to fund our exploitation and development capital expenditures. If our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain the current production levels over the long-term of our oil and natural gas properties or maintain the current operating capacity of our other capital assets, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may have the effect of, and may effectively represent, a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment.


	•	Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.

	•	Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders, other than in certain limited circumstances where no unitholder approval is required. However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner). At the closing of this offering, the Founders and Yorktown will own, and the Founders will control, our general partner, and the Founders and Yorktown will own approximately % of our outstanding common units and all of our outstanding subordinated units, or % of our limited partner interests. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

	•	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, our new credit facility and any other debt agreements we may enter into in the future.

	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.


	•	We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including decreases in commodity prices, decreases in our oil and natural gas production or increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs. For a discussion of additional factors that may affect our ability to pay distributions, please read “Risk Factors.”

	•	If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund growth capital expenditures.

	•	All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the cumulative operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components that represent non-operating sources of cash, including a $ million cash basket and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $ million cash basket would allow us to distribute as operating surplus cash proceeds we receive from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, which would represent a return of capital. Distributions representing a return of capital could result in a corresponding decrease in our asset base. Additionally, any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is similar to a return of capital. Distributions from capital surplus could result in a corresponding decrease in our asset base. We do not anticipate that we will make any distributions from capital surplus. Please read “Risk Factors—Risks Inherent in an Investment in Us—If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased,” and “Provisions of Our Partnership Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus” and “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions from Capital Surplus—Effect of a Distribution from Capital Surplus.”

	•	Our ability to make distributions to our unitholders depends on the performance of our operating subsidiary and its ability to distribute cash to us. The ability of our operating subsidiary to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

Our Ability to Grow Depends on Our Ability to Access External Capital

Because we will distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including borrowings under our new credit facility and the issuance of debt and equity securities, rather than operating cash flow, to fund our acquisitions and growth capital expenditures. As a result, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand their ongoing operations. To the extent we issue additional units in connection with any capital expenditures, the payment

of distributions on those additional units may increase the risk that we will be unable to maintain or increase our quarterly per unit distribution level. There are no limitations in our partnership agreement, nor do we expect any limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings (under our credit facility or otherwise) or other debt to finance our growth strategy will increase our interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $ per unit per quarter, or $ per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter, beginning with the quarter ending December 31, 2011. This equates to an aggregate cash distribution of approximately $ million per quarter, or $ million on an annualized basis, based on the number of common units, subordinated units and general partner units expected to be outstanding immediately after the closing of this offering. We will prorate our first distribution for the period from the closing of this offering through December 31, 2011 based on the length of that period. The number of outstanding common units, subordinated units and general partner units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

To the extent the underwriters exercise their option to purchase additional common units in connection with this offering, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remaining common units subject to the option, if any, will be issued to the Contributing Parties, at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units or subordinated units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Use of Proceeds.”

Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner’s initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to the Contributing Parties, upon expiration of the underwriters’ option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units in connection with a reset of the incentive distribution target levels) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its initial 2.0% general partner interest. Our general partner has the right, but is not obligated, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its then current general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 23% of the cash we distribute in excess of $ per common unit per quarter.

The table below sets forth the number of common units, subordinated units and general partner units expected to be outstanding immediately following the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing

of this offering at our minimum quarterly distribution of $ per unit per quarter, or $ per unit on an annualized basis.

Number of

Minimum Quarterly Distribution

Units

One Quarter

Four Quarters

Common units held by the public(1)(2)

Common units held by the Contributing Parties(1)(2)(3)

Subordinated units(3)

General partner units

Total


(1)		Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters do not exercise their option to purchase an additional common units, we will issue the additional common units to the Contributing Parties, upon the expiration of the option. To the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder, if any, will be issued to the Contributing Parties. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

(2)		Does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

(3)		Includes common units and subordinated units held by the Founders and common units and subordinated units held by Yorktown.

During the subordination period, before we make any quarterly distributions to the holders of our subordinated units, our common unitholders will be entitled to receive the full minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period generally will end, and all of the subordinated units will convert into an equal number of common units, once we have earned and paid at least (i) $ on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2014, or (ii) $ (125% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and the incentive distribution rights for any four-quarter period ending on or after , 2012, and we have paid at least the minimum quarterly distribution on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest for each quarter during such four-quarter period, in each case, provided that there are no arrearages on our common units at that time. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units and the corresponding distributions on our general partner’s 2.0% interest, we will use this excess available cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made to holders of the subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement,

including those related to requirements to make cash distributions as described above. However, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in the best interests of the Partnership. Please read “Conflicts of Interest and Fiduciary Duties.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended by a vote of the holders of a majority of our common units. At the closing of this offering, the Founders and Yorktown will own, and the Founders will control, our general partner and the Founders and Yorktown will own approximately % of our outstanding common units and all of our outstanding subordinated units, or % of our limited partner interests. Assuming we do not issue any additional common units and the Founders and Yorktown do not transfer their common units, they will have the ability to amend our partnership agreement without the approval of any other unitholder once the subordination period ends. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

We will pay our quarterly distributions on or about the 15th of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our initial quarterly distribution, we will prorate the minimum quarterly distribution payable for the period from the closing of this offering through December 31, 2011 based on the actual length of the period. We expect to pay this initial quarterly cash distribution on or before February 15, 2012.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $ per unit for the year ending December 31, 2012. In those sections, we present two tables, consisting of:


	•	“Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2010 and the twelve months ended June 30, 2011, based on our unaudited pro forma financial statements. Our calculation of unaudited pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had the formation transactions contemplated in this prospectus occurred in an earlier period; and

	•	“Estimated Cash Available for Distribution,” in which we demonstrate our ability to generate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full minimum quarterly distribution on all the outstanding units, including our general partner units, for the year ending December 31, 2012.

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended June 30, 2011

If we had completed the formation transactions contemplated in this prospectus on January 1, 2010, our unaudited pro forma available cash for the year ended December 31, 2010 would have been approximately $0.1 million. This amount would have been sufficient to pay a cash distribution of $ per unit per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution on our common units during that period, and we would not have been able to pay any distribution on our subordinated units during that period.

If we had completed the transactions contemplated in this prospectus on July 1, 2010, our unaudited pro forma available cash generated for the twelve months ended June 30, 2011 would have been approximately $7.3 million. This amount would have been sufficient to pay a cash distribution of $ per unit per quarter ($ on an annualized basis), or approximately % of the minimum quarterly distribution on our common units during that period, and we would not have been able to pay any distribution on our subordinated units during that period.

Our unaudited pro forma cash available for distribution does not include incremental general and administrative expenses that we expect we will incur as a result of being a publicly traded partnership, consisting of costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, NASDAQ Global Market listing, registrar and transfer agent fees, incremental director and officer liability insurance costs and officer and director compensation. We estimate that these incremental general and administrative expenses initially will be approximately $3.0 million per year. Such incremental general and administrative expenses are not reflected in our historical and pro forma financial statements.

The pro forma financial statements, from which pro forma cash available for distribution is derived, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

The following table illustrates, on an unaudited pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011, the amount of available cash that would have been available for distribution to our unitholders, assuming that the formation transactions had been consummated on January 1, 2010 and July 1, 2010, respectively. Each of the pro forma adjustments reflected or presented below is explained in the footnotes to such adjustments.

Mid-Con Energy Partners, LP

Unaudited Pro Forma Available Cash


	Pro Forma
	Year			Twelve Months
	Ended			Ended
	December 31,			June 30,
	2010			2011
	(in thousands, except per unit data)

Net income	$	3,438		$	9,938
Plus:
Income tax expense (benefit), if any		—			—
Interest expense		1,200			1,200
Depreciation, depletion and amortization		3,277			3,785
Accretion of discount on asset retirement obligations		63			158
Unrealized (gain) loss on derivatives, net		707			(77	)
Impairment of proved oil and gas properties		1,234			1,234
Dry hole costs and abandonments of unproved properties		514			1,263
Interest income		(126	)		(31	)
(Gain) loss on sale of assets		—			—

Adjusted EBITDA(1)	$	10,307		$	17,470
Less:
Incremental general and administrative expense(2)		3,000			3,000
Cash interest expense(3)		1,200			1,200
Estimated average maintenance capital expenditures(4)		6,000			6,000

Pro Forma Available cash	$	107		$	7,270
Pro Forma Annualized distributions per unit		—			—
Pro Forma Estimated annual cash distributions:
Distributions on common units held by purchasers in this offering		—			—
Distributions on common units held by affiliates of our general partner
Distributions on subordinated units
Distributions on general partner units

Total estimated annual cash distributions

Shortfall

Percent of minimum quarterly distributions payable to common unitholders
Percent of minimum quarterly distributions payable to subordinated unitholders


(1)		Adjusted EBITDA is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(2)		Reflects the $3.0 million of estimated incremental annual general and administrative expenses associated with being a publicly traded partnership that we expect to incur.

(3)		In connection with this offering, we intend to enter into a new $ million credit facility under which we expect to incur approximately $30.0 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $30.0 million of borrowings at an assumed weighted-average rate of 4.0%.

(4)		Historically, our predecessor did not make a distinction between maintenance and growth capital expenditures. For purposes of the presentation of Unaudited Pro Forma Cash Available for Distribution, we have estimated that approximately $6.0 million of our capital expenditures were maintenance capital expenditures for each period, which reflects our estimate of the average annual maintenance capital expenditures necessary to maintain our current projected level of production from existing assets through December 31, 2015, based on the forecasted production level of 1,529 Boe per day for the year ending December 31, 2012.

Estimated Adjusted EBITDA for the Year Ending December 31, 2012

Set forth below is a Statement of Estimated Adjusted EBITDA that supports our belief that we will be able to generate sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution on all of our outstanding units for the twelve months ending December 31, 2012. The financial forecast presents, to the best of our knowledge and belief, our expected results of operations, Adjusted EBITDA and cash available for distribution for the forecast period. Based upon the assumptions and considerations set forth in the table below, to fund cash distributions to our unitholders at our annualized minimum quarterly distribution of $ per common unit, subordinated unit and general partner unit, or $ million in the aggregate, for the year ending December 31, 2012, our Adjusted EBITDA for the year ending December 31, 2012 must be at least $ million. The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

Our Statement of Estimated Adjusted EBITDA reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take in order to be able to pay the annualized minimum quarterly distribution on all of our outstanding common, subordinated and general partner units for the year ending December 31, 2012. The assumptions discussed below under “—Assumptions and Considerations” are those that we believe are significant to our ability to generate the minimum Adjusted EBITDA. We believe our actual results of operations and cash flow will be sufficient to generate the minimum Adjusted EBITDA necessary to pay the aggregate annualized minimum quarterly distribution. We can, however, give you no assurance that we will generate this amount. There will likely be differences between our estimated Adjusted EBITDA and our actual results, and those differences could be material. If we fail to generate the estimated Adjusted EBITDA contained in our forecast, we may not be able to pay the aggregate annualized minimum quarterly distribution to all of our unitholders.

While we do not as a matter of course make public projections as to future sales, earnings or other results, our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the minimum quarterly distribution on all our common units, subordinated units and general partner units for the year ending December 31, 2012. This forecast is a forward-looking statement and should be read together with our historical financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the minimum Adjusted EBITDA necessary for us to pay the minimum quarterly distribution on all of our outstanding common, subordinated and general partner units for the year ending December 31, 2012. Readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “—Assumptions and Considerations.”

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Grant Thornton LLP has not compiled, examined or performed any procedures with respect to the accompanying prospective financial information and, accordingly, Grant Thornton LLP does not express an opinion or any other form of assurance with respect thereto. The Grant Thornton LLP reports included in the registration

statement relate to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the minimum Adjusted EBITDA necessary to pay the aggregate annualized minimum quarterly distribution on all of our outstanding common, subordinated and general partner units for the year ending December 31, 2012.

We are providing the Statement of Estimated Adjusted EBITDA to supplement our historical financial statements and in support of our belief that we will have sufficient available cash to pay the aggregate annualized minimum quarterly distribution on all of our outstanding common, subordinated and general partner units for the year ending December 31, 2012. Please read below under “—Assumptions and Considerations” for further information about the assumptions we have made for the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

Our Estimated Adjusted EBITDA

To pay the annualized minimum quarterly distribution to our unitholders of $ per unit for the year ending December 31, 2012, our aggregate cash available to pay distributions must be at least approximately $ million over that period. We have calculated that the amount of estimated Adjusted EBITDA for the year ending December 31, 2012 that will be necessary to generate cash available to pay an aggregate annualized distribution of approximately $ million over that period is approximately $ million. Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flow from operating activities or any other measure calculated in accordance with GAAP.

Adjusted EBITDA is a significant financial metric that will be used by our management to indicate (prior to the establishment of any reserves by the board of directors of our general partner) the cash distributions we expect to pay to our unitholders. Specifically, we intend to use this financial measure to assist us in determining whether we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. For a definition of Adjusted EBITDA, please read “Prospectus Summary—Non-GAAP Financial Measures.”

Mid-Con Energy Partners, LP

Statement of Estimated Adjusted EBITDA


	Year Ending
	December 31, 2012
	(in thousands, except
	per unit amounts)

Revenue and realized commodity derivative gains(losses)(1)	$	49,706
Less:
Lease operating expenses		8,080
Oil and gas production taxes		2,364
General and administrative(2)		4,000
Depreciation, depletion and amortization		9,000
Interest expense		1,200

Net income excluding unrealized gains (losses) on derivatives	$	25,062
Adjustments to reconcile net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA:
Add:
Depreciation, depletion and amortization	$	9,000
Interest expense		1,200

Estimated Adjusted EBITDA(3)	$	35,262
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense	$	1,200
Estimated maintenance capital expenditures(4)		6,000

Estimated cash available for distribution	$	28,062
Annualized minimum quarterly distribution per unit
Estimated annual cash distributions(5):
Distributions on common units held by purchasers in this offering
Distributions on common units held by affiliates of our general partner
Distributions on subordinated units
Distributions on general partner units
Total estimated annual cash distributions
Excess cash available for distribution


(1)		Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)		Includes $3.0 million of estimated incremental annual general and administrative expenses associated with being a publicly traded partnership that we expect to incur.

(3)		Adjusted EBITDA is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(4)		In calculating the estimated cash available for distribution, we have included estimated maintenance capital expenditures for the year ending December 31, 2012 of approximately $6.0 million. We estimate that this amount of average annual maintenance capital expenditures will enable us to maintain our current level of production from existing assets through December 31, 2015, based on a forecasted production level of 1,529 Boe per day for the year ending December 31, 2012.

(5)		The number of outstanding common units assumed herein does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the year ending December 31, 2012, we expect to generate estimated Adjusted EBITDA sufficient to establish reserves for capital expenditures and to pay the aggregate annualized minimum quarterly distribution on all common, subordinated and general partner units for the year ending December 31, 2012.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay quarterly cash distributions equal to our minimum quarterly distribution (absent additional borrowings under our new revolving credit facility), or any amount, on all common, subordinated and general partner units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our minimum quarterly distribution over the long term without making accretive acquisitions or substantial capital expenditures that maintain the current production levels of our oil and natural gas properties and the current operating capacity of our other capital assets. We expect to rely primarily on external financing sources, including bank borrowings and the issuance of equity and debt securities, rather than operating cash flow to fund our growth capital expenditures. If we do not make sufficient cash expenditures from operating cash flow to maintain the current production levels of our oil and natural gas properties or the current operating capacity of our other capital assets, we may be unable to pay distributions at the then-current level from cash generated from operations and would therefore expect to reduce our distributions over time. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production. The following table sets forth information regarding net production of oil and natural gas on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and on a forecasted basis for the year ending December 31, 2012:


	Pro Forma		Pro Forma		Forecasted
	Year Ended		Twelve Months		Year Ending
	December 31,		Ended June 30,		December 31,
	2010		2011		2012

Annual production:
Oil (MBbl)		209		273		539
Natural gas (MMcf)		184		159		123

Total (MBoe)		240		300		560

Average net daily production:
Oil (Bbl/d)		573		749		1,474
Natural Gas (Mcf/d)		504		435		335

Total (Boe/d)		657		822		1,529

We estimate that our total oil and natural gas production for the year ending December 31, 2012 will be 1,529 Boe per day as compared to 657 Boe per day on a pro forma basis for the year ended December 31, 2010 and 822 Boe per day on a pro forma basis for the twelve months ended June 30, 2011. For the month ended June 30, 2011, our average net production was 1,248 Boe per day. The forecast reflects a 281 Boe per day production increase from our June 2011 production resulting from ongoing drilling activities and ongoing response to our existing waterflood projects. We expect to spend $8.3 million on these activities in the second half of 2011. We intend to maintain our forecasted production level of 1,529 Boe per day for the year ending December 31, 2012 with cash generated from operations.

Prices. The table below illustrates the relationship between average oil and natural gas realized sales prices and average NYMEX prices on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and our forecast for the year ending December 31, 2012:


	Pro Forma			Pro Forma			Forecasted
	Year Ended			Twelve Months			Year Ending
	December 31,			Ended June 30,			December 31,
	2010			2011			2012

Average oil sales prices:
Average daily NYMEX-WTI oil price per Bbl	$	79.61		$	89.51		$	90.00
Differential to NYMEX-WTI oil per Bbl	$	(5.46	)	$	(3.22	)	$	(4.35	)
Realized oil sales price per Bbl (excluding cash settlements of derivatives)	$	74.15		$	86.29		$	85.65
Realized oil sales price per Bbl (including cash settlements of derivatives)	$	74.31		$	83.23		$	90.64
Average natural gas sales prices:
Average daily NYMEX-Henry Hub natural gas price per MMBtu	$	4.38		$	4.20		$	4.20
Differential to NYMEX-Henry Hub natural gas per MMBtu	$	3.18		$	3.81		$	2.36
Realized natural gas sales price per Mcf(1)	$	7.56		$	8.01		$	6.56


(1)		We had no natural gas derivative contracts for the pro forma periods and assume that we will not enter into any such contracts for the year ending December 31, 2012. Realized natural gas sales price per Mcf includes the sale of natural gas liquids.

Price Differentials. Our oil production, which is predominantly “light sweet” oil, typically sells at a discount to the NYMEX-WTI price due to quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Our natural gas production has historically sold at a positive basis differential from the NYMEX-Henry Hub price primarily due to the rich Btu and liquids content of the production attributable to our operating areas. The adjustments we have made to reflect the basis differentials for our forecasted production during the year ending December 31, 2012 are

presented in the following table and shown per Bbl for oil and per Mcf for natural gas, as reflected in our reserve report as of June 30, 2011:


	Oil			Natural Gas
Operating Area	Per Bbl			Per Mcf(1)

Southern Oklahoma	$	(5.66	)	$	1.00
Northeastern Oklahoma	$	(1.63	)	$	(1.62	)
Hugoton Basin	$	(3.95	)	$	(1.20	)
Other	$	(1.60	)	$	4.38
Weighted Average	$	(4.35	)	$	2.36


(1)		Realized natural gas sales price per Mcf includes the sale of natural gas liquids.

Use of Commodity Derivative Contracts. For purposes of our forecast, we have assumed that our commodity derivative contracts will cover 240 MBbl, or approximately 44%, of our forecasted total oil production of 539 MBbl for the year ending December 31, 2012. Our commodity derivative contracts consist of swap and collar agreements based upon NYMEX-WTI prices. The table below shows the volumes and prices covered by the commodity derivative contracts for the year ending December 31, 2012. For purposes of our forecast, we have assumed that we will not enter into natural gas derivative contracts or additional oil derivative contracts during the forecast period, although we may do so on an opportunistic basis if market conditions are favorable.


	Swaps					Collars
				Weighted					Weighted		Weighted
				Average					Average		Average
	Bbl			Price		Bbl			Floor Price		Ceiling Price

Oil:
January—December 2012		168,000		$	101.83		72,000		$	100.00	$	117.00
% of forecasted oil production		31.15	%				13.35	%

Operating Revenues and Realized Commodity Derivative Gains. The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2010 and the twelve months ended June 30, 2011 and on a forecasted basis for the year ending December 31, 2012:


	Pro Forma			Pro Forma			Forecasted
	Year Ended			Twelve Months			Year Ending
	December 31,			Ended June 30,			December 31,
	2010			2011			2012
	(in thousands)

Oil:
Oil revenues	$	15,516		$	23,590		$	46,195
Realized oil derivative instruments gain (loss)		(90	)		(837	)		2,707

Total	$	15,426		$	22,753		$	48,902

Natural gas:
Natural gas revenues(1)	$	1,392		$	1,273		$	804


(1)		We had no natural gas derivative contracts for the pro forma periods and assume that we will not enter into any such contracts for the year ending December 31, 2012. Realized natural gas sales price per Mcf includes the sale of natural gas liquids.


	Pro Forma			Pro Forma			Forecasted
	Year Ended			Twelve Months			Year Ending
	December 31,			Ended June 30,			December 31,
	2010			2011			2012
	(in thousands)

Total:
Operating revenues	$	16,908		$	24,863		$	46,999
Commodity derivative instruments gain (loss)		(90	)		(837	)		2,707

Operating revenue and realized commodity derivative instruments gains	$	16,818		$	24,026		$	49,706

Capital Expenditures and Expenses

Capital Expenditures. Our estimated maintenance capital expenditures for the year ending December 31, 2012 of $6.0 million represent our estimate of the average annual maintenance capital expenditures necessary to maintain our production through December 31, 2015 based on the forecasted production level of 1,529 Boe per day for the year ending December 31, 2012.

We anticipate replacing declining production and reserves through the ongoing response to waterflooding, drilling and completing of development wells in our waterflood properties and through the acquisition of producing and non-producing oil and natural gas properties from affiliates of our general partner and from third parties. To achieve and maintain our forecasted production levels during the forecast period, we estimate that we will drill 8 gross (5 net) wells during the forecast period and spend additional maintenance capital on workovers, recompletions and other field related activities at an aggregate net cost of approximately $6.0 million. Although we may make acquisitions during the year ending December 31, 2012, our forecast period does not reflect any acquisitions because we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements.

Lease Operating Expenses. The following table summarizes lease operating expenses on an aggregate basis and on a per Boe basis for the year ended December 31, 2010, pro forma, the twelve months ended June 30, 2011, pro forma, and on a forecasted basis for the year ending December 31, 2012:


	Pro Forma		Pro Forma		Forecasted
	Year Ended		Twelve Months		Year Ending
	December 31,		Ended June 30,		December 31,
	2010		2011		2012

Lease operating expenses (in thousands)	$	4,788	$	5,734	$	8,080
Lease operating expenses (per Boe)	$	19.95	$	19.11	$	14.43

We estimate that our lease operating expenses for the year ending December 31, 2012 will be approximately $8.1 million. On a pro forma basis, for the year ended December 31, 2010 and the twelve months ended June 30, 2011, lease operating expenses were $4.8 million and $5.7 million, respectively. The increase in forecasted lease operating expenses is primarily a result of increased drilling activity and production. The decrease in lease operating expenses per Boe is a result of the projected increase in production. Lease operating expenses also include ad valorem taxes, which are generally tied to the valuation of the oil and natural gas properties. These valuations

are generally correlated to revenues, excluding the effects of our commodity derivative contracts. As a result, we forecast our ad valorem taxes as a percent of revenues, excluding the effects of commodity derivative contracts.

Production Taxes. The following table summarizes production taxes before the effects of our commodity derivative contracts on a pro forma basis for the year ended December 31, 2010, the twelve months ended June 30, 2011 and on a forecasted basis for the year ending December 31, 2012:


	Pro Forma			Pro Forma			Forecasted
	Year Ended			Twelve Months			Year Ending
	December 31,			Ended June 30,			December 31,
	2010			2011			2012
	(in thousands)

Oil and natural gas revenues, excluding the effect of our commodity derivative contracts	$	16,908		$	24,863		$	46,999
Production taxes	$	741		$	1,009		$	2,364
Production taxes as a percentage of revenue		4.38	%		4.05	%		5.03	%

Our production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Additionally, production tax rates vary by state, and as revenues by state vary, our production taxes will increase or decrease. The State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties, and an excise tax of 0.095%. A portion of our wells in the State of Oklahoma currently receive a reduced production tax rate due to the Enhanced Recovery Project Gross Production Tax Exemption. The State of Colorado currently imposes a 1.0% production tax for oil properties.

General and Administrative Expenses. At the closing of this offering, we will enter into a services agreement with Mid-Con Energy Operating with respect to all general and administrative expenses and costs it incurs on our general partner’s and our behalf, including $3.0 million of incremental annual expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NASDAQ Global Market; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and director and officer compensation. Under the services agreement, Mid-Con Energy Operating will be reimbursed for all general and administrative expenses allocated to us under the services agreement.

Depreciation, Depletion and Amortization Expense. Based on our reserve report as of June 30, 2011, we estimate that our depreciation, depletion and amortization expense for the year ending December 31, 2012 will be approximately $9.0 million, as compared to $3.3 million and $3.8 million on a pro forma basis for the year ending December 31, 2010 and the twelve months ended June 30, 2011, respectively. The forecasted increase in the depletion of our oil and natural gas properties is primarily based on the forecasted increase in our production. Our capitalized costs are calculated using the successful efforts method of accounting. For a detailed description of the successful efforts method of accounting, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates.”

Cash Interest Expense. We estimate that at the closing of this offering we will borrow approximately $30.0 million in revolving debt under our new $ million credit facility. We estimate that the borrowings will bear interest at a weighted average rate of approximately 4.0%. Based on these assumptions, we estimate that our cash interest expense for the year ending December 31, 2012 will be $1.2 million as compared to $1.2 million on a pro forma basis for both the year ended December 31, 2010 and the twelve months ended June 30, 2011.

We expect that our new credit facility will contain financial covenants that require us to maintain a leverage ratio of not more than to 1.0x and a current ratio of not less than to 1.0x. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility” for additional detail regarding the covenants and restrictive provisions to be included in our new credit facility. We expect that the new credit facility will not require any cash expenditures on our part that would affect our cash available for distribution other than cash interest expense.

Regulatory, Industry and Economic Factors

Our forecast for the year ending December 31, 2012 is based on the following significant assumptions related to regulatory, industry and economic factors:


	•	There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or any interpretation of existing regulations, that will be materially adverse to our business;

	•	There will not be any material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;

	•	All supplies and commodities necessary for production and sufficient transportation will be readily available;

	•	There will not be any major adverse change in commodity prices or the energy industry in general;

	•	There will not be any material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events, including any events that could lead to force majeure under any of our marketing agreements;

	•	There will not be any adverse change in the markets in which we operate resulting from supply or production disruptions, reduced demand for our product or significant changes in the market prices for our product; and

	•	Market, insurance, regulatory and overall economic conditions will not change substantially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay cash distributions to our unitholders is a function of two primary variables: (i) production volumes; and (ii) commodity prices. In the tables below, we illustrate the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the minimum quarterly distributions on our outstanding common units and subordinated units for the year ending December 31, 2012.

Production Volume Changes

The following table shows estimated Adjusted EBITDA under production levels of 90%, 100% and 110% of the production level we have forecasted for the year ending December 31, 2012. The

estimated Adjusted EBITDA amounts shown below are based on the assumptions used in our forecast.


	Percentage of Forecasted
	Net Production
	90%		100%		110%
	(in thousands, except per unit amounts)

Forecasted net production:
Oil (MBbl)		485		539		593
Natural gas (MMcf)		110		123		135

Total (MBoe)		504		560		616
Oil (Bbl/d)		1,326		1,474		1,621
Natural gas (Mcf/d))		301		335		368

Total (Boe/d)		1,376		1,529		1,682
Forecasted prices:
NYMEX-WTI oil price (per Bbl)	$	90.00	$	90.00	$	90.00
Realized oil price (per Bbl) (excluding derivatives)	$	85.65	$	85.65	$	85.65
Realized oil price (per Bbl) (including derivatives)	$	91.23	$	90.67	$	90.21
NYMEX-Henry Hub natural gas price (per MMBtu)	$	4.20	$	4.20	$	4.20
Realized natural gas price (per Mcf)(1)(2)	$	6.56	$	6.56	$	6.56
Forecasted Adjusted EBITDA projection:
Operating revenue	$	42,299	$	46,999	$	51,699
Realized derivative gains (losses)		2,707		2,707		2,707

Total revenue including realized derivative gains (losses)	$	45,006	$	49,706	$	54,406
Lease operating expenses(3)		7,272		8,080		8,888
Production taxes		2,128		2,364		2,600
General and administrative expenses		4,000		4,000		4,000

Estimated Adjusted EBITDA	$	31,606	$	35,262	$	38,918


(1)		Realized natural gas sales price per Mcf includes the sale of natural gas liquids.

(2)		We assume that we will not enter into any natural gas derivative contracts for the year ending December 31, 2012.

(3)		The calculation of lease operating expenses includes ad valorem taxes.

Commodity Price Changes

The following table shows estimated Adjusted EBITDA under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the year ending December 31, 2012. For the year ending December 31, 2012, we have assumed that commodity derivative contracts will cover 240 MBoe, or approximately 44% of our estimated total oil production from proved reserves for the year ending December 31, 2012, at a weighted average floor price of $101.28 per Bbl of oil. In addition, the estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity

prices that take into account assumptions based on our average historical NYMEX commodity price differentials as set forth in our June 30, 2011 reserve report. We have assumed no changes in our production based on changes in prices. The estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices.


	(in thousands, except per unit amounts)

NYMEX-WTI oil price (per Bbl):	$	70.00	$	80.00	$	90.00	$	100.00	$	110.00
NYMEX-Henry Hub natural gas price (per MMBtu):	$	3.20	$	3.70	$	4.20	$	4.70	$	5.20
Forecasted net production:
Oil (MBbl)		539		539		539		539		539
Natural gas (MMcf)		123		123		123		123		123

Total (MBoe)		560		560		560		560		560
Oil (Bbl/d)		1,474		1,474		1,474		1,474		1,474
Natural gas (Mcf/d)		335		335		335		335		335

Total (Boe/d)		1,529		1,529		1,529		1,529		1,529
Forecasted prices:
NYMEX-WTI oil price (per Bbl)	$	70.00	$	80.00	$	90.00	$	100.00	$	110.00
Realized oil price (per Bbl) (excluding derivatives)	$	65.65	$	75.65	$	85.65	$	95.65	$	105.65
Realized oil price (per Bbl) (including derivatives)	$	79.57	$	85.12	$	90.67	$	96.22	$	101.77
NYMEX-Henry Hub natural gas price (per MMBtu)	$	3.20	$	3.70	$	4.20	$	4.70	$	5.20
Realized natural gas price (per Mcf)(1)(2)	$	5.56	$	6.06	$	6.56	$	7.06	$	7.56
Forecasted Adjusted EBITDA projection:
Operating revenue	$	36,089	$	41,544	$	46,999	$	52,454	$	57,908
Realized derivative gains (losses)		7,507		5,107		2,707		307		(2,093	)

Total revenue including realized derivative gains (losses)		43,597		46,651		49,706		52,761		55,816
Lease operating expenses(3)		8,080		8,080		8,080		8,080		8,080
Production taxes		1,815		2,090		2,364		2,638		2,913
General and administrative expenses		4,000		4,000		4,000		4,000		4,000

Estimated Adjusted EBITDA	$	29,701	$	32,482	$	35,262	$	38,042	$	40,823


(1)		Realized natural gas sales price per Mcf includes the sale of natural gas liquids.

(2)		We assume that we will not enter into any natural gas derivative contracts for the year ending December 31, 2012.

(3)		The calculation of lease operating expenses includes ad valorem taxes.

If NYMEX oil and natural gas prices decline, our estimated Adjusted EBITDA would not decline proportionately for two reasons: (1) the effects of our commodity derivative contracts; and (2) production taxes, which are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts, and which decrease as commodity prices decline. Furthermore, we have assumed no decline in estimated production or oil and natural gas operating costs during the year ending December 31, 2012. However, over the long-term, a sustained decline in oil and natural gas prices would likely lead to a decline in production and oil and natural gas operating costs, as well as a reduction in our realized oil and natural gas prices. Therefore, the foregoing table is not illustrative of all of the potential effects of changes in commodity prices for periods subsequent to December 31, 2012.

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO
CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash to unitholders of record on the applicable record date. We will prorate the minimum quarterly distribution payable for the period from the closing of this offering through December 31, 2011, based on the actual length of that period.

Definition of Available Cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:


	•	less , the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

	•	provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

	•	comply with applicable law, any of our debt instruments or other agreements; or

	•	provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

	•	plus , if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to distribute to the holders of our common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $ per unit, or $ per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution or any amount on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our

partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility” for a discussion of the restrictions to be included in our credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

As of the date of this offering, our general partner will be entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. Our general partner’s 2.0% interest in us is represented by general partner units for allocation and distribution purposes. At the consummation of this offering, our general partner’s 2.0% interest in us will be represented by general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest. Our general partner’s initial 2.0% interest in our distributions will be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to the Contributing Parties upon expiration of the underwriters’ option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its 2.0% general partner interest.

Our general partner will hold incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined below) in excess of $ per unit per quarter. The maximum distribution of 25% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. Upon the closing of this offering, Yorktown will hold non-voting member interests in our general partner that will entitle them to receive % of the distributions with respect to the incentive distribution rights and any common units issued to our general partner in connection with a reset of the incentive distribution rights, in each case.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

Operating surplus for any period consists of:


	•	$ million (as described below); plus

	•	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:


	•	borrowings (including sales of debt securities) that are not working capital borrowings;

	•	sales of equity interests;

	•	sales or other dispositions of assets outside the ordinary course of business;

	•	capital contributions received;

	•	corporate reorganizations or restructurings; and


	•	cash receipts from the termination of a commodity or interest rate hedge prior to its specified termination date; provided that such cash receipts shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus


	•	working capital borrowings made after the end of the period but on or before the date of determination of operating surplus for the period; plus

	•	cash distributions paid on equity issued (including incremental distributions on incentive distribution rights), other than equity issued on the closing date of this offering, to finance all or a portion of the construction, replacement, acquisition or improvement of a capital improvement or replacement of a capital asset (such as reserves or equipment) in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or the replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is disposed of or abandoned; plus

	•	cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above, in each case, in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or the replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is disposed of or abandoned; less

	•	all of our operating expenditures (as described below) after the closing of this offering and the completion of the transactions described in “Prospectus Summary—Formation Transactions and Partnership Structure;” less

	•	the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

	•	all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

	•	any loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $ million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including (as described above) certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working

capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner (including expenses incurred under the services agreement with Mid-Con Energy Operating), payments made in the ordinary course of business under interest rate and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments (except as otherwise provided in our partnership agreement) and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:


	•	repayment of working capital borrowings previously deducted from operating surplus pursuant to the provision described in the penultimate bullet point of the description of operating surplus above when such repayment actually occurs;

	•	payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

	•	growth capital expenditures;

	•	actual maintenance capital expenditures (as discussed in further detail below);

	•	investment capital expenditures;

	•	payment of transaction expenses relating to interim capital transactions;

	•	distributions to our partners (including distributions in respect of our incentive distribution rights);

	•	repurchases of equity interests except to fund obligations under employee benefit plans; or

	•	any other payments made in connection with this offering that are described under “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):


	•	borrowings (including sales of debt securities) other than working capital borrowings;

	•	sales of our equity interests;

	•	sales or other dispositions of assets outside the ordinary course of business;

	•	capital contributions received; and

	•	corporate reorganizations and restructurings.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the

quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes up to $ million, which does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from interim capital transactions that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but growth capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production levels and asset base, including over the long term. We expect that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of any replacement asset that is paid in respect of the period from such financing until the earlier to occur of the date that any such construction, replacement, acquisition or improvement of a capital improvement or construction replacement, acquisition or improvement of a capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is disposed of or abandoned. Plugging and abandonment cost will also constitute maintenance capital expenditures. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long-term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:


	•	it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

	•	it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

	•	in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights to our general partner because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to our unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

	•	it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Growth capital expenditures are those capital expenditures that we expect will increase our production levels and asset base over the long-term. Examples of growth capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase our production levels and asset base over the long-term. Growth capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement begins producing in paying quantities or is placed into service, as applicable, or the date that it is disposed of or abandoned. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor growth capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of the maintenance of our asset base, but which are not expected to expand our asset base for more than the short term.

As described above, neither investment capital expenditures nor growth capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) in respect of the period that begins on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement and ending on the earlier to occur of the date any such capital asset begins

producing in paying quantities or is placed into service, as applicable, and the date that it is disposed of or abandoned, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or growth capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or growth capital expenditure by our general partner’s board of directors.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Definition of Subordination Period

The subordination period will begin upon the date of this offering and will extend until the first business day of any quarter beginning after , 2014 that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on each of the outstanding common units, subordinated units and general partner units on a fully diluted basis during those periods; and

	•	there are no arrearages in the payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs on or after , 2012:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $ (125.0% of


		the annualized minimum quarterly distribution) for the immediately preceding four-quarter period;


	•	the adjusted operating surplus (as defined below) generated during the immediately preceding four-quarter period equaled or exceeded the sum of $ (125.0% of the annualized minimum quarterly distribution) on each of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis;

	•	the minimum quarterly distribution was actually paid on each outstanding common and subordinated unit and on our general partner’s 2.0% interest in each quarter of that four-quarter period; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period Upon Removal of Our General Partner

In addition, if the unitholders remove our general partner other than for cause:


	•	the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner; and

	•	if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in the distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus is calculated using estimated maintenance capital expenditures rather than actual maintenance capital expenditures and, to the extent the estimated amount is less than the actual amount, the cash generated from operations during that period would be less than the adjusted operating surplus for that period. Adjusted operating surplus for any period consists of:


	•	operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus”); less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

	•	any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a


		reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	third , 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter , in the manner described in “—General Partner Interest and Incentive Distribution Rights.”

The preceding discussion is based on the assumption that we do not issue any additional classes of equity securities and that our general partner maintains its 2.0% general partner interest in us.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	first , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter , in the manner described in “—General Partner Interest and Incentive Distribution Rights.”

The preceding discussion is based on the assumptions that we do not issue any additional classes of equity securities and that our general partner maintains its 2.0% general partner interest in us.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for general partner units to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units separate from its general partner interest, the issuance of common units to the Contributing Parties upon expiration of the underwriters’ option to purchase additional common units, the issuance of common units upon conversion of outstanding

subordinated units or the issuance of common units in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash, and our general partner may fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13% and 23%, in each case, not including distributions paid to the general partner on its 2.0% general partner interest) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Upon the closing of this offering, our general partner will hold all of our incentive distribution rights and may transfer these rights separate from its general partner interest, which is subject to restrictions on its transfer in our partnership agreement. Yorktown will hold non-voting member interests in our general partner that will entitle it to receive % of the distributions with respect to the incentive distribution rights and any common units issued to our general partner in connection with a reset of the incentive distribution rights, in each case, owned by our general partner.

The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:


	•	we have distributed available cash from operating surplus to the unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution to the common unitholders;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:


	•	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

	•	second , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”); and

	•	thereafter , 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner assume that there are no arrearages on common units, that our general partner has contributed any additional capital necessary to

maintain its 2.0% general partner interest and that our general partner has not transferred its incentive distribution rights.


		Marginal Percentage Interest in Distributions
					General Partner
	Total Quarterly				General			Incentive
	Distribution per Unit				Partner			Distribution
	Target Amount	Unitholders			Interest			Rights

Minimum Quarterly Distribution	$		98.0	%		2.0	%
First Target Distribution	above $ up to $		98.0	%		2.0	%
Second Target Distribution	above $ up to $		85.0	%		2.0	%		13.0	%
Thereafter	above $		75.0	%		2.0	%		23.0	%

Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. The right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us at the same level as existed immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior

to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each quarter in that two-quarter period.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:


	•	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

	•	second , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount equal to 125% of the reset minimum quarterly distribution for that quarter;

	•	thereafter , 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $ .


			Marginal Percentage
			Interest in Distributions
	Quarterly					2.0%
	Distribution					General			Incentive			Quarterly Distribution
	per Unit					Partner			Distribution			per Unit Following
	Prior to Reset		Unitholders			Interest			Rights			Hypothetical Reset

Minimum Quarterly Distribution	$			98.0	%		2.0	%		—		$
First Target Distribution	above $	up to $		98.0	%		2.0	%		—		above $		up to $	(1	)
Second Target Distribution	above $	up to $		85.0	%		2.0	%		13	%	above $	(1)	up to $	(2	)
Thereafter	above $			75.0	%		2.0	%		23	%	above $


(1)		This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(2)		This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $ for the two quarters prior to the reset.

Cash Distributions to General

Cash

Partner and its Affiliate Prior to Reset

Distributions to

2.0%

Common

General

Incentive

Quarterly Distribution per

Unitholders

Common

Partner

Distribution

Total

Unit Prior to Reset

Prior to Reset

Units

Interest

Rights

Total

Distribution

Minimum Quarterly Distribution

—

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

Thereafter

above $

—

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of the incentive distribution rights held by our general partner, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $ . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of the incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $ , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $

Cash Distributions to General

Cash

Partner After Reset

Quarterly

Distributions to

2.0%

Distribution

Common

General

Incentive

per Unit

Unitholders

Common

Partner

Distribution

Total

After Reset

Units

Interest

Rights

Total

Distribution

Minimum Quarterly Distribution

—

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

—

Thereafter

above $

—

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:


	•	first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available


		cash from capital surplus equal to the initial public offering price per common unit in this offering;


	•	second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	thereafter , we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumption that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 75.0% being paid to the holders of units and 25.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and the target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the target distribution levels;

	•	the unrecovered initial unit price, as described below;

	•	the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution; and

	•	the number of subordinated units and the number of general partner units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units and general partner units using the same ratio applied to the common units.

In addition, as a result of a change in law or interpretation thereof, if we or our subsidiary is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation) and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive the price paid for the common units issued in this offering, less any prior distributions of capital surplus in respect of common units issued in this offering, which we refer to as the “unrecovered initial unit price,” plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights held by our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	first , to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

	•	third , 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and


	•	fourth , 98.0% to all unitholders, pro rata, and 2.0% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to the general partner, for each quarter of our existence;

	•	fifth , 85.0% to all unitholders, pro rata, and 15.0% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence; and

	•	thereafter , 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

If our liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and the unitholders in the following manner:


	•	first , 98.0% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	second , 98.0% to the holders of common units, in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter , 100% to our general partner.

If our liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate

any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

We were formed in July 2011 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor, which consist of the consolidated historical financial statements of Mid-Con Energy Corporation through June 30, 2009 and the combined historical financial statements of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, thereafter. The following table presents selected historical financial data of our predecessor and selected pro forma financial data of Mid-Con Energy Partners, LP as of the dates and for the periods indicated. The selected historical financial data as of December 31, 2009 and 2010 and for the years ended June 30, 2008 and 2009, the six months ended December 31, 2009 and the year ended December 31, 2010 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The selected historical financial data for the years ended June 30, 2006 and 2007 are derived from audited historical financial statements of our predecessor not included herein. The selected historical financial data as of June 30, 2011 and for the six months ended June 30, 2010 and 2011 are derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.

The selected unaudited pro forma financial data as of June 30, 2011 and for the six months ended June 30, 2011 and the year ended December 31, 2010 are derived from the unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:


	•	the sale by Mid-Con Energy I, LLC and Mid-Con Energy II, LLC of certain oil and natural gas properties representing approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011, and certain subsidiaries that do not own oil and natural gas reserves, including Mid-Con Energy Operating, to the Mid-Con Affiliates for aggregate consideration of $7.5 million;

	•	the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC with our wholly owned subsidiary in exchange for an aggregate of common units, subordinated units and $ million in cash;

	•	the issuance to our general partner of general partner units, representing a 2.0% general partner interest in us, and the incentive distribution rights;

	•	the issuance and sale by us to the public of common units in this offering and the application of the net proceeds as described in “Use of Proceeds;” and

	•	our borrowing of approximately $ million under our new credit facility and the application of the proceeds as described in “Use of Proceeds.”

You should read the following table in conjunction with “Prospectus Summary—Formation Transactions and Partnership Structure,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of our predecessor and the unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP and the notes thereto included elsewhere in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed

financial statements include more detailed information regarding the basis of presentation for the following information.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.


													Mid-Con Energy I, LLC and												Mid-Con Energy
													Mid-Con Energy II, LLC												Partners, LP
													(combined)												Pro Forma
	Mid-Con Energy Corporation												Six Months			Year			Six Months						Year			Six Months
	(consolidated)												Ended			Ended			Ended						Ended			Ended
	Year Ended June 30,												December 31,			December 31,			June 30,						December 31,			June 30,
Statement of Operations Data:	2006			2007			2008			2009			2009			2010			2010			2011			2010			2011
																			(unaudited)			(unaudited)			(unaudited)			(unaudited)
	(in thousands)
Revenues:
Oil sales	$	5,569		$	6,944		$	13,667		$	10,246		$	5,729		$	16,853		$	7,482		$	15,609		$	15,516		$	14,888
Natural gas sales		51			64			618			2,172			743			1,418			803			657			1,392			657
Realized loss on derivatives, net		(165	)		558			(804	)		(669	)		(350	)		(90	)		(91	)		(714	)		(90	)		(714	)
Unrealized gain (loss) on derivatives, net		(294	)		45			(2,035	)		1,679			(147	)		(707	)		545			1,046			(707	)		984

Total revenues	$	5,161		$	7,611		$	11,446		$	13,428		$	5,975		$	17,474		$	8,739		$	16,598		$	16,111		$	15,815

Operating costs and expenses:
Lease operating expenses		2,252			3,429			5,005			5,369			2,431			6,237			3,038			3,550			4,788			2,967
Oil and gas production taxes		407			478			946			631			269			822			384			655			741			609
Dry holes and abandonments of unproved properties		539			220			—			—			—			1,418			44			772			514			772
Geological and geophysical		146			342			1,296			507			979			394			287			58			—			—
Depreciation, depletion and amortization		982			1,047			1,786			2,802			2,503			6,217			3,629			2,419			3,277			2,081
Accretion of discount on asset retirement obligations		2			35			56			78			58			127			64			32			63			32
General and administrative		1,391			1,805			1,871			1,767			704			982			587			476			982			476
Impairment of proved oil and gas properties		276			—			—			—			7,785			1,831			—			—			1,234			—

Total operating costs and expenses		5,995			7,356			10,960			11,154			14,729			18,028			8,033			7,962			11,599			6,937

Income (loss) from operations		(834	)		255			486			2,274			(8,754	)		(554	)		706			8,636			4,512			8,878

Other income (expenses):
Interest income and other		63			126			115			119			35			218			151			62			126			4
Interest expense		(24	)		(11	)		(3	)		(93	)		(2	)		(98	)		(17	)		(237	)		(1,200	)		(600	)
Gain on sale of assets		—			—			—			—			—			354			353			1,209			—			—
Other revenue and expenses, net		138			439			108			298			118			847			299			576			—			—
Income tax expense—current		—			—			—			(625	)		—			—			—			—
Income tax (expense) benefit—deferred		379			(153	)		(194	)		686			—			—			—			—			—			—

Net income (loss)	$	(278	)	$	656		$	512		$	2,659		$	(8,603	)	$	767		$	1,492		$	10,246		$	3,438		$	8,282

Net income per limited partner unit (basic and diluted)																									$			$

Weighted average number of limited partner units outstanding (basic and diluted)


													Mid-Con Energy I, LLC and												Mid-Con Energy
													Mid-Con Energy II, LLC												Partners, LP
													(combined)												Pro Forma
	Mid-Con Energy Corporation												Six Months			Year			Six Months						Year		Six Months
	(consolidated)												Ended			Ended			Ended						Ended		Ended
	Year Ended June 30,												December 31,			December 31,			June 30,						December 31,		June 30,
	2006			2007			2008			2009			2009			2010			2010			2011			2010		2011
																			(unaudited)			(unaudited)			(unaudited)		(unaudited)
	(in thousands)
Other Financial Data:
Adjusted EBITDA							$	4,471		$	3,773		$	1,857		$	10,593		$	4,197		$	11,389		$	10,307	$	10,779
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	(282	)	$	2,052		$	4,221		$	10,935		$	(14	)	$	11,798		$	6,685		$	5,192
Investing activities		(5,599	)		(11,143	)		(7,646	)		(12,448	)		(4,039	)		(22,726	)		(8,284	)		(13,351	)
Financing activities		4,918			9,980			147			4,841			(1,164	)		10,387			1,058			8,377


	Mid-Con Energy I, LLC and							Mid-Con
	Mid-Con Energy II, LLC							Energy
	(combined)							Partners, LP
	(in thousands)							Pro Forma
	As of December 31,					As of June 30,		As of June 30,
Balance Sheet Data:	2009		2010			2011		2011
						(unaudited)		(unaudited)

Working capital(1)	$	2,420	$	(1,256	)	$	4,383	$	4,383
Total assets		40,999		57,059			72,582		72,342
Total debt		337		5,513			13,310		30,000
Partners’ capital		37,282		43,264			56,290		39,360


(1)		For 2010, excludes $5.3 million of current maturities under our predecessor’s credit facilities. The maturity date for these facilities was subsequently extended to December 2013.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the “Selected Historical and Pro Forma Financial Data” and the accompanying financial statement and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure” and in the unaudited pro forma condensed financial statements included elsewhere in this prospectus.

Overview

As of June 30, 2011, our total estimated proved reserves were approximately 7.9 MMBoe, of which approximately 98% were oil and 71% were proved developed, both on a Boe basis. As of June 30, 2011, we operated 98% of our properties and 92% were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended June 30, 2011 was approximately 1,248 Boe per day and our total estimated proved reserves had a reserve-to-production ratio of approximately 17 years. Our management team developed approximately two-thirds of our total reserves through new waterflood projects.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil properties, including:


	•	Oil and natural gas production volumes;

	•	Realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

	•	Lease operating expenses; and

	•	Adjusted EBITDA.

Production Volumes

Production volumes directly impact our results of operations. For more information about our production volumes, please read “—Historical Financial and Operating Data.”

The following table presents production volumes for our properties for the years ended June 30, 2008 and 2009, for the six months ended December 31, 2009, for the year ended December 31, 2010, and for the six months ended June 30, 2011.


					Six Months				Six Months
					Ended		Year Ended		Ended
	Year Ended June 30,				December 31,		December 31,		June 30,
	2008		2009		2009		2010		2011

Oil (MBbls)		145		153		87		228		167
Natural Gas (MMcf)		86		341		140		191		79

Total (MBoe)		159		210		110		260		180

Average Net Production (Boe/d)		437		575		602		710		986

Realized Prices on the Sale of Oil

Factors Affecting the Sales Price of Oil. We currently market approximately 89% of our oil production to one party, Sunoco Logistics, under renewable six-month marketing contracts. We sell the remainder of our production to several other purchasers based on regional pricing. From time to time, we compare the pricing under our current Sunoco Logistics contract to offers from other purchasers to determine the best price in the relevant market. The price of oil generally is determined by factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. Oil prices are also heavily influenced by product quality and location relative to consuming and refining markets.

Oil Prices. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that oil can differ in its molecular makeup, which plays an important part in its refining and subsequent sale as petroleum products. The two primary characteristics that account for quality differentials are: (1) the oil’s American Petroleum Institute, or API, gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content or “sweet” oil is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil or “sour” oil. The oil produced from our properties is predominately “light sweet” oil. We sell our oil at the NYMEX-WTI price, less a differential for quality and transportation, depending primarily on location and purchaser.

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced oil’s proximity to the major trading, transportation and refining markets to which it is ultimately delivered. Oil that is produced close to major trading, transportation and refining markets, such as Cushing, Oklahoma, command a higher price because of lower transportation costs as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major trading, transportation and refining markets normally realizes a higher price ( i.e. , a lower location differential to NYMEX-WTI).

Commodity Derivative Contracts. To better manage oil price fluctuations and achieve more predictable cash flow, we intend to maintain a portfolio covering approximately 50% to 80% of our estimated oil production from proved reserves over a three-to-five year period on a rolling basis. We may from time to time hedge more or less than this approximate range. These instruments limit our exposure to declines in prices, but also limit our upside if prices increase.

For the years ending December 31, 2011, 2012 and 2013, we have commodity derivative contracts covering approximately 43%, 44% and 24%, respectively, of our estimated oil production from proved reservesas of June 30, 2011. All of our derivative contracts for 2012 and 2013

contain price floors of at least $100 per Boe. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”

The following table reflects, with respect to our existing commodity derivative contracts, the volumes our production covered by commodity derivative contracts and the average prices at which the production will be hedged:


	Year Ended December 31,
	2011		2012		2013

Oil Derivative Contracts:
Swap Contracts:
Volume (Bbls/d)		559		460		197
Weighted Average NYMEX-WTI price per Bbl	$	91.22		$101.83		$105.80

Put/Call Option Contracts (Collars):
Volume (Bbls/d)				197		197
Weighted Average NYMEX-WTI price per Bbl				$100 – $117		$100 – $111

Lease Operating Expenses

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative costs, but do include ad valorem taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses during the time which they are performed.

A majority of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil, separation and treatment of water produced in connection with our oil production, and re-injection of water into the oil producing formation to maintain reservoir pressure. As these costs are driven not only by volumes of oil produced but also volumes of water produced, fields that have a high percentage of water production relative to oil production, also known as a high water cut, will experience higher power costs for each barrel of oil produced. Since a majority of our oil is produced from waterflooding, the amount of water produced will increase for a given volume of oil production over the life of these fields. In newly implemented waterflood projects, per unit lifting costs increase early in the life of the project due to production losses associated with the conversion of producing wells to water injection and the additional cost of injecting water. Once production response to injection occurs, the per unit lease operating expenses will begin to decrease as absolute costs remain relatively stable and production rates increase.

An example of decreasing per unit lease operating expenses is our Highlands Unit, where operating costs increased on an absolute basis during the twelve months ended June 30, 2011. During the same twelve month period, per unit lease operating expenses for our Highlands Unit decreased from approximately $40 per Boe to $11 per Boe as production increased due to ongoing response to waterflooding and development drilling. After a waterflood project has reached peak production, the water cut will usually increase, resulting in the production of each barrel of oil becoming more expensive until, at some point, additional production becomes uneconomic.

We typically evaluate our lease operating expenses on a per Boe basis. This allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. For mature waterflood projects, total lease operating expenses may remain relatively stable, but due to production declines, lease operating expenses will generally increase on a per Boe basis. We believe that one of our areas of core expertise lies in reducing per unit lease operating expenses for mature high water cut waterfloods. We monitor our operations to ensure that we are incurring operating costs at the optimal level relative to our production. Accordingly, we monitor our lease operating expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss):


	•	Plus


	•	income tax expense (benefit), if any;

	•	interest expense;

	•	depreciation, depletion and amortization;

	•	accretion of discount on asset retirement obligations;

	•	unrealized losses on commodity derivative contracts;

	•	impairment expenses;

	•	dry hole costs and abandonment of unproved properties; and

	•	loss on sale of assets;


	•	Less


	•	interest income;

	•	unrealized gains on commodity derivative contracts; and

	•	gain on sale of assets.


	•	The cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and

	•	Our ability to incur and service debt and fund capital expenditures.

Adjusted EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. For further discussion of the non-GAAP financial measure Adjusted EBITDA, please read “Prospectus Summary—Non-GAAP Financial Measures.”

Outlook

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. While oil prices have steadily increased since the second quarter of 2009, the outlook and timing for a worldwide economic recovery remains uncertain for the foreseeable

future. As a result, it is likely that commodity prices will continue to be volatile. Sustained periods of low prices for oil could materially and adversely affect our financial position, our results of operations, the quantities of oil reserves that we can economically produce and our access to capital.

Our business faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil production from a given well or formation decreases. Although our waterflood operations tend to restore reservoir pressure and production, once a waterflood is fully effected, production, once again, begins to decline. Our future growth will depend on our ability to continue to add reserves in excess of our production. We plan to maintain our focus primarily on adding reserves through improving the economics of producing oil from our existing fields and, secondarily, through acquisitions of additional proved reserves. We expect that acquisition opportunities may come from the Mid-Con Affiliates and also from unrelated third parties. Our ability to add reserves through exploitation projects and acquisitions is dependent upon many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and close acquisitions.

Historical Financial and Operating Data

The following table sets forth selected historical combined financial and operating data of our predecessor and unaudited pro forma financial and operating data for the periods presented. The following table should be read in conjunction with “Selected Historical and Pro Forma Financial Data.”


							Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (combined)
	Mid-Con Energy Corporation						Six Months			Year			Six Months
	(consolidated)						Ended			Ended			Ended
	Year Ended June 30,						December 31,			December 31,			June 30,
	2008			2009			2009			2010			2010			2011
													(unaudited)
Revenues (in thousands):
Oil sales	$	13,667		$	10,246		$	5,729		$	16,853		$	7,482		$	15,609
Natural gas sales		618			2,172			743			1,418			803			657
Realized gain (loss) on derivatives, net		(804	)		(669	)		(350	)		(90	)		(91	)		(714	)
Unrealized gain (loss) on derivatives, net		(2,035	)		1,679			(147	)		(707	)		545			1,046

Total Revenues	$	11,446		$	13,428		$	5,975		$	17,474		$	8,739		$	16,598

Expenses (in thousands):
Lease operating expense	$	5,005		$	5,369		$	2,431		$	6,237		$	3,038		$	3,550
Oil and gas production taxes		946			631			269			822			384			655
Dry holes and abandonments of unproved properties		—			—			—			1,418			44			772
Depreciation, depletion and amortization(1)		1,653			2,612			2,308			5,570			3,118			2,080
General and administrative		1,871			1,767			704			982			587			476
Impairment of proved oil and gas properties		—			—			7,785			1,831			—			—
Interest expense		3			93			2			98			17			237
Production:
Oil (MBbls)		145			153			87			228			104			167
Natural gas (MMcf)		86			341			140			191			106			79
Total (MBoe)		159			210			110			260			121			180
Average net production (Boe/d)		437			575			602			710			666			986
Average sales price:
Oil (per Bbl):
Sales price	$	94.20		$	66.87		$	66.11		$	74.07		$	72.05		$	93.58
Effect of realized commodity derivative instruments	$	(5.54	)	$	(4.37	)	$	(4.04	)	$	0.40		$	(0.87	)	$	(4.28	)
Realized price	$	88.66		$	62.50		$	62.06		$	73.67		$	71.17		$	89.30
Natural gas (per Mcf):
Sales price(2)	$	7.17		$	6.37		$	5.33		$	7.44		$	7.59		$	8.28
Average unit costs per Boe:
Lease operating expenses	$	31.39		$	25.56		$	22.11		$	24.05		$	25.01		$	19.72
Oil and gas production taxes	$	5.93		$	3.00		$	2.45		$	3.17		$	3.16		$	3.64
General and administrative expenses	$	11.73		$	8.41		$	6.40		$	3.79		$	4.83		$	2.64
Depreciation, depletion and amortization	$	10.36		$	12.44		$	20.99		$	21.48		$	25.67		$	11.55


(1)		Depreciation, depletion, and amortization expenses for this table only represent the depletion expenses for the producing properties.

(2)		Natural gas sales price per Mcf includes the sale of natural gas liquids.

Results of Operations

Factors Impacting the Comparability of Our Financial Results

The comparability of our future results of operations to our historical results of operations and the comparability of our historical results of operations among the periods presented may be impacted by:


	•	The drilling of 35 wells in 2010 and 21 wells in 2011 on our properties in Oklahoma;

	•	Our sale to the Mid-Con Affiliates on June 30, 2011 of certain properties representing approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011, and certain subsidiaries that do not own oil and natural gas reserves, including Mid-Con Energy Operating, to the Mid-Con Affiliates for aggregate consideration of $7.5 million;

	•	Our acquisition of the War Party I and II Units for a purchase price of $7.2 million on June 30, 2011, which together represented approximately 7.2% of our total estimated proved reserves on a Boe basis as of that date;

	•	The acquisition of interests in various properties located in Oklahoma for an aggregate purchase price of approximately $6.5 million throughout the year in 2010;

	•	The unitization of the Ardmore and Twin Forks Units in January 2009 and the Highlands Unit in June 2008; and

	•	The reorganization of Mid-Con Energy Corporation into two limited liability companies in June 2009, which eliminated our corporate tax expense, and in connection therewith, the change in our fiscal year end from June 30 to December 31.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Sales Revenues. Revenues from oil and natural gas sales for the six months ended June 30, 2011 were approximately $16.3 million as compared to $8.3 million for the six months ended June 30, 2010. The increase in revenues was primarily due to an increase in daily oil production and higher sales prices during the six months ended June 30, 2011.

Our production volumes for the six months ended June 30, 2011 were 180 MBoe, or 986 Boe per day. In comparison, our production volumes for the six months ended June 30, 2010 were 121 MBoe or 666 Boe per day. The increase in production volumes was primarily due to ongoing waterflood response and the drilling programs in our Oklahoma waterflood units. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the six months ended June 30, 2011 was $93.58, compared with $72.05 for the six months ended June 30, 2010.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net gain from our commodity hedging program for the six months ended June 30, 2011 of approximately $0.3 million, which was composed of a realized loss of $0.7 million and an unrealized gain of $1.0 million. For the six months ended June 30, 2010, we recorded a net gain from our commodity hedging program of approximately $0.4 million, which was composed of a realized loss of $0.1 million and an unrealized gain of $0.5 million.

Lease Operating Expenses. Our lease operating expenses were $3.6 million for the six months ended June 30, 2011, or $19.72 per Boe, compared to $3.0 million for the six months ended June 30, 2010, or $25.01 per Boe. The increase in total lease operating expenses during the six months ended June 30, 2011 was primarily due to the increase in production and the increase in the number of wells producing. The decrease in lease operating expenses per Boe was due to the increased production for the six months ended June 30, 2011. Ad valorem taxes are also reflected in lease operating expenses. Ad valorem taxes are levied on our properties in

100

Colorado and are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts, and a percentage of production equipment value.

Production Taxes. Our production taxes were $0.7 million for the six months ended June 30, 2011, or $3.64 per Boe for an effective tax rate of 4.0%, compared to $0.4 million for the six months ended June 30, 2010, or $3.16 per Boe for an effective tax rate of 4.6%. The increase in production taxes during the six months ended June 30, 2011 was primarily due to the increase in the realized average oil sales price. The decrease in the effective tax rate is due to increased production from several of our Southern Oklahoma waterflood projects that qualify for reduced tax rates. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. Although the State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties and an excise tax of 0.095%, a portion of our wells in Oklahoma currently receive a reduced rate due to the Enhanced Recovery Project Gross Production Tax Exemption.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses for the six months ended June 30, 2011 were $2.1 million, or $11.55 per Boe produced, compared to $3.1 million, or $25.67 per Boe produced, for the six months ended June 30, 2010. The decrease in the depreciation, depletion and amortization expenses on an overall and on a per Boe produced basis was primarily due to the substantial increase in proved developed reserves estimated at June 30, 2011.

Impairment of Oil and Natural Gas Properties. There was no impairment charge for both the six months ended June 30, 2011 and 2010.

General and Administrative Expenses. Our general and administrative expenses were approximately $0.5 million for the six months ended June 30, 2011, or $2.64 per Boe produced compared to $0.6 million for the six months ended June 30, 2010 or $4.83 per Boe produced. The decrease in general and administrative expenses for the six months ended June 30, 2011 was primarily due to increased affiliate subsidiary activity resulting in the subsidiaries receiving a greater portion of the general and administrative expenses.

Interest Expense. Our interest expense for the six months ended June 30, 2011 was $0.2 million, compared to $17,000 for the six months ended June 30, 2010. The increase was due to increased borrowings on our credit facilities for capital expenditures and acquisitions.

Year Ended December 31, 2010 Compared to Six Months Ended December 31, 2009

Sales Revenues. Revenues from oil and natural gas sales for the year ended December 31, 2010 were approximately $18.3 million as compared to $6.5 million for the six months ended December 31, 2009. The increase in revenues was primarily due to an increase in oil production and an increase in the average oil and natural gas price during the twelve months ended December 31, 2010.

Our production volumes for the twelve months ended December 31, 2010 were 259 MBoe, or 710 Boe per day. In comparison, our production volumes for the six months ended December 31, 2009 were 110 MBoe or 602 Boe per day. The increase in production volumes was primarily due to the drilling programs in our waterflood units and the acquisitions of interests in various properties located in Oklahoma. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the year ended December 31, 2010 was $74.07, compared with $66.11 for the six months ended December 31, 2009.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net loss from our commodity hedging program for the year ended December 31, 2010 of approximately $0.8 million, which is composed of a realized loss of $0.1 million and an unrealized loss of $0.7 million. For the six months ended December 31, 2009, we recorded a net

101

loss from the commodity hedging program of approximately $0.5 million, which is composed of a realized loss of $0.4 million and an unrealized loss of $0.1 million.

Lease Operating Expenses. Our lease operating expenses were $6.2 million for the year ended December 31, 2010, or $24.05 per Boe, compared to $2.4 million for the six months ended December 31, 2009, or $22.11 per Boe. The increase in lease operating expenses, on both a total and per Boe basis, was primarily due to the increase in production and the increase in the number of wells drilled and used for injection during the twelve months ended December 31, 2010. Ad valorem taxes are also reflected in lease operating expenses.

Production Taxes. Our production taxes were $0.8 million for the year ended December 31, 2010, or $3.17 per Boe for an effective tax rate of 4.5%, compared to $0.3 million for the six months ended December 31, 2009, or $2.45 per Boe for an effective tax rate of 4.2%. The increase in production taxes during the year ended December 31, 2010 was primarily due to the increase in the realized average oil sales price. The increase in the effective tax rate was due to increased production from certain of our Oklahoma properties that do not qualify for reduced tax rates.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses for the year ended December 31, 2010 were $5.6 million, or $21.48 per Boe produced, compared to $2.3 million, or $20.99 per Boe produced, for the six months ended December 31, 2009. The increase per Boe produced was primarily due to the reduction of proved developed reserves on certain non-performing properties during the year ended December 31, 2010.

Impairment of Oil and Natural Gas Properties. An impairment of $1.8 million was required during the year ended December 31, 2010 due to a decline in reserve estimates for certain producing properties. An impairment expense of $7.8 million was also recorded for the six months ended December 31, 2009 due to a decline in reserve estimates for certain producing properties.

General and Administrative Expenses. Our general and administrative expenses were approximately $1.0 million for the year ended December 31, 2010, or $3.79 per Boe produced, compared to $0.7 million of general and administrative expenses for the six months ended December 31, 2009, or $6.40 per Boe produced. The decrease in general and administrative expenses per Boe in the year ended December 31, 2010 was primarily due to increased affiliate subsidiary activity resulting in the subsidiaries receiving a greater allocation of the overall general and administrative expenses.

Interest Expense. Our interest expense for the year ended December 31, 2010 was $98,000 compared to $2,000 for the six months ended December 31, 2009. The increase is attributable to an increase in borrowings from our credit facilities due to capital expenditures and acquisitions.

Six Months Ended December 31, 2009 Compared to Year Ended June 30, 2009

Sales Revenues. Revenues from oil and natural gas sales for the six months ended December 31, 2009 were approximately $6.5 million as compared to $12.4 million for the twelve months ended June 30, 2009.

Our production volumes for the six months ended December 31, 2009 were 110 MBoe or 602 Boe per day compared to 210 MBoe and 575 Boe per day for the year ended June 30, 2009. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the six months ended December 31, 2009 was $66.11 compared with $66.87 for the year ended June 30, 2009. The increase in production in Boe per day was due to an increase in oil production partially offset by a decline in natural gas production.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net loss from the commodity hedging program for the six months ended December 31, 2009 of approximately $0.5 million, which was composed of a realized loss of $0.4 million and an unrealized loss of $0.1 million. For the year ended June 30, 2009, we recorded realized net gain

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from the commodity hedging program of approximately $1.0 million, which was composed of $0.7 million of realized loss and an unrealized gain of $1.7 million.

Lease Operating Expenses. Our lease operating expenses were $2.4 million, or $22.11 per Boe produced for the six months ended December 31, 2009 compared to approximately $5.4 million, or $25.56 per Boe produced for the year ended June 30, 2009. The decrease in lease operating expenses per Boe was attributable to an increase in production.

Production Taxes. Our production taxes were $0.3 million for the six months ended December 31, 2009, or $2.45 per Boe for an effective tax rate of 4.2%, compared to $0.6 million for the year ended June 30, 2009, or $3.00 per Boe for an effective tax rate of 5.1%. The decrease in production taxes on a per unit basis during the year ended December 31, 2009 was primarily due to a decrease in the effective tax rate. The decrease in the effective tax rate was due to increased production from certain of our Oklahoma properties that qualify for reduced tax rates.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses for the six months ended December 31, 2009 were $2.3 million, or $20.99 per Boe produced, as compared to $2.6 million, or $12.44 per Boe produced, for the year ended, June 30, 2009. The increase per Boe produced for the six months ended December 31, 2009 was primarily due to a decrease in reserve estimates on a total basis for some of our non-performing properties.

Impairment of Oil and Natural Gas Properties. An impairment of $7.8 million was required during the six months ended December 31, 2009 due to a decline in reserve estimates for certain producing properties. There were no impairment charges for the year ended June 30, 2009.

General and Administrative Expenses. Our general and administrative expenses were approximately $0.7 million for the six months ended December 31, 2009, or $6.40 per Boe produced, compared to $1.8 million of general and administrative expenses for the year ended June 30, 2009 or $8.41 per Boe produced. The decrease in general and administrative expenses per Boe produced was primarily due to an increase in production.

Interest Expense. Our interest expense for the six months ended December 31, 2009 was $2,000 compared to $94,000 for the year ended June 30, 2009. The decrease is attributable to reduced debt resulting from a capital contribution during the six months ended December 31, 2009.

Year Ended June 30, 2009 Compared to Year Ended June 30, 2008

Sales Revenues. Revenues from oil and natural gas sales for the year ended June 30, 2009 were approximately $12.4 million compared to $14.3 million for the year ended June 30, 2008. The decrease in revenue was attributable to the sharp decline in oil prices beginning October 2008, offset by an increase in natural gas sales of approximately $1.6 million for the year ended June 30, 2009.

Our production volumes for the year ended June 30, 2009 were 210 MBoe, or 575 Boe per day. In comparison, the production volumes for the year ended June 30, 2008 were 159 MBoe, or 437 Boe per day. The increase in overall volumes was primarily due to the response from our Battle Springs waterflood unit in Southern Oklahoma and the increase of gas production due to the drilling of gas wells in Oklahoma. Our average sales price per barrel of oil, excluding commodity derivative contracts, for the year ended June 30, 2009 was $66.87, compared with $94.20 for the year ended June 30, 2008.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net gain from the commodity hedging program for the year ended June 30, 2009 of approximately $1.0 million, which was composed of a realized loss of $0.7 million and an unrealized gain of $1.7 million. For the year ended June 30, 2008, we recorded a net loss from

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the commodity hedging program of approximately $2.8 million, which was composed of a realized loss of approximately $0.8 million and an unrealized loss of approximately $2.0 million.

Lease Operating Expenses. Our lease operating expenses were $5.4 million for the year ended June 30, 2009, or $25.56 per Boe, compared to $5.0 million for the year ended June 30, 2008, or $31.39 per Boe. The decrease in lease operating expenses per Boe during the year ended June 30, 2009 was primarily due to an increase in production.

Production Taxes. Our production taxes were $0.6 million for the year ended June 30, 2009, or $3.00 per Boe for an effective tax rate of 5.1%, compared to $0.9 million for the year ended June 30, 2008, or $5.93 per Boe for an effective tax rate of 6.6%. The decrease in production taxes on a per unit basis during the year ended June 30, 2009 was due to a decrease in the realized average oil sales price and a decrease in the effective tax rate. The decrease in the effective tax rate was due to increased production from certain of our Oklahoma properties that qualify for reduced tax rates.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses increased to approximately $2.6 million, or $12.44 per Boe produced for the year ended June 30, 2009 compared to approximately $1.7 million, or $10.36 per Boe produced for the year ended June 30, 2008. The increase is due to an increase in production.

Impairment of Oil and Natural Gas Properties. There were no impairment charges in the years ended June 30, 2009 and 2008, respectively.

General and Administrative Expenses. Our general and administrative expenses decreased to approximately $1.8 million, or $8.41 per Boe produced, in the year ended June 30, 2009 from approximately $1.9 million, or $11.73 per Boe produced, in the year ended June 30, 2008.

Interest Expense. Our interest expense for the year ended June 30, 2009 was approximately $94,000 compared to approximately $3,000 for the year ended June 30, 2008. The increase was due to increased borrowings on our credit facilities for capital expenditures and acquisitions.

Liquidity and Capital Resources

Historically, our primary sources of liquidity and capital resources have been proceeds from capital contributions from Yorktown, bank borrowings, and cash flow from operations. Our primary uses of capital have been for the acquisition, development and drilling of waterflood units.

After the consummation of this offering, as a publicly traded partnership, we expect that our primary sources of liquidity and capital resources will be cash flow generated by operating activities and borrowings under our new credit facility that we will enter into concurrently with the closing of this offering. We also expect to be able to issue additional equity and debt securities from time to time as market conditions allow. Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement will permit our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters.

In addition, our partnership agreement permits us to borrow funds to make distributions to our unitholders. We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. For example, we plan to hedge a significant portion of our production. We generally will be required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and gas industry, we do not generally receive the proceeds

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from the sale of our hedged production until 20 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions.

Cash Flow

Net cash provided by (used in) operating activities was approximately $11.8 million, $10.9 million, $4.2 million, $5.2 million, $6.7 million and ($14,000) for the twelve months ended December 31, 2010, June 30, 2009 and June 30, 2008 and for the six months ended June 30, 2011, June 30, 2010 and December 31, 2009, respectively. Our revenues increased significantly for the year ended December 31, 2010 and for the six month period ended June 30, 2011 compared to prior periods, primarily due to increased production, favorable commodity pricing, our successful exploitation of our proved reserves, our ability to reduce our per unit operating expenses and our successful acquisition activity and, therefore, our net cash provided by operating activities increased during the same period. Cash provided by operating activities is impacted by the prices received for oil and natural gas and levels of production volumes. Our production volumes in the future will in large part be dependent upon the results of past waterflood development activities and results of future capital expenditures. Our future levels of capital expenditures may vary due to many factors, including development and drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Net cash used in investing activities was approximately $22.7 million, $12.4 million, $7.6 million, $13.3 million, $8.3 million and $4.0 million for the twelve months ended December 31, 2010, June 30, 2009, June 30, 2008 and for the six months ended June 30, 2011, June 30, 2010 and December 31, 2009, respectively. The increased amount of cash used in investing activities for the year ended December 31, 2010 and six months ended June 30, 2011 compared to corresponding twelve and six month prior periods was primarily due to the increased waterflood development activities in Southern Oklahoma, including the in-field drilling in these units and acquisition of interest in oil properties.

Net cash provided by (used in) financing activities was approximately $10.4 million, $4.8 million, $0.1 million, $8.4 million, $1.1 million and ($1.2 million) for the twelve months ended December 31, 2010, June 30, 2009 and June 30, 2008 and for the six months ended June 30, 2011, June 30, 2010 and December 31, 2009, respectively. For the year ended December 31, 2010 and the six months ended June 30, 2011, cash flow from financing activities was provided from borrowings under our credit facilities. For the year ended December 31, 2010, the cash provided by financing activities primarily related to $10.0 million of capital contributions, $5.3 million from borrowings and was used to fund a $4.7 million distribution to certain members. For the six months ended December 31, 2009, net cash provided by financing activities was used to fund a $1.5 million distribution to our members. For the twelve months ended June 30, 2009 the cash provided by financing activities primarily related to $5.0 million of capital contributions.

Working Capital

Our working capital totaled $4.4 million, ($1.3 million), and $2.4 million at June 30, 2011, December 31, 2010, and December 31, 2009, respectively. Our cash balances at June 30, 2011, December 31, 2010, and December 31, 2009 were $0.4 million, $0.2 million, and $0.8 million, respectively. The negative working capital at December 31, 2010 was directly related to accrued expenses for our drilling program and the accrued unrealized loss on our commodity derivative contracts. In addition, the working capital amount at December 31, 2010 excludes $5.3 million of current maturities under our existing credit facilities. The maturity date for these facilities was

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subsequently extended to December 2013; they will be repaid in full with proceeds from this offering.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production levels and asset base, including over the long term. The primary purpose of maintenance capital expenditures is to prevent our production from declining over time, which could result in a corresponding decline in our distributions per unit. For the twelve months ending December 31, 2012, we have estimated our maintenance capital expenditures will be approximately $6.0 million.

Growth capital expenditures are capital expenditures that we expect to increase our production levels and asset base over the long term. The primary purpose of growth capital expenditures is to acquire, develop and produce assets that will allow us to increase our production levels and asset base in a manner that is expected to be accretive to our unitholders and, as a result, increase our distributions per unit. Growth capital expenditures on existing properties may include projects such as drilling new injection wells or producing wells on our existing waterflood projects. Growth capital expenditures may also include acquisitions of additional oil and gas properties. Although we intend to make acquisitions in the future, including potential acquisitions of producing properties from the Mid-Con Affiliates, we currently have no budgeted growth capital expenditures related to acquisitions, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts.

We plan to reinvest a sufficient amount of our operating cash flow to fund our maintenance capital expenditures in order to maintain our production levels and asset base. We plan primarily to use external financing sources, including borrowings under our new credit facility and the issuance of debt and equity securities, rather than operating cash flow, to make growth capital expenditures to increase our production levels and asset base. Because our proved reserves and production are expected to decline over time, we will need to continue the development of our existing reserves and/or make acquisitions to maintain and grow our distributions to unitholders over time.

If cash flow from operations does not meet our expectations, we may reduce our level of capital expenditures, reduce distributions to our unitholders, and/or fund a portion of our capital expenditures using borrowings under our credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot be certain that budgeted capital will be available on acceptable terms or at all. The covenants in our credit facility could limit our ability to incur additional indebtedness. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to make growth capital expenditures or even fund the capital expenditures necessary to maintain our production or proved reserves.

The amount and timing of our capital expenditures are largely discretionary and within our control. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our new credit facility will exceed our planned capital expenditures and other cash requirements for the twelve months ending December 31, 2012. However, future cash flow is subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production. We

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cannot be certain that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

New Credit Facility

Concurrently with the closing of this offering, we anticipate that we will enter into a new credit facility, which we expect to be a five-year, $ million revolving credit facility with an initial borrowing base of approximately $ million. We expect the new credit facility to include typical operational and financial covenants.

We anticipate that our new credit facility will be reserve-based, and thus we will be permitted to borrow under our new credit facility in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion. We expect that our borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which will take into account our lenders’ commodity price assumptions, as adjusted for the impact of our commodity derivative contracts. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our new credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our new credit facility.

Derivative Contracts

The following table summarizes, for the periods indicated, our oil swaps and options, as of December 31, 2011 through December 31, 2013. These transactions are settled based upon the NYMEX-WTI price of oil.


		Weighted
Term	Type of Derivative	Average ($/Bbl)		Bbls/d

2011	Swaps	$	91.22		559
2012	Swaps	$	101.83		460
2012	Put/Call	$	100 – $117		197
2013	Swaps	$	105.80		197
2013	Put/Call	$	100 – $111		197

We intend to enter into commodity derivative contracts at times and on terms designed to maintain, over the long term, a portfolio covering approximately 50% to 80% of our estimated oil production from proved reserves over a three-to-five year period at any given point in time. We intend to enter into additional commodity derivative contracts in connection with material increases in our estimated production and at times when we believe market conditions or other circumstances suggest that it is prudent to do so as opposed to

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entering into commodity derivative contracts at predetermined times or on prescribed terms. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes or the duration of our hedge contracts when circumstances suggest that it is prudent to do so. These instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a commodity derivative contract is terminated prior to its expiration.

Contractual Obligations

A summary of our contractual obligations as of June 30, 2011 is provided in the following table.


	Obligations Due in Period
	(in thousands)
Contractual Obligation	2011		2012		2013		2014		2015		Thereafter		Total

Long-term debt	$	—	$	—	$	13,310	$	—	$	—	$	—	$	13,310
Interest on long-term debt(1)	$	266	$	532	$	532		—		—		—	$	1,330
Office lease	$	89	$	89		—		—		—		—	$	178

Total contractual obligations	$	355	$	621	$	13,842	$	—	$	—	$	—	$	14,818


(1)		Based upon an interest rate of 4.0% under the credit facilities at June 30, 2011.

Quantitative and Qualitative Disclosure about Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil production. Realized pricing is primarily driven by the spot market prices applicable to the prevailing price for oil. Pricing for oil has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil production depend on many factors outside of our control, such as the strength of the global economy.

To reduce the impact of fluctuations in oil prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into commodity derivative contracts with respect to a significant portion of our projected oil production through various transactions that fix the future prices received. These hedging activities are intended to manage our exposure to oil price fluctuations. We do not enter into derivative contracts for speculative trading purposes.

Swaps

In a typical commodity swap agreement we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher than the fixed price, we pay the

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difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

For a summary of the oil swaps and swap prices, related basis swap prices and resulting adjusted swap prices in place as of June 30, 2011, please read “—Liquidity and Capital Resources —Derivative Contracts.”

Collars

A collar is a combination of a put option we purchase and a call option we write. In a typical collar transaction, if the reference price, based on NYMEX quoted prices, is below the floor price, we receive an amount equal to this difference multiplied by the specified volume. If the reference price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the reference price exceeds the ceiling price, we must pay an amount equal to this difference multiplied by the specified volume.

For a summary of the oil collars in place as of June 30, 2011, please read “—Liquidity and Capital Resources—Derivative Contracts.”

Interest Rate Risk

At June 30, 2011 we had $13.3 million of debt outstanding under our existing credit facilities, with an effective interest rate of 4.0%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $53,000 on an annual basis. At the closing of this offering, we intend to enter into a new revolving credit facility, which will allow us to borrow up to $ million, at an interest rate of .

Counterparty and Customer Credit Risk

Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. We evaluate the credit standing of such counterparties by reviewing their credit rating. The counterparties to our derivative contracts currently in place are lenders under our credit facility and have investment grade ratings. We expect to enter into future derivative contracts with these or other lenders under our new credit facility whom we expect will also carry investment grade ratings.

We are also subject to credit risk due to the concentration of our revenues attributable to one significant customer, Sunoco Logistics. The inability or failure of Sunoco Logistics to meet its obligations to us or its insolvency or liquidation may adversely affect our financial results. However, Sunoco Logistics has a positive payment history and an investment grade credit rating and, as a result, we believe the credit quality of Sunoco Logistics is high.

Critical Accounting Policies and Estimates

Oil and Natural Gas Quantities

Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrated, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. The estimates of our proved reserves as of December 31, 2010 and June 30, 2011 included in this prospectus are based on reserve reports prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc. The accuracy of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that

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data, the accuracy of various economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are also a function of many assumptions, all of which could deviate significantly from actual results. For example, when the price of oil and natural gas increases, the economic life of our properties is extended, thus increasing estimated proved reserve quantities and making certain projects economically viable. Likewise, if oil and natural gas prices decrease, the properties economic life is reduced and certain projects may become uneconomic, reducing estimated proved reserved quantities. Oil and natural gas price volatility adds to the uncertainty of our reserve quantity estimates. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Industries—Oil and Gas Topic of the Accounting Standards Codification with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements. We implemented ASU 2010-03 as of December 31, 2010. Key items in the new rules include changes to the pricing used to estimate reserves whereby an unweighted average of the first-day-of-the-month price for each month within the applicable twelve-month period is used rather than a single day spot price, the use of new technology for determining reserves, the ability to include nontraditional resources in reserves and permitting disclosure of probable and possible reserves.

Successful Efforts Method of Accounting

We account for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

We evaluate the impairment of our proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flow is less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and developmental costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in our estimated cash flow is the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation and depletion unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and

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expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. We will assess unproved properties for impairment quarterly on the basis of our experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors.

Impairment of Oil and Natural Gas Properties

For the year ended December 31, 2010 and the six months ended December 31, 2009 we recorded a non-cash impairment charge of approximately $1.8 million and $7.8 million, respectively, primarily associated with proved oil and natural gas properties related to unfavorable market conditions. For the year ended December 31, 2010, approximately $0.6 million of the impairment charge was associated with properties that were sold to the Mid-Con Affiliates. For the year ended December 31, 2009, approximately $6.3 million of the impairment charge was associated with properties that were sold to the Mid-Con Affiliates. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in impairment of oil and natural gas properties in our combined statement of operations. We recorded no impairment charge for proved oil and natural gas properties for the years ended June 30, 2009 and June 30, 2008.

Asset Retirement Obligations

The initial estimated asset retirement obligation associated with oil and natural gas properties is recognized as a liability, with a corresponding increase in the carrying value of oil and natural gas properties. Amortization expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the liability and the carrying value of the property. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable.

Derivative Contracts and Hedging Activities

Current accounting rules require that all derivative contracts, other than those that meet specific exclusions, be recorded at fair value. Quoted market prices are the best evidence of fair value. If quotations are not available, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or on other valuation techniques.

Our derivative contracts are exchange-traded transactions. Valuation is determined by reference to readily available public data.

We recognize all of our derivative contracts as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative contract depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative contracts that are designated and qualify as hedging instruments, we designated the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative contracts not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of

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change. None of our derivatives was designated as a hedging instrument during the six months ended June 30, 2011, the year ended December 31, 2010, the six months ended December 31, 2009, or the year ended June 30, 2009 and 2008, respectively.

Recently Issued Accounting Pronouncements

In December 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (ASU) 2010-29, “Business Combinations” (Topic 805): “Disclosure of Supplementary Pro Forma Information for Business Combinations”, which updates the amended guidance in Accounting Standards Codification (ASC) Topic 805-10-50. This update was issued in order to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations.

The update requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. If comparative financial statements are presented, the pro forma revenue and earnings of the combined entity for the comparable prior reporting period should be reported as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period.

In practice, some preparers have presented the pro forma information in their comparative financial statements as if the business combination that occurred in the current reporting period had occurred as of the beginning of each of the current and prior annual reporting periods. Other preparers have disclosed the pro forma information as if the business combination occurred at the beginning of the prior annual reporting period only, and carried forward the related adjustments, if applicable, through the current reporting period. We plan to adopt the updated rules in relation to all future business combinations.

Internal Controls and Procedures

Prior to the completion of this offering, we have been a private entity with limited accounting personnel but have adequately executed our accounting processes. Our ability to maintain adequate control over our accounting processes have led to minimal audit adjustments to the financial statements. In connection with our audit for the year ended December 31, 2010 we received a letter of internal control deficiencies identified during the audit from our independent registered accounting firm, but none of these matters were classified as a material weakness or significant deficiency. We have taken steps that we believe have resolved each of these deficiencies.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

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BUSINESS AND PROPERTIES

Overview

As of June 30, 2011, our total estimated proved reserves were 7.9 MMBoe, of which approximately 98% were oil and approximately 71% were proved developed, both on a Boe basis. As of June 30, 2011, we operated 98% of our properties and 92% were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended June 30, 2011 was approximately 1,248 Boe per day and our total estimated proved reserves had a reserve-to-production ratio of approximately 17 years. Our management team developed approximately two-thirds of our total reserves through new waterflood projects.

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The following table summarizes information by core area regarding our estimated oil and natural gas reserves as of June 30, 2011 and our average net production for the month ended June 30, 2011.


												Average
												Net
												Production
	Estimated											for the Month Ended
	Net Proved Reserves											June 30,
	as of June 30, 2011											2011				Average		Gross Active Wells
																Reserve-to-		Oil and
									% Proved			Boe/d		Boe/d		Production		Natural		Injection
	(MBoe)		% Operated			% Oil			Developed			Gross		Net		Ratio(1)		Gas Wells		Wells

Southern Oklahoma		4,783		100	%		99	%		58	%		1,892		700		19		65		42
Northeastern Oklahoma		2,043		100	%		99	%		91	%		593		340		16		154		59
Hugoton Basin		720		100	%		99	%		85	%		234		141		14		43		18
Other		361		77	%		60	%		100	%		231		67		15		13		4

Total		7,907		99	%		98	%		71	%		2,950		1,248		17		275		123


(1)		The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of June 30, 2011 by average net production for the month ended June 30, 2011.

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Our Hedging Strategy

Our Business Strategies


	•	*Continue exploitation of our existing properties to maximize production.* We plan to continue exploiting our proved reserves to maximize production, primarily through waterflood projects and through various oil recovery methods, including workovers, conventional hydraulic fracturing, re-stimulations, recompletions, infill drilling and other optimization activities. Using these techniques, we significantly increased our average net pro forma production over the twelve months ended June 30, 2011. We expect to continue these activities in order to maximize our production.

	•	*Pursue acquisitions of long-lived, low-risk producing properties with upside potential.* We will seek to acquire onshore properties with long-lived reserves, low production decline rates and low-risk development potential. We also will seek to acquire properties within mature oil fields with opportunities for incremental improvements in oil

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		recovery through waterfloods and other recovery techniques, which we believe will offer us additional potential to increase reserves, production and cash flow.


	•	*Capitalize on our relationship with the Mid-Con Affiliates for favorable acquisition opportunities.* We expect that the Mid-Con Affiliates will invest capital and technical staff resources to acquire and develop properties with existing waterfloods and to identify, acquire, form and develop new waterflood projects on those properties. Through this relationship with the Mid-Con Affiliates, we plan to avoid much of the capital, engineering and geological risks associated with the early development of any of these properties we may acquire. While they are not obligated to sell any properties to us and may have difficulties acquiring and developing them, we expect that the Mid-Con Affiliates will offer to sell properties to us from time to time. We believe that the opportunity to acquire properties from the Mid-Con Affiliates provides us with a strategic advantage over those of our competitors who must bear a greater share of development risks themselves.

	•	*Maintain operational control and a focus on cost-effectiveness in all our operations.* As of June 30, 2011, we operated 98% of our properties, as calculated on a Boe basis, through our affiliate, Mid-Con Energy Operating. We plan to continue exercising this level of operational control over our existing properties and favor acquisitions of operated properties in order to manage the timing and levels of our capital expenditures, development activities and operating costs.

	•	*Reduce the impact of commodity price volatility on our cash flow through a disciplined commodity hedging strategy.* We will seek to reduce the impact of commodity price volatility on our cash flow by maintaining a portfolio covering approximately 50% to 80% of our estimated oil production from proved reserves over a three-to-five year period. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated production and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes or the duration of our hedge contracts when circumstances suggest that it is prudent to do so.

	•	*Maintain a balanced capital structure to allow for financial flexibility to execute our business strategies.* We intend to maintain a balanced capital structure that will afford us the financial flexibility to execute our business strategies. We believe our borrowing capacity under our new credit facility, our access to capital markets and internally generated cash flow will provide us with the liquidity and financial flexibility to exploit organic growth opportunities and allow us to pursue additional acquisitions of producing properties.

	•	*Utilize compensation programs that align the interests of our management team with our unitholders.* We will tie the compensation of our executives and directors directly to achieving our strategic, operating and financial goals and to adopt compensation programs that place a significant part of the pay of each of our executives “at risk” in the form of an annual short-term incentive award and long-term, equity-based incentive grants. The amount of the annual short-term incentive award paid will depend on our performance against financial and operating objectives as well as the executive meeting key leadership and development standards. A portion of the compensation of the executives will also be in the form of equity awards that tie their compensation directly to creating unitholder value over the long-term. We believe this combination of annual short-term incentive awards and long-term equity awards aligns the incentives of our management with our unitholders.

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Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:


	•	An asset portfolio largely consisting of properties with existing waterflood projects that have relatively predictable production profiles, that provide growth potential through ongoing response to waterflooding and that have modest capital requirements. Our properties consist of interests in mature fields located in Oklahoma and Colorado that have well-understood geologic features, relatively predictable production profiles and modest capital requirements, which we believe make them well-suited for waterflood development and for our objective of generating stable cash flow. Over 90% of our properties are being waterflooded and have been producing continuously since 1982 or earlier. Based on production estimates from our June 30, 2011 reserve report, the average estimated decline rate for our existing proved developed producing reserves is approximately 4% for 2011 and, on a compounded average annual decline basis, approximately 11% for the subsequent five years and approximately 10% thereafter. Additionally, based on production estimates from this reserve report, we believe that we have the ability to increase our average net production from our existing proved reserves to approximately 1,700 Boe per day during the next three years. Further, we believe that a substantial majority of the capital required for growth from our existing properties has been spent prior to this offering. As a result, these properties have relatively predictable production profiles and production growth potential with modest capital requirements.

	•	*The ability to further exploit existing mature properties by utilizing our waterflood expertise.* Our management team has actively operated most of our properties since 2005, and has a history of exploiting proved reserves to maximize production, primarily through waterflood projects. Over the last six years, we identified, initiated, acquired, formed and developed over 24% of all new waterflood projects in the State of Oklahoma, while the next most active competitor formed only 6% of all new waterfloods. Furthermore, our experience in the Mid-Continent allows us to exploit synergies developed by applying knowledge of field, reservoir and play characteristics across the region. We believe that our expertise in secondary recovery techniques will increase the level of production from certain of our properties, particularly from existing waterflood projects, which, over time, may increase our cash flow.

	•	Acquisition opportunities that are consistent with our criteria of predictable production profiles with upside potential that may arise as a result of our relationship with the Mid-Con Affiliates. We expect the Mid-Con Affiliates to invest capital and technical staff resources to acquire and develop properties with existing projects and to identify, acquire, form and develop new waterflood projects on their properties. While they are not obligated to sell any properties to us and may have difficulties acquiring and developing them, we expect that the Mid-Con Affiliates will offer to sell properties to us from time to time. Through this relationship with the Mid-Con Affiliates, we plan to avoid much of the capital, engineering and geological risks associated with the early development of any of these properties we may acquire.

	•	*Access to the collective expertise of Yorktown’s employees and their extensive network of industry relationships through our relationship with Yorktown.* Yorktown is a private equity firm focused on investments in the energy sector with more than $3.0 billion in assets under management. Following the consummation of this offering, Yorktown will own an approximate % limited partner interest in us, making it our largest unitholder, and will own a separate class of non-voting member interests in our general partner. With their extensive investment experience in the oil and natural gas

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		industry and their extensive network of industry relationships, we believe that Yorktown’s employees are well positioned to assist us in identifying and evaluating acquisition opportunities and in making strategic decisions.


	•	*The ability to better manage our operating costs, capital expenditures and development schedule because of our high level of operational control.* As of June 30, 2011, we operated 98% of our properties, as calculated on a Boe basis. Following this offering, we expect to continue exercising this level of operational control over our properties, including any properties we acquire through future acquisitions, which will allow us to better manage our operating costs and capital expenditures. We believe that this substantial operational control of our producing properties will also allow us to maximize the value of our properties, help us to stabilize cash flow and better control the timing and costs of our operations.

	•	*An enhanced ability to pursue acquisition opportunities arising from our competitive cost of capital and balanced capital structure.* Unlike our corporate competitors, we are not subject to federal income taxation at the entity level. This attribute should provide us with a lower cost of capital compared to those competitors, thereby enhancing our ability to compete for future acquisitions of oil and, when advantageous, natural gas properties. We also believe our low level of indebtedness and our ability to issue additional common units and other partnership interests in connection with these acquisitions will improve our financial flexibility. Further, we expect to have an available borrowing capacity of approximately $ million under our new credit facility after giving effect to approximately $ million borrowed thereunder in connection with this offering, which will provide us with another potential means of financing acquisition opportunities.

	•	*The range and depth of our technical and operational expertise will allow us to expand both geographically and operationally to achieve our goals.* During the past eight years, we have assembled a senior team of geologists, engineers, landmen, accountants and operational personnel that have been successful in developing a significant number of new waterflood projects. Collectively, our management and employees have prior waterflood experience in over 150 waterflood projects located in more than ten states. We have a team of more than 60 employees, with senior leadership in all production disciplines, and we have recruited a select group of younger professionals that are being trained in our waterflood specialty. With this expertise and depth, we believe this team has the ability to generate new waterflood projects that may become future acquisition opportunities for us. Beyond our core strength of waterflood development, we believe that our range and depth of expertise will allow us to expand both geographically and operationally. Although our projects to date have been focused on waterfloods in the Mid-Continent region, we believe our management and operational employees have significant oil and gas experience in many other regions of the United States. We believe that our wealth of experience may enable us to pursue other types of exploitation opportunities, such as infill drilling projects, that could significantly contribute to our strategy of generating stable cash flow and, over time, increasing our quarterly cash distributions.

Our Principal Business Relationships

Our Relationship with the Mid-Con Affiliates

In June 2011, management and Yorktown formed two limited liability companies, which we refer to as the Mid-Con Affiliates, to acquire and develop oil and natural gas properties that are either undeveloped or that may require significant capital investment and development efforts before they meet our criteria for ownership. As these development projects mature, we expect to have the opportunity to acquire certain of these properties from the Mid-Con Affiliates. Through this relationship with the Mid-Con Affiliates, we plan to avoid much of the capital, engineering

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and geological risks associated with the early development of any of these properties we may acquire. However, the Mid-Con Affiliates may not be successful in indentifying or consummating acquisitions or in successfully developing the new properties they acquire. Further, the Mid-Con Affiliates are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. For a summary of the process by which such mutually agreeable prices will be determined, please see “Certain Relationships and Related Party Transactions—Review, Approval or Ratification of Transactions with Related Persons.”

Our Relationship with Yorktown

Oil Recovery Overview

When an oil field is first produced, the oil typically is recovered as a result of expansion of reservoir fluids which are naturally pressured within the producing formation. The only natural force present to move the oil through the reservoir rock to the wellbore is the pressure differential between the higher pressure in the rock formation and the lower pressure in the producing wellbore. Various types of pumps are often used to reduce pressure in the wellbore, thereby increasing the pressure differential. At the same time, there are many factors that act to impede the flow of oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production, referred to as “primary recovery,” recovers only a small fraction of the oil originally in place in a producing formation, typically ranging from 10% to 25%.

After the primary recovery phase many, but not all, oil fields respond positively to “secondary recovery” techniques in which external fluids are injected into a reservoir to increase reservoir pressure and to displace oil towards the wellbore. Secondary recovery techniques often result in increases in production and reserves above primary recovery. Waterflooding, a form of secondary recovery, works by repressuring a reservoir through water injection and “sweeping” or pushing oil to producing wellbores. Conventional hydraulic fracturing techniques are often employed to increase a well’s productivity in waterflooding. Through waterflooding, water injection replaces the loss of reservoir pressure caused by the primary production of oil and gas, which is often referred to as “pressure depletion” or “reservoir voidage.” The degree to which reservoir voidage

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has been replaced through water injection is known as “reservoir fill up” or, simply as “fill up.” A reservoir which has had all of the produced fluids replaced by injection is at 100% fill up. In general, peak oil production from a waterflood typically occurs at 100% fill up. Estimating the percentage of fill up which has occurred, or when a reservoir is 100% filled up, is subject to a wide variety of engineering and geologic uncertainties. As a result of the water used in a waterflood, produced fluids contain both water and oil, with the relative amount of water increasing over time. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. In general, in the Mid-Continent region, a secondary recovery project may produce an additional 10% to 20% of the oil originally in place in a reservoir.

A third stage of oil recovery is called “tertiary recovery.” In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate additional production. The three major types of tertiary recovery are chemical flooding, thermal recovery (such as a steamflood) and miscible displacement involving carbon dioxide (CO ₂ ), hydrocarbon or nitrogen injection. We are currently field testing new technologies in chemical flooding on some of our properties. If successful, this testing may lead to reserve and production increases in the future. Any future tertiary development programs and subsequent capital expenditures would be contingent upon commercial viability established by successful pilot testing. At this time there are no estimated reserves or production associated with tertiary recovery projects assigned to our properties. We will continue to review future opportunities for growth through the use of various tertiary recovery techniques.

Our Properties

Our properties are located in the Mid-Continent region of the United States in three core areas: Southern Oklahoma, Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. These core areas are each composed of multiple units that are in close proximity to one another, produce from the same or geologically similar reservoirs and use similar waterflood methods. Focusing on these core areas allow us to apply our cumulative technical and operational knowledge to ongoing property development and to better predict future rates of recovery. For a discussion of the properties in our core areas, please see “—Summary of Oil Properties and Projects.”

Our properties consist of mature, legacy onshore oil reservoirs, approximately 92% of the reserves of which are being produced under waterflooding, as calculated using the standardized measure. Our properties include multiple waterflood projects with varying degrees of maturity. We have staggered the waterflooding of these properties so that production increases from more recently developed waterfloods offsets declines from mature waterflood areas, leading to more stable cash flow and production.

We use words such as “mature” or “legacy” to describe our properties as having established operating, reservoir and production characteristics. The production and corresponding decline rates attributable to properties of this type—in contrast with more recently drilled properties—can generally be forecasted with a greater degree of accuracy. Our ability to predict future performance is further enhanced by the familiarity that we have with most of our properties. We have observed the performance of many of our properties over many years, in many cases from the inception of waterflooding. This long-term observation allows for greater understanding of production and reservoir characteristics, making future performance more predictable.

We own a 62% average working interest across 275 gross producing wells (159 net) wells, 123 gross injection wells (66 net) wells and operate 99% of our properties by value, as calculated using the standardized measure. Approximately 98% of our revenue is derived from the proceeds of oil production. Based on the standardized measure, our value-weighted average working interest on these properties was approximately 65% based on our June 30, 2011 reserve report.

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Our estimated proved reserves as of June 30, 2011 were 7.9 MMBoe, of which approximately 98% were oil and approximately 71% were proved developed, both on a Boe basis. For the month ended June 30, 2011, we produced an average of 1,248 Boe per day. Based on production estimates from our June 30, 2011 reserve report, the average estimated decline rate for our existing proved developed producing reserves is approximately 4% for 2011, approximately 11% for the subsequent five years and, on a compounded average decline basis, approximately 10% thereafter.

The following table shows the estimated net proved oil reserves or principal fields, based on a reserve report prepared by our internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, as of June 30, 2011, and certain unaudited information regarding production and sales of oil and natural gas with respect to such properties.

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	Pro Forma Average Net					Estimated Net Proved Reserves
	Production					as of June 30,
	for the Month Ended					2011
	June 30,							% of						%
	2011(1)							Total						Proved
	Net		% of					Proved						Developed			Undiscounted		Standardized		% of
	(Boe/d)		Total			MBoe		Reserves			% Oil			Reserves			Cap. Ex.		Measure(2)(3)		Total
																	(in millions)		(in millions)

Southern Oklahoma Fields/Units:
Highlands(4)		206		17	%		2,393		30	%		99	%		62	%	$	11	$	85		37	%
Battle Springs(4)		348		28	%		1,122		14	%		100	%		81	%		4		45		19	%
Ardmore West(4)		49		4	%		649		8	%		99	%		5	%		2		17		7	%
Twin Forks(4)		30		2	%		455		6	%		100	%		42	%		3		13		6	%
Southeast Hewitt		55		4	%		126		2	%		100	%		100	%		—		5		2	%
Other Southern Oklahoma Fields/Units		12		1	%		38		< 1	%		100	%		100	%		—		1		< 1	%

Total Southern Oklahoma Fields / Units		700		56	%		4,783		60	%		99	%		58	%	$	20	$	166		71	%

Northeastern Oklahoma Fields / Units:
Cleveland		209		17	%		1,036		13	%		99	%		100	%	$	2	$	25		11	%
Cushing		91		7	%		596		8	%		99	%		100	%				12		5	%
Skiatook(4)		25		2	%		363		5	%		100	%		50	%		1		6		3	%
Other Northeastern Oklahoma Fields/Units		15		1	%		48		< 1	%		100	%		100	%		—		1		—

Total Northeastern Oklahoma Fields / Units		340		27	%		2,043		26	%		99	%		91	%	$	3	$	44		19	%

Hugoton Fields / Units:
War Party I		61		5	%		350		4	%		99	%		100	%		—	$	7		3	%
War Party II		59		5	%		217		3	%		100	%		100	%		—		3		1	%
Harker Ranch(4)		21		2	%		153		2	%		100	%		27	%		1		3		1	%


Total Hugoton Fields / Unit		141		12	%		720		9	%		99	%		85		$	1	$	13		5	%

Other Fields / Units:
Decker(4)		18		1	%		216		3	%		100	%		100	%		—	$	8		3	%
Miscellaneous		49		4	%		145		2	%		< 1	%		100	%		—		2		1	%


Total Other Fields / Units		67		5	%		361		5	%		60	%		100	%		—	$	10		5	%

*All Fields*		1,248		100	%		7,907		100	%		98	%		71	%	$	24	$	233		100	%


(1)		Excludes production from certain properties, which represent approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011, that were sold to the Mid-Con Affiliates on June 30, 2011.

(2)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 — Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas . Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”

(3)		Our estimated net proved reserves and standardized measure were computed by applying average trailing 12-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable 12-month period), held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The average trailing 12-month index prices were $89.96 per Bbl for oil and $4.20 per MMBtu for natural gas for the 12 months ended June 30, 2011.

(4)		Denotes a waterflood project or unit that we identified, acquired, formed and developed.

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Summary of Oil Properties and Projects

Our principal fields detailed below represent approximately 97% of our total estimated net proved reserves as of June 30, 2011, 94% of our average daily net production for the month ended June 30, 2011 and 98% of our standardized measure as of June 30, 2011. Please read “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in evaluating the material presented below. The following is a summary of each of our properties within our core areas. All of the following descriptions are based on our June 30, 2011 reserve report.

Southern Oklahoma

Highlands Unit. The Highlands Unit is in the SE Joiner City Field, an oil-weighted field located in Love County, Oklahoma. Since its discovery in 1980, the Highlands Unit has produced approximately 2,814 MBoe. Production from the Highlands Unit is from the Deese formation at an average depth of approximately 8,000 feet. The Highlands Unit was formed and is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during October 2008, and production response to injection started in April 2009. We own 15 gross (7 net) producing and 16 gross injection (7 net) wells in this unit with an average working interest of 57%. As of June 30, 2011, our properties in this unit were producing 569 Boe per day gross, 206 Boe per day net, and contained 2,393 MBoe of estimated net proved reserves. The current rate of 569 Boe per day gross is approximately 41% of the future peak rate as estimated in our June 30, 2011 reserve report, and has increased from 88 Boe per day gross for the month of January 2010. As a result of ongoing response to waterflooding, proved producing and proved developed reserves represent 24% and 62%, respectively, as of June 30, 2011, of the total proved reserves, compared to 5% and 49%, respectively, as of January 1, 2010. Reservoir fill-up is estimated to be 23%.

Battle Springs Unit. The Battle Springs Unit is in the SE Joiner City Field, an oil-weighted field located in Love County, Oklahoma. Since its discovery in 1982, the Battle Springs Unit has produced approximately 2,519 MBoe. Production from the Battle Springs Unit is from the Deese formation at an average depth of approximately 8,850 feet. The Battle Springs Unit was formed and is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during September 2006, and production response to injection started in December 2006. We own 16 gross (8 net) producing and 12 gross injection (6 net) wells in this unit with an average working interest of 51%. As of June 30, 2011, our properties in this unit were producing 861 Boe per day gross, 348 Boe per day net, and contained 1,122 MBoe of estimated net proved reserves. The current rate of 861 Boe per day gross is approximately 92% of the future peak rate as estimated in our June 30, 2011 reserve report, and has increased from 354 Boe per day gross for the month of January 2010. As a result of ongoing response to waterflooding, proved producing and proved developed reserves represent 72% and 81%, respectively, as of June 30, 2011, of the total proved reserves, compared to 42% and 58%, respectively, as of January 1, 2010. Reservoir fill-up is estimated to be 25%.

Ardmore West Unit. The Ardmore West Unit is in the Ardmore West Field, an oil-weighted field located in Carter County, Oklahoma. Since its discovery in 1969, the Ardmore West Unit has produced approximately 580 MBoe. Production from the Ardmore West Unit is from the Deese formation at an average depth of approximately 7,200 feet. The Ardmore West Unit is a waterflood currently being developed which was formed in July 2010 and is operated by our affiliate, Mid-Con Energy Operating. We own 4 gross (4 net) producing and 2 gross (2 net) injection wells in this unit with an average working interest of 96%. As of June 30, 2011, our properties in this unit were producing 63 Boe per day gross, 49 Boe per day net, and contained 649 MBoe of estimated net proved reserves. The current rate of 63 Boe per day gross is approximately 25% of the future peak rate as estimated in our June 30, 2011 reserve report, and has increased from 3 Boe per day gross for the month of January 2010. Proved producing and

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proved developed reserves represent 5% and 5%, respectively, as of June 30, 2011, of the total proved reserves. Reservoir fill-up is 0% as injection should commence during the third quarter of 2011.

Twin Forks Unit. The Twin Forks Unit is in the SE Joiner City Field, an oil-weighted field located in Carter County, Oklahoma. Since its discovery in 1979, the Twin Forks Unit has produced approximately 1,092 MBoe. Production from the Twin Forks Unit is from the Deese formation at an average depth of approximately 7,000 feet. The Twin Forks Unit was formed and is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during September 2009, and production response to injection started in October 2010. We own 6 gross (3 net) producing and 3 gross (2 net) injection wells in this unit with an average working interest of 64%. As of June 30, 2011, our properties in this unit were producing 73 Boe per day gross, 30 Boe per day net, and contained 455 MBoe of estimated net proved reserves. The current rate of 73 Boe per day gross is approximately 34% of the future peak rate as estimated in our June 30, 2011 reserve report, and has increased from 35 Boe per day gross for the month of January 2010. As a result of ongoing response to waterflooding, proved producing and proved developed reserves represent 42% and 42%, respectively, as of June 30, 2011, of the total proved reserves, compared to 14% and 14%, respectively, as of January 1, 2010. Reservoir fill-up is estimated to be 12%.

Southeast Hewitt Unit. The Southeast Hewitt Unit is in the SE Wilson Field, an oil-weighted field located in Carter County, Oklahoma. Since its discovery in 1979, the Southeast Hewitt Unit has produced approximately 1,503 MBoe. Production from the Southeast Hewitt Unit is from the Deese formation at an average depth of approximately 6,000 feet. The Southeast Hewitt Unit is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during June 1997, and production response to injection started in November 1997. We own 8 gross (2 net) producing and 7 gross (2 net) injection wells in this unit with an average working interest of 22%. As of June 30, 2011, our properties in this unit were producing 296 Boe per day gross, 55 Boe per day net, and contained 126 MBoe of estimated net proved reserves. The Southeast Hewitt Unit is a mature waterflood which reached its peak production rate during 2010. We will continue our efforts to maximize production and reserves from the Southeast Hewitt Unit. Reservoir fill-up is estimated to be 95%.

Northeastern Oklahoma

Cleveland Field. The Cleveland Field is an oil-weighted field located in Pawnee County, Oklahoma. Since its discovery in 1904, the entire Cleveland Field has produced approximately 47 MMBoe. Production from the Cleveland Field is primarily from the multiple Pennsylvanian age sands at depths from 1,000 to 2,400 feet. Approximately 1560 acres in the Cleveland Field is being operated by our affiliate, Mid-Con Energy Operating. Approximately 840 of the total 1560 acres have been acquired in the last eighteen months. We have been actively developing our Cleveland Field leases through drilling, recompletions and workovers, resulting in an approximate doubling of net production within the last twelve months. The majority of Mid-Con Energy Operating operated leases are produced under waterflood. We operate 63 gross (54 net) producing wells and 19 gross (18 net) injection wells in this field with an average working interest of 96%. As of June 30, 2011, our properties in this field were producing 250 Boe per day gross, 209 Boe per day net, and contained 1,036 MBoe of estimated net proved reserves. Waterflooding in the Cleveland Field was initiated in most areas by about 1960, although waterflood pilot testing began on some leases prior to 1960. We believe that reservoir fill up probably has occurred within the Bartlesville reservoir on these properties. However, the historical injection and production records necessary to determine fill up status are not available. The Cleveland Field is flooded on a lease basis and not as a unit, with the date of production response to injection varying from lease to lease. The Cleveland Field is a mature waterflood area which has already reached its peak production rate. We will continue our efforts to maximize production and reserves from the Cleveland Field through workovers, recompletions and infill drilling.

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Cushing Field. The Cushing Field, one of the largest oil fields (by total historical production volume) in the United States is an oil-weighted field located in Creek County, Oklahoma. Since its discovery in 1912, the entire Cushing Field has produced in excess of 500 MMBoe. Production from the Cushing Field is primarily from multiple Pennsylvanian age sands at depths from 1,200 to 2,500 feet. Our affiliate, Mid-Con Energy Operating, operates approximately 2,800 acres in the Cushing Field, the majority of which are being produced under waterflood. We are currently engaged in a workover program on this property to develop additional zones in existing wellbores and to return wells to production. We operate 72 gross (18 net) producing wells and 35 gross (9 net) producing wells in this field with an average working interest of 38%. As of June 30, 2011, our properties in this field were producing 286 Boe per day gross, 91 Boe per day net, and contained 596 MBoe of estimated net proved reserves. Waterflooding in the Cushing field was initiated in most areas by about 1960, although waterflood pilot testing began on some leases prior to 1960. We believe that reservoir fill up probably has occurred within the main reservoir(s) on these properties. However, the historical injection and production records necessary to determine fill up status are not available. The Cushing field is flooded on a lease basis and not as units, with waterflood responses varying from lease to lease. The Cushing Field is a mature waterflood area which has already reached its peak production rate. We will continue our efforts to maximize production and reserves from the Cushing Field through workovers and recompletions.

Skiatook Project. The Skiatook Waterflood Project is in the Skiatook Field, an oil-weighted field located in Osage County, Oklahoma. Since its discovery in 1919, the Skiatook Field has produced approximately 1,169 MBoe. Production from the Skiatook Project is primarily from the Bartlesville and Burgess formations at an average depth of approximately 1,600 feet. The Skiatook Project was developed by and is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during December 2006, and production response to injection started in January 2008. We own 14 gross (14 net) producing and 5 gross (5 net) injection wells in this field with a working interest of 100%. As of June 30, 2011, our properties in this field were producing 30 Boe per day gross, 25 Boe per day net, and contained 363 MBoe of estimated net proved reserves. The current rate of 30 Boe per day gross is approximately 55% of the future peak rate as estimated in our June 30, 2011 reserve report, and has increased from 27 Boe per day gross for the month of January 2010. As a result of ongoing response to waterflooding, proved producing and proved developed reserves represent 50% and 50%, respectively, as of June 30, 2011, of the total proved reserves, compared to 16% and 16%, respectively, as of January 1, 2010. Reservoir fill-up is estimated to be 8%.

Hugoton Basin

War Party I and II Units. The War Party I and II Units are in the SE Guymon Field, an oil-weighted field located in Texas County, Oklahoma. Since their discovery in 1998, the War Party I and II Units have collectively produced approximately 3,959 MBoe. Production from the War Party I and II Units is from the Cherokee formation at an average depth of approximately 5,800 feet. The War Party I and II Units are operated by our affiliate, Mid-Con Energy Operating, and both are being produced under waterflood. Injection began during December 2001 and July 2002 for War Party Unit I and War Party Unit II, respectively, and production response to injection started in February 2002 and March 2003 for War Party Unit I and War Party Unit II, respectively. We own 39 gross (26 net) producing wells and 15 gross (10 net) injection wells in both units with an average working interest in War Party I of 86% and in War Party II of 54%. As of June 30, 2011, our properties in these units were producing 209 Boe per day gross, 120 Boe per day net, and contained 567 MBoe of estimated net proved reserves. These are mature waterflood properties which have already reached peak production rates and where injection commenced several years prior to acquisition by our predecessor. We believe that reservoir fill up probably has occurred within the main reservoir(s) on these properties. However, the historical injection and production records necessary to determine fill up status are not available. We are

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currently working to maximize production and reserves from these units through workovers and by returning idle wells to production.

Harker Ranch Unit. The Harker Ranch Unit is in the Harker Ranch Field, an oil-weighted field located in Cheyenne County, Colorado. Since its discovery in 1989, the Harker Ranch Unit has produced over 903 MBoe. Production from the Harker Ranch Field is from the Morrow formation at an average depth of approximately 5,200 feet. The Harker Ranch Unit was formed and is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during September 2006, and production response to injection started in May 2008. We own 3 gross (3 net) producing and 3 gross (3 net) injection wells in this unit with a working interest of 100%. As of June 30, 2011, our properties in this unit were producing 26 Boe per day gross, 21 Boe per day net, and contained 153 MBoe of estimated net proved reserves. The current rate of 26 Boe per day gross is approximately 44% of the future peak rate as estimated in our June 30, 2011 reserve report, and is relatively unchanged from 27 Boe per day gross for the month of January 2010. As a result of ongoing response to waterflooding, proved producing and proved developed reserves represent 27% and 27%, respectively, as of June 30, 2011, of the total proved reserves, compared to 9% and 9%, respectively, as of January 1, 2010. Reservoir fill-up is estimated to be 56%.

Other Properties

Decker Unit. The Decker Unit is in the NW Little Field, an oil-weighted field located in Seminole County, Oklahoma. Since its discovery in 1954, the Decker Unit has produced approximately 563 MBoe. Production from the Decker Unit is from the Earlsboro formation at an average depth of approximately 3,600 feet. The Decker Unit was formed and is operated by our affiliate, Mid-Con Energy Operating, and is being produced under waterflood. Injection began during December 2008, and production response to injection started in September 2009. We own 8 gross (8 net) producing and 4 gross (4 net) injection wells in this unit with an average working interest of 98%. As of June 30, 2011, our properties in this unit were producing 23 Boe per day gross, 18 Boe per day net, and contained 216 MBoe of estimated net proved reserves. The current rate of 23 Boe per day gross is approximately 30% of the future peak rate as estimated in our June 30, 2011 reserve report, and has increased from 18 Boe per day gross for the month of January 2010. As a result of ongoing response to waterflooding, proved producing and proved developed reserves represent 23% and 100%, respectively, as of June 30, 2011, of the total proved reserves, compared to 4% and 4%, respectively, as of January 1, 2010. Reservoir fill-up is estimated to be 52%.

The balance of the Company’s properties, located throughout the State of Oklahoma, consist of a mix of operated and non-operated properties, none of which are under waterflood. As of June 30, 2011, our other properties contained 145 MBoe of estimated net proved reserves and generated average net production of 49 Boe per day for the month ended June 30, 2011.

Oil and Natural Gas Reserves and Production

Internal Controls Relating to Reserve Estimates

Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by our reservoir engineering staff. Reserves are reviewed internally by our senior management on a quarterly basis. Following the consummation of this offering, we anticipate that the audit committee of our board of directors will conduct a similar review on a quarterly basis. We expect to have our reserve estimates audited by our independent third-party reserve engineers, Cawley, Gillespie & Associates, Inc., at least annually.

Our staff works closely with Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve audit process. To facilitate their audit of our reserves, we provide Cawley,

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Gillespie & Associates, Inc. with any information they may request, including all of our reserve information as well as geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures, lease operating expenses, product pricing, production taxes and relevant economic criteria. We also make all of our pertinent personnel available to Cawley, Gillespie & Associates, Inc. to respond to any questions they may have.

Technology Used to Establish Proved Reserves

Under the SEC rules, proved reserves are those quantities of oil and natural gas that 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Cawley, Gillespie & Associates, Inc. employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, injection data, seismic data and well test data. Reserves attributable to producing properties with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing properties with limited production history and for undeveloped locations were estimated using performance from analogous properties in the surrounding area and geologic data to assess the reservoir continuity. These properties were considered to be analogous based on production performance from the same formation and similar completion techniques.

Qualifications of Responsible Technical Persons

Internal Mid-Con Energy Operating Person. Robbin W. Jones, P.E., Vice President and Chief Engineer of our general partner, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Mr. Jones has over 30 years of industry experience with positions of increasing responsibility in management, production, reservoir engineering and reserve evaluations with companies such as Enserch Exploration, Caruthers Producing, Diamond Energy Operating Company, Equinox Oil Company and Schlumberger Data & Consulting Services. In 1981, he received a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. He is a Registered Professional Engineer in the States of Louisiana and Texas and a member of the Society of Petroleum Engineers.

Cawley, Gillespie & Associates, Inc. Cawley, Gillespie & Associates, Inc. is an independent oil and natural gas consulting firm. No director, officer, or key employee of Cawley, Gillespie & Associates, Inc. has any financial ownership in our predecessor, the Mid-Con Affiliates, Mid-Con Energy Operating, Yorktown or any of their respective affiliates. Cawley, Gillespie & Associates, Inc.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. Cawley, Gillespie & Associates, Inc. has not performed other work for our predecessor, the Mid-Con Affiliates or Mid-Con Energy Operating. Cawley, Gillespie & Associates, Inc. has performed services for certain of Yorktown’s portfolio companies. The engineering audit presented in the Cawley, Gillespie & Associates, Inc. report was overseen by Bob Ravnaas, P.E., Executive Vice President. Mr. Ravnaas is an

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experienced reservoir engineer having been a practicing petroleum engineer since of 1981. He has more than 28 years of experience in reserves evaluation. Mr. Ravnaas received a BS with special honors in Chemical Engineering from the University of Colorado at Boulder in 1979, and a M.S. in Petroleum Engineering from the University of Texas at Austin in 1981. He is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Petrophysicists and Well Log Analysts.

Estimated Proved Reserves

The following table presents our estimated net proved oil and natural gas reserves and the standardized measure amounts associated with our estimated proved reserves attributable to our properties as of December 31, 2010, and as of June 30, 2011, in each case, based on reserve reports prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc.


	Pro Forma as of		As of
	December 31,		June 30,
	2010(2)		2011

Reserve Data(1):
Estimated proved reserves (MBoe)		7,116		7,907
Estimated proved developed reserves (MBoe)		3,710		5,605
Estimated proved undeveloped reserves (MBoe)		3,406		2,302
Standardized Measure (in millions)(3)	$	182.1	$	233.1


(1)		Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $79.43 per Bbl for oil and $4.37 per MMBtu for natural gas at December 31, 2010 and $89.96 per Bbl for oil and $4.20 per MMBtu for natural gas at June 30, 2011. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For the year ended December 31, 2010, the relevant average realized prices for oil and natural gas were $74.15 per Bbl and $7.56 per Mcf, respectively, on a pro forma basis. For the six months ended June 30, 2011, the relevant average realized prices for oil and natural gas were $93.55 per Bbl and $8.84 per Mcf, respectively, on a pro forma basis. Realized natural gas sales price per Mcf includes the sale of natural gas liquids for both the years ended December 31, 2010 and the six months ended June 30, 2011.

(2)		Excludes certain properties which represented approximately 2% of our proved reserves by value, as calculated using the standardized measure, as of June 30, 2011 that were sold to the Mid-Con Affiliates on June 30, 2011.

(3)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas . Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”

The data in the table above represent estimates only. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Risk Factors—Risks Related to Our Business—Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts

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shown above should not be construed as the current market value of our estimated oil reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

The following table represents a summary of activity within our proved undeveloped reserve category for the year ended December 31, 2010:


	Oil			Gas		Total
	(MBbl)			(MMcf)		(MBoe)

Proved undeveloped reserves-beginning of year		3,686			—		3,686
Transferred to proved developed through drilling		(333	)		—		(333	)
Increase (decrease) due to evaluation reassessments and drilling results, net		(234	)		—		(234	)
Acquisition of reserves		287			—		287
Reduction of proved developed reserves aged five or more years		—			—		—
Proved undeveloped reserves-end of year		3,406			—		3,406

None of our proved undeveloped reserves at June 30, 2011 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our development programs were substantially funded from investment capital, bank debt and cash flow from operations. Based on our current expectations of our cash flow and development programs, we believe that we can fund the development of our proved undeveloped reserves associated with our waterflood operations from our cash flow from operations and, if needed, borrowings from our new credit facility. For a more detailed discussion of our pro forma liquidity position, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” For more information about our predecessor’s historical costs associated with the development of proved undeveloped reserves, please read Note 11 to the Historical Consolidated Financial Statements of our predecessor as of and for the year ended December 31, 2010.

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Production, Revenues and Price History

The following table sets forth information regarding combined net production of oil and certain price and cost information based on historical information for each of the periods presented:


					Mid-Con Energy I, LLC and
	Mid-Con Energy				Mid-Con Energy II, LLC
	Corporation				(combined)
	(consolidated)				Six
	Year		Year		Months		Year		Six Months
	Ended		Ended		Ended		Ended		Ended
	June 30,		June 30,		December 31,		December 31,		June 30,
	2008		2009		2009		2010		2010		2011

Production and operating data:
Net production volumes:
Oil (MBbls)		145		153		87		228		104		167
Natural gas (MMcf)		86		341		140		191		106		79
Total (MBoe)		159		210		110		260		121		180
Average net production (Boe/d)		437		575		602		710		666		986
Average sales price:(1)
Oil (per Bbl)	$	94.20	$	66.87	$	66.11	$	74.07	$	72.05	$	93.58
Natural gas (per Mcf)	$	7.17	$	6.37	$	5.33	$	7.44	$	7.59	$	8.28
Average price per Boe	$	89.78	$	59.06	$	59.07	$	70.69	$	68.58	$	90.46
Average unit costs per Boe:
Oil and natural gas production expenses	$	31.39	$	25.56	$	22.11	$	24.05	$	25.01	$	19.72
Production taxes	$	5.93	$	3.00	$	2.45	$	3.17	$	3.16	$	3.64
General and administrative and other	$	11.73	$	8.41	$	6.40	$	3.79	$	4.83	$	2.64
Depreciation, depletion and amortization	$	10.36	$	12.44	$	20.99	$	21.48	$	25.67	$	11.55


(1)		Prices do not include the effects of derivative cash settlements.

Development Activities

Since January 2010, we have undertaken an extensive program, consisting of drilling approximately 45 gross (26 net) development wells, mostly in our Southern Oklahoma core area. Approximately half of these development wells are injection wells, and the remainder are producing wells. The program has successfully increased injection and production. We expect that this program will be substantially completed by September 30, 2011, and should result in modest future capital expenditure requirements.

In our Northeastern Oklahoma core area, since early 2010, we have been engaged in an active acquisition and corresponding exploitation program in our Cleveland Field. We have acquired a number of leases adjacent to our legacy properties that have been operated since 1985. These acquisitions have resulted in an approximately 70% increase in our acreage position in the field. Our exploitation program has consisted of returning wells to production on acquired leases, recompleting shallower horizons and expanding waterflood operations to include previously unflooded reservoirs.

Effective June 1, 2011, we acquired two waterflood units, War Party I and II Units, in our Hugoton Basin core area. We are currently engaged in a workover program to return a number

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of inactive wells in these units to production, to optimize producing well rates and to increase injection. We expect that this program will be substantially completed by September 30, 2011.

The following table sets forth information with respect to development activities during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.


	Year Ended December 31,
	2008				2009				2010
	Gross		Net		Gross		Net		Gross		Net

Development wells:
Productive		4		2		7		2		21		13
Injection		2		2		1		1		10		5
Dry		—		—		—		—		4		2
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total wells:

Productive		4		2		7		2		21		13
Injection		2		2		1		1		10		5
Dry		—		—		—		—		4		2

Total		6		4		8		3		35		20

We are currently conducting multiple development activities, including the drilling of 3 gross (2 net) production wells. Because we focus primarily on secondary recovery, our drilling activity is not indicative of our development activity as is typical with oil and gas exploration and primary production companies. Additionally, we are in the process of completing a development program located in Carter and Love Counties, Oklahoma. The program consists of drilling approximately 55 gross (31 net) wells, with 45 gross (26 net) gross drilled as of the date of this offering, with a focus on improving the infrastructure of the waterfloods within our Southern Oklahoma core area. Also, we are in the process of completing approximately 50 gross (34 net) workovers in the Northeastern Oklahoma core area, consisting of approximately 25 gross (24 net) workovers in the Cleveland Field and approximately 25 gross (10 net) workovers in the Cushing Field. As of June 30, 2011, we were in the process of completing the installation of additional waterflood facilities in the Ardmore West Unit to activate infill injection wells completed in 2011.

Productive Wells

The following table sets forth information at June 30, 2011 relating to the productive wells in which we, on a pro forma basis, owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.


	Oil				Natural Gas				Injection
	Gross		Net		Gross		Net		Gross		Net

Operated		269		157		1		1		123		66
Non-operated		1		—		4		1		—		—

Total		270		157		5		2		123		66

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Developed Acreage

The following table sets forth information as of June 30, 2011 relating to our pro forma leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table. As of June 30, 2011 substantially all of our leasehold acreage was held by production.


	Developed Acreage
	Gross		Net

Southern Oklahoma		9,865		5,578
Northeastern Oklahoma		5,919		3,576
Hugoton Basin		4,658		3,079
Other		1,294		1,294

Total		21,736		13,527

Delivery Commitments

We will have no delivery commitments with respect to our production upon the closing of this offering.

Operations

General

We operated approximately 98% of our properties, as calculated on a Boe basis as of June 30, 2011. All of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. We engage independent contractors to provide all the equipment and personnel associated with these activities. We also retain independent contractors to perform conventional hydraulic fracturing services in order to increase well productivity in our waterflooding operations. Pursuant to a services agreement to be entered into in connection with the closing of this offering, our affiliate, Mid-Con Energy Operating, will provide certain services to us, including geological, engineering and administration.

Geological and Engineering Services

Mid-Con Energy Operating employs production and reservoir engineers, geologists and land specialists, as well as field production supervisors. Through the services agreement, we have the direct operational support of a staff of 23 petroleum professionals with significant technical expertise. We believe that this technical expertise, which includes extensive experience utilizing secondary recovery methods, particularly waterfloods, differentiates us from, and provides us with a competitive advantage over, many of our competitors. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement.”

Administrative Services

Mid-Con Energy Operating will also provide us with management, administrative and operational services under the services agreement. We will reimburse Mid-Con Energy Operating, on a cost basis, for the allocable expenses it incurs in performing these services. Mid-Con Energy Operating will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. For a detailed description of the administrative services provided by Mid-Con Energy Operating pursuant to the services

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agreement, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement.”

Oil and Natural Gas Leases

The typical oil lease agreement covering our properties provides for the payment of royalties to the mineral owner for all hydrocarbons produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from less than 10% to 33%, resulting in a net revenue interest to us ranging from 67% to 87.5%, or 83.8% on average, on a 100% working interest basis. Based on the standardized measure, our value-weighted average net revenue interest on our properties was approximately 81.8%, on a 100% working interest basis, based on our June 30, 2011 reserve report. Most of our leases are held by production and do not require lease rental payments.

Marketing and Major Customers

For the year ended December 31, 2010, and for the six months ended June 30, 2011, purchases by Sunoco Logistics accounted for approximately 76% and 89%, respectively, of our total sales revenues. Our production is marketed to Sunoco Logistics under renewable six-month marketing contracts with Mid-Con Energy Operating. By selling a substantial majority of our production to Sunoco Logistics under these contracts, we believe that we receive more favorable pricing than would otherwise be available to us if smaller amounts had been sold to several purchasers based on posted prices.

The loss of Sunoco Logistics or any of our other customers could temporarily delay production and sale of our oil and natural gas. If we were to lose Sunoco Logistics or any of our customers, we believe that under current market conditions, we could identify substitute customers to purchase the impacted production volumes. However, if Sunoco Logistics dramatically decreased or ceased purchasing oil from us, we may have difficulty finding substitute customers to purchase our production volumes at comparable rates. For a discussion of risks associated with our relationship with Sunoco Logistics, please read “Risk Factors—Risks Related to our Business—We are primarily dependent upon one customer for our production sales and we may experience a temporary decline in revenues and production if we lose that customer.”

Hedging Activities

We intend to enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flow and to reduce our exposure to short-term fluctuations in oil and natural gas prices. Our current commodity derivative contracts are primarily fixed price swaps (with collars) with NYMEX prices and option agreements. For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

Competition

We operate in a highly competitive environment for acquiring properties and securing trained personnel. Many of our competitors possess and employ financial resources substantially greater than ours, which can be particularly important in the areas in which we operate. Some of our competitors may also possess greater technical and personnel resources than us. As a result, our competitors may be able to pay more for productive oil properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to acquire and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

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We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment and services. In recent years, the United States onshore oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation programs.

Title to Properties

Prior to completing an acquisition of producing oil properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

We initially conduct only a review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Hydraulic Fracturing

Hydraulic fracturing has been a part of the completion process for the majority of the wells on our producing properties in Oklahoma and Colorado, and most of our properties are dependent on our ability to hydraulically fracture the producing formations. We are currently conducting hydraulic fracturing activities in our Northeastern Oklahoma and Southern Oklahoma core areas. All of our leasehold acreage is currently held by production from existing wells. Therefore, fracturing is not currently required to maintain this acreage but it will be required in the future to develop the majority of our proved behind pipe and proved undeveloped reserves associated with this acreage. Nearly all of our proved behind pipe and proved undeveloped reserves associated with future drilling and recompletion projects, or 32% of our total estimated proved reserves as of June 30, 2011, will be subject to hydraulic fracturing. Although the cost of each well will vary, on average approximately 12.5% of the total cost of drilling and completing a well is associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completing our wells are treated and are built into and funded through our normal capital expenditure budget. Of our $6.0 million of estimated maintenance capital expenditures for the year ended December 31, 2012, approximately $0.7 million is expected to be attributable to hydraulic fracturing.

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Almost all of our hydraulic fracturing operations are conducted on vertical wells. The fracture treatments on these wells are much smaller and utilize much less water than what is typically used on most of the shale gas wells that are being drilled throughout the United States. For example, a “typical” hydraulic fracture stimulation on a Marcellus shale well is pumped in five or more stages, utilizing a total of 4 million gallons of water and 1.5 million pounds of sand. In comparison, for our wells, a large hydraulic fracture stimulation on one of our new wells would be pumped in three stages utilizing a total of 50,000 gallons of water and 60,000 pounds of sand. Typical hydraulic fracture stimulation for a recompletion of one of our existing wells would be pumped in one stage, utilizing about 20,000 gallons of water and 15,000 pounds of sand.

We follow applicable industry standard practices and legal requirements for groundwater protection in our operations, subject to close supervision by state and federal regulators, which conduct many inspections during operations that include hydraulic fracturing. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well casing to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Fracture treating rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the treating string and, where applicable, the immediate annulus to the treating string. Hydraulic fracturing operations would be shut down if an abrupt change occurred in the treating pressure or annular pressure.

Regulations applicable to our operating areas do not currently require, and we do not currently evaluate, the environmental impact of typical additives used in fracturing fluid. We note, however, that approximately 98% of the hydraulic fracturing fluids we use are made up of water and sand.

We minimize the use of water and dispose of it in a way that minimizes the impact to nearby surface water by disposing excess water and water that is produced back from the wells into approved disposal or injection wells. We currently do not intentionally discharge water to the surface.

To our knowledge, there have not been any incidents, citations or suits related to environmental concerns from our fracturing operations.

Surface spills and leaks are controlled, contained and remediated in accordance with the applicable requirements of state oil and gas commissions, as well as any Spill Prevention, Control and Countermeasures (SPCC) plans we maintain in accordance with EPA requirements. This would include any action up to and including total abandonment of the wellbore.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean up costs stemming from a sudden and accidental pollution event. We may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “—Environmental Matters and Regulation—Water Discharges.” For related risks to our unitholders, please read “Risk Factors—Risks Related to Our Business—Federal and State legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

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Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, tribal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (v) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of 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, the U.S. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, we can provide no assurance that we will not incur substantial costs in the future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition and results of operations.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their respective implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration,

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development, and production of oil, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. However, it is possible that certain oil exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third-parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease, or operate numerous properties that have been used for oil and/or natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into waters in the United States. The discharge of pollutants into federal or state waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state or tribal agency that has been delegated authority for the program by the EPA. Federal, state and tribal regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended (the “OPA”), amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst case discharge of oil into waters of the United States.

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The Safe Drinking Water Act (the “SDWA”) and analogous state laws impose requirements relating to our underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations relating to permitting, testing, monitoring, record-keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water. We currently own and operate a number of injection wells, used primarily for reinjection of produced waters that are subject to SDWA requirements.

We employ conventional hydraulic fracturing techniques to increase the productivity of certain of our properties. This commonly used process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. The U.S. Congress is considering legislation to amend the federal SDWA to require the disclosure of chemicals used by the oil and natural gas industry in connection with conventional hydraulic fracturing. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level, and could make it easier for third parties to initiate legal proceedings based on allegations that chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil and surface water. In addition, the EPA has recently asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA’s Underground Injection Program and has begun the process of drafting guidance documents on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel fuel. In addition, a number of other federal agencies are also analyzing a variety of environmental issues associated with hydraulic fracturing and could potentially take regulatory actions that impair our ability to conduct hydraulic fracturing activities. Some states, including Texas, and local governments have adopted, and others are considering, regulations to restrict and regulate hydraulic fracturing. For example, the State of Arkansas recently required certain oil and gas operators to cease water injection associated with hydraulic fracturing activities due to a concern that the injection was related to increased earthquake activity. Any similar actions by the State of Oklahoma could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of our projects.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues. For example, on July 28, 2011, the EPA proposed four sets of new rules which, if adopted, will impose stringent new standards for air emissions from oil and gas development and production operations, including crude oil storage tanks with a throughput of at least 20 barrels per day, condensate storage tanks with a throughput of at least 1 barrel per day, completions of new hydraulically fractured natural gas wells, and recompletions of existing natural gas wells that are fractured or refractured. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action by February 28, 2012. If adopted, these rules may require us to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. Though the regulations ultimately adopted may change, we do not believe that such requirements will have a material adverse effect on our operations.

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Climate Change

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, or CO ₂ , methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. In addition, in October 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 8, 2010, the EPA expanded this GHG reporting rule to include onshore oil production, processing, transmission, storage, and distribution facilities, with reporting beginning in 2012 for emissions occurring in 2011. On August 4, 2011, the EPA issued a proposed rule amending and clarifying certain provisions of the reporting rule and extended the 2012 reporting deadline to September 2012. We are required to report under this rule but we do not believe that our compliance costs associated with GHG reporting will be material.

In addition, both houses of U.S. Congress have previously considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil that we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur in areas where we operate, they could have an adverse effect on our assets and operations.

National Environmental Policy Act

Oil exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA 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 analyses 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. Currently, we have no

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exploration and production activities on federal lands. However, for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA may be required. This process has the potential to delay the development of oil projects.

Endangered Species Act

The Endangered Species Act, as amended, or ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While our facilities are located in areas that are not currently designated as habitat for endangered or threatened species, the designation of previously unidentified endangered or threatened species habitats could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

OSHA

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are 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 oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in U.S. Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, we do not believe that compliance with these laws will have a material adverse impact on us.

The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

State Regulation

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and

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reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:


	•	the location of wells;

	•	the method of drilling and casing wells;

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

	•	the permitting and operating of injection wells;

	•	the plugging and abandoning of wells; and

	•	notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil properties. Some states, like Oklahoma (where most of our properties are currently located), allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil we can produce from our wells or limit the number of wells or the locations at which we can drill.

States impose severance taxes and enforce requirements for obtaining drilling permits. For example, the State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties and an excise tax of 0.095%. A portion of our wells in the State of Oklahoma currently receive a reduced production tax rate due to the Enhanced Recovery Project Gross Production Tax Exemption. Additionally, production tax rates vary by state. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future.

Employees

The officers of our general partner will manage our operations and activities. However, neither we, our subsidiary, nor our general partner have employees. Immediately prior to the closing of this offering, our general partner will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will perform services for us, including the operation of our properties. Please read “Certain Relationships and Related Party Transactions —Agreements Governing the Transactions—Services Agreement.” Immediately after the closing of this offering, we expect that Mid-Con Energy Operating will have approximately 60 employees performing services for our operations and activities. We believe that Mid-Con Energy Operating has a satisfactory relationship with those employees.

Offices

Our headquarters are located in Dallas, Texas at . For our principal operating office, we currently lease approximately 10,000 square feet of office space in Tulsa, Oklahoma at 2431 East 61st Street, Suite 850, Tulsa, Oklahoma 74136. Our lease expires on June 30, 2012.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT

Management of Mid-Con Energy Partners, LP

Our general partner will manage our operations and activities on our behalf through its executive officers and board of directors. References in this prospectus to our officers and board of directors therefore refer to the officers and board of directors of our general partner. Our general partner is owned by the Founders and Yorktown and is controlled by the Founders.

Our general partner is not elected by our unitholders and will not be subject to re-election on an annual or other continuing basis in the future. In addition, our unitholders will not be entitled to elect the directors of our general partner, each of whom will be appointed by the Founders, or directly or indirectly participate in our management or operations. Further, our partnership agreement contains provisions that substantially restrict the fiduciary duties that our general partner would otherwise owe to our unitholders under Delaware law. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Upon the closing of this offering, we expect that the board of directors of our general partner will have seven members. The NASDAQ listing rules do not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members, all of whom are required to meet the independence and experience standards established by the NASDAQ listing rules and SEC rules, subject to certain transitional relief during the one-year period following the consummation of this offering. Please see “—Director Independence” and “—Committees of the Board of Directors” below.

All of the executive officers of our general partner are also officers and/or directors of the Mid-Con Affiliates. The executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of the Mid-Con Affiliates. In addition, employees of Mid-Con Energy Operating will provide management, administrative and operating services to us pursuant to the services agreement, but they will also provide these services to the Mid-Con Affiliates. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Services Agreement.” We expect the executive officers of our general partner and other shared personnel to devote a sufficient amount of time to our business and affairs as is necessary for the proper management and conduct of our business and operations. However, we anticipate that, for the foreseeable future, the executive officers of our general partner and other shared personnel will also devote substantial amounts of their time to managing the businesses of the Mid-Con Affiliates.

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Directors and Executive Officers of Mid-Con Energy GP, LLC

The following table sets forth certain information regarding the current directors and executive officers of our general partner upon consummation of this offering.


Name	Age		Position with Mid-Con Energy GP, LLC

S. Craig George		59	Executive Chairman of the Board
Charles R. “Randy” Olmstead		63	Chief Executive Officer and Director
Jeffrey R. Olmstead		34	President, Chief Financial Officer and Director
David A. Culbertson		46	Vice President and Chief Accounting Officer
Robbin W. Jones		52	Vice President and Chief Engineer
Peter A. Leidel		55	Director
Cameron O. Smith		61	Director
Robert W. Berry		87	Director
Peter Adamson, III		70	Director

The members of our general partner’s Board of Directors are appointed for one-year terms by the Founders and hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been appointed and qualified. The executive officers of our general partner serve at the discretion of the board of directors. All of our general partner’s executive officers also serve as executive officers of the Mid-Con Affiliates. Charles R. Olmstead and Jeffrey R. Olmstead are father and son, respectively. There are no other family relationships among our general partner’s executive officers and directors. In evaluating director candidates, the Founders will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board to fulfill their duties. While the Founders may consider diversity among other factors when considering director nominees, they do not apply any specific diversity policy with regard to selecting and appointing directors to the board of directors. However, when appointing new directors, the Founders will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, and the diversity of these attributes for the board of directors as a whole.

S. Craig George will serve as Executive Chairman of the board of directors of our general partner. Mr. George has been a member of the board of directors of Mid-Con Energy III, LLC, Mid-Con Energy IV, LLC and Mid-Con Energy Operating since July 2011. Mr. George has been a member of the board of directors of Mid-Con Energy I, LLC and Mid-Con Energy Operating since its formation in 2004 and of Mid-Con Energy II, LLC since its formation in 2009. From 1991 to 2004, Mr. George served in various executive positions at Vintage Petroleum, Inc., including President, Chief Executive Officer and as a member of the board of directors. In 1981, Mr. George joined Santa Fe Minerals, Inc. where he served until 1991 in executive positions including Vice President of Domestic Operations and Vice President-International. From 1975-1981, Mr. George held engineering and management positions with Amoco Production Company. Mr. George is a graduate of Missouri University of Science and Technology, with a Bachelor of Science degree in Mechanical Engineering, and of Aquinas Institute, with a Master of Arts in Theology. We believe that Mr. George’s service as the chief executive officer and a director of a publicly traded exploration and production company brings important experience and leadership skill to the board of directors of our general partner.

Charles R. “Randy” Olmstead will serve as Chief Executive Officer and as a member of the board of directors of our general partner. Mr. Olmstead has been Chief Executive Officer and Chairman of the board of directors of Mid-Con Energy III, LLC and Mid-Con Energy IV, LLC since July 2011. Mr. Olmstead has served as President, Chief Financial Officer and Chairman of

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the board of directors of Mid-Con Energy I, LLC since its formation in 2004 and of Mid-Con Energy II, LLC since its formation in 2009. He has been President, Chief Financial Officer and Chairman of the board of directors of Mid-Con Energy Operating since its incorporation in 1986. Prior to that, Mr. Olmstead was general manager for LB Jackson Drilling Company from 1978 to 1980 and worked in public accounting for Touche Ross & Co. from 1974 to 1978 as an oil and gas tax consultant. Mr. Olmstead is a certified public accountant. Mr. Olmstead graduated from the University of Oklahoma with Bachelors of Business Administration degrees in finance and accounting before serving three years in the US Navy. We believe that Mr. Olmstead’s extensive experience in the oil and gas industry brings important experience and leadership skill to the board of directors of our general partner.

Jeffrey R. Olmstead will serve as President, Chief Financial Officer and as a member of the board of directors of our general partner. Mr. Olmstead has been a member of the board of directors of Mid-Con Energy III, LLC and President, Chief Financial Officer and a member of the board of directors of Mid-Con Energy IV, LLC since July 2011. Mr. Olmstead has been a member of the board of directors of Mid-Con Energy I, LLC and Mid-Con Energy Operating since 2007 and of Mid-Con Energy II, LLC since its formation. Mr. Olmstead previously served as Chief Financial Officer and Vice President of Primexx Energy Partners, Ltd., a privately held exploration and production company, from May 2010 until July 2011. From August 2006 until May 2010, Mr. Olmstead served as an Assistant Vice President at Bank of Texas/Bank of Oklahoma where, in the bank’s energy group, he managed a portfolio of approximately 20 oil and gas borrowers with total commitments of approximately $250 million. Mr. Olmstead is a graduate of Vanderbilt University, with a Bachelor of Engineering degree in Electrical Engineering and Math, and of the Owen School of Business at Vanderbilt University, with a Master of Business Administration. We believe that Mr. Olmstead’s experience in energy-related finance brings important experience and leadership skill to the board of directors of our general partner.

David A. Culbertson will serve as Vice President and Chief Accounting Officer of our general partner. Mr. Culbertson has served as Controller of Mid-Con Energy I, LLC since 2006 and of Mid-Con Energy II, LLC since its formation in 2009. He has also supervised the accounting function for affiliates of our predecessor. Prior to joining us in 2006, Mr. Culbertson served in various accounting positions with Vintage Petroleum from 2003-2006, The Williams Companies from 1999-2003 and Samson Resources from 1989-1999. Mr. Culbertson is a graduate of Oklahoma State University, with a Bachelor of Business Administration degree in accounting, and of the University of Tulsa, with a Master of Business Administration. He is a Certified Public Accountant.

Robbin W. Jones, P.E. will serve as Vice President and Chief Engineer of the General Partner. Mr. Jones was elected President of Mid-Con Energy III, LLC in July 2011. Mr. Jones has been a Vice President and Chief Operating Officer of the predecessor and affiliate companies since 2007. Mr. Jones served as reservoir engineer and manager of our Houston office from March 2005, when he joined our predecessor, until 2007. Mr. Jones served as manager at Schlumberger Data & Consulting Services from 2004 to 2005 and has twenty years of engineering experience in all phases of waterflood development and management working for Enserch Exploration, Caruthers Producing, Diamond Energy Operating Company and Equinox Oil Company. Mr. Jones received a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. He is a Registered Professional Engineer in the states of Louisiana and Texas and a member of the Society of Petroleum Engineers.

Peter A. Leidel will serve as a member of the board of directors of our general partner. Mr. Leidel is a founder and principal of Yorktown Partners LLC, which was established in September 1990. Yorktown Partners LLC is the manager of private equity partnerships that invest in the energy industry. Mr. Leidel has been a member of the board of directors of Mid-Con Energy III, LLC, Mid-Con Energy IV, LLC and Mid-Con Energy Operating since July 2011. Mr. Leidel has been a member of the board of directors of Mid-Con Energy I, LLC since its

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formation in 2004 and of Mid-Con Energy II, LLC since its formation in 2009. Previously, he was a partner of Dillon, Read & Co. Inc., held corporate treasury positions at Mobil Corporation and worked for KPMG and for the U.S. Patent and Trademark Office. Mr. Leidel is a director of certain non-public companies in the energy industry in which Yorktown holds equity interests. Mr. Leidel is a graduate of the University of Wisconsin, with a Bachelor of Business Administration degree in accounting and of the Wharton School at the University of Pennsylvania, with a Master of Business Administration. We believe that Mr. Leidel’s extensive financial and private equity experience, as well as his experience on the boards of directors of numerous private energy companies, bring substantial leadership skill and experience to the board of directors.

Cameron O. Smith will serve as a member of the board of directors of our general partner. Mr. Smith founded and from 1992 to 2008, served as a Senior Managing Director of COSCO Capital Management LLC, an investment bank focused on private oil and gas corporate and project financing until Rodman & Renshaw, LLC, a full service investment bank, purchased the business and assets of COSCO Capital Management LLC. From 2008 until December 2009, Mr. Smith served as a Senior Managing Director of Rodman & Renshaw, LLC and as Head of The Rodman Energy Group, a sector vertical within Rodman & Renshaw, LLC. Mr. Smith retired from The Rodman Energy Group in December 2009. Mr. Smith founded and ran Taconic Petroleum Corporation, an exploration company headquartered in Tulsa, Oklahoma from 1978 to 1991. Mr. Smith served as exploration geologist, officer and director of several family and client partnerships from 1975 to 1985. Mr. Smith attended Princeton University receiving an A.B. in Art History in 1972 and Pennsylvania State University receiving a Master of Science in Geology in 1975. We believe that Mr. Smith’s extensive financial and private equity experience, as well as his experience in the oil and natural gas industry generally, bring substantial leadership skill and experience to the board of directors.

Robert W. Berry will serve as a member of the board of directors of our general partner. Mr. Berry is founder, Chief Executive Officer and President of W. Berry, Inc., Empress Gas Corp. Ltd., R.W. Berry Canada, Inc. and Berry Ventures, Inc. which produce oil and gas in Oklahoma, Texas, Arkansas, North Dakota and Canada, and has served in these positions for more than the past five years. Mr. Berry has drilled and discovered numerous oil fields in Texas, North Dakota and Canada since working for Amerada Petroleum Corporation as a geologist. Mr. Berry graduated from the University of Oklahoma with a Bachelor of Science degree in Geology. We believe that Mr. Berry’s extensive experience in the oil and gas industry brings substantial leadership skill and experience to the board of directors of our general partner.

Peter Adamson, III will serve as a member of the board of directors of our general partner. Mr. Adamson is a founder of Adams Hall Asset Management LLC, a Tulsa, Oklahoma based registered investment advisor with over $1 billion under management. Prior to forming Adams Hall in 1997, Mr. Adamson was an owner and principal of Houchin, Adamson & Co., Inc., a registered broker-dealer formed in 1980. Mr. Adamson is founding co-investor and advisor to Horizon Well Logging, a leading provider of geological field services. Mr. Adamson serves on the advisory board of the Michel F. Price College of Business at the University of Oklahoma and serves on the University of Oklahoma asset oversight committee. Mr. Adamson received his Bachelor of Business Administration degree in accounting from the University of Oklahoma. We believe that Mr. Adamson’s extensive financial and investing experience bring substantial leadership skill and experience to the board of directors.

Reimbursement of Expenses of Our General Partner

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partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Upon the closing of this offering, we will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us. We will reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated to us. Mid-Con Energy Operating will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions.” For further discussion of the reimbursements that Mid-Con Energy Operating will be entitled to receive relating to services provided in connection with the services agreement, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement.”

Director Independence

Messrs. Berry and Adamson meet the independence standards established by the NASDAQ listing rules. In accordance with the NASDAQ listing rules, one additional independent director must be appointed within twelve months of listing on the NASDAQ Global Market.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that our board of directors or an appointed committee will approve equity grants to directors and employees. As noted above, the NASDAQ listing rules do not require a listed limited partnership to establish a compensation committee or a nominating and corporate governance committee.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NASDAQ listing rules and rules of the SEC. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary. Initially, Messrs. Berry and Adamson will serve on the audit committee.

Conflicts Committee

Our partnership agreement requires that at least two independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest (including certain transactions with affiliates of our general partner, including the Mid-Con Affiliates) and that it determines to submit to the conflicts committee for review. We expect that additional independent directors will

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serve on the conflicts committee as they are appointed. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including the Mid-Con Affiliates, and must meet the independence standards established by the NASDAQ listing rules and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.” Initially, Messrs. Berry and Adamson will serve on the conflicts committee.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in a Chairman of the Board. Although our Chief Executive Officer currently does not serve as Chairman of the Board of Directors of our general partner, we currently have no policy prohibiting our current or any future chief executive officer from serving as Chairman of the Board. The board of directors, in recognizing the importance of its ability to operate independently, determined that separating the roles of Chairman of the Board and Chief Executive Officer is advantageous for us and our unitholders. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director could enhance understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations, and ultimately improves the ability of the board of directors to perform its oversight role.

The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while retaining responsibility for oversight of our executive officers in that regard. Our executive officers will offer an enterprise-level risk assessment to the board of directors at least once every year.

Compensation of Executive Officers

We and our general partner were formed in July 2011. As such, neither we nor our general partner accrued any obligations with respect to compensation for directors and executive officers for the fiscal year ended December 31, 2010, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. We have not paid or accrued any amounts for compensation for directors and executive officers for the 2010 fiscal year.

The executive officers of our general partner are also executive officers and/or directors of the Mid-Con Affiliates. We expect these executive officers to devote a sufficient amount of time to our business and affairs as is necessary for the proper management and conduct of our business and operations. However, we anticipate that these executive officers will devote substantial amounts of time to managing the businesses of the Mid-Con Affiliates. We expect that the executive officers of our general partner will devote their business time to our business as follows: S. Craig George, Charles R. Olmstead, Jeffrey R. Olmstead, David A. Culbertson and Robbin W. Jones will devote approximately 80%, 66 2 / 3 %, 80%, 66 2 / 3 % and 50% of their business time, respectively. The amount of time that each of our executive officers devotes to our business will be subject to change depending on our activities, the activities of the Mid-Con Affiliates to which they also provide services, and any acquisitions or dispositions made by us or the Mid-Con Affiliates.

Because the executive officers of our general partner are employees of Mid-Con Energy Operating, their compensation will be paid by Mid-Con Energy Operating and we will reimburse

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Mid-Con Energy Operating pursuant to the services agreement for the portion of such compensation allocable to us. Please see “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement.”

The executive officers of our general partner, as well as the employees of Mid-Con Energy Operating who provide services to us, may participate in employee benefit plans and arrangements sponsored by Mid-Con Energy Operating, including plans that may be established in the future.

We anticipate that, following the closing of this offering, our general partner will adopt a long-term incentive plan and the board of directors of our general partner may grant awards to our executive officers, key employees and our outside directors pursuant to this long-term incentive plan. However, the board has not made any determination as to the number of awards, the type of awards or whether or when any awards would be granted. The long-term incentive plan is described in further detail below.

Compensation Committee Interlocks and Insider Participation

The NASDAQ listing rules do not require a listed limited partnership to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.

Compensation Discussion and Analysis

General

We do not directly employ any of the persons responsible for managing our business. Our general partner’s executive officers will manage and operate our business as part of the services provided by Mid-Con Energy Operating to our general partner under the services agreement. All of our general partner’s executive officers and other employees necessary to operate our business will be employed and compensated by Mid-Con Energy Operating, subject to reimbursement by our general partner. The compensation for all of our executive officers will be indirectly paid by us to the extent provided for in the partnership agreement because we will reimburse our general partner for payments it makes to Mid-Con Energy Operating. Please see “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Services Agreement” and “—Reimbursement of Expenses of Our General Partner.”

We and our general partner were formed in July 2011; therefore, we incurred no cost or liability with respect to the compensation of our executive officers, nor has our general partner accrued any liabilities for management incentive or retirement benefits for our executive officers for the fiscal year ended December 31, 2010 or for any prior periods. Accordingly, we are not presenting any compensation information for historical periods.

The Founders, as the controlling members of our general partner, will have responsibility and authority for compensation-related decisions for our Chief Executive Officer and, upon consultation and recommendations by our Chief Executive Officer, for our other executive officers. Equity grants pursuant to our long-term incentive plan will also be administered by the Founders. Our predecessor historically compensated its executive officers primarily with base salary and cash bonuses.

In connection with this offering, the Founders may consider the compensation structures and levels that they believe will be necessary for executive recruitment and retention for us as a public company. The Founders expect to examine the compensation practices of our peer companies and may also review compensation data from the exploration and production industry generally.

Our general partner may also grant equity-based awards to our executive officers pursuant to a long-term incentive plan which our general partner intends to adopt as described below. However, no determination has been made as to the number of awards, the type of awards or

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whether or when any awards would be granted under this plan. We expect that annual bonuses payable to our executive officers will be determined based on our financial performance as measured across a fiscal year. However, incentive compensation in respect of services provided to us will not be tied in any way to the performance of entities other than our partnership. Specifically, any performance metrics will not be tied in any way to the performance of the Mid-Con Affiliates or any other affiliate of ours.

Although we will bear an allocated portion of Mid-Con Energy Operating’s costs of providing compensation and benefits to Mid-Con Energy Operating employees who serve as the executive officers of our general partner and provide services to us, we will have no control over such costs and will not establish or direct the compensation policies or practices of Mid-Con Energy Operating. Mr. Charles R. Olmstead previously made all compensation related-decisions for Mid-Con Energy Operating. Mr. Olmstead determined the overall compensation philosophy and set the final compensation of the executive officers of our predecessors without the assistance of a compensation consultant. Mr. Olmstead will continue to make all compensation-related decisions for those Mid-Con Energy Operating employees who do not perform services for us.

Mid-Con Energy Operating does not maintain a defined benefit or pension plan for its executive officers or employees because it believes such plans primarily reward longevity rather than performance. Mid-Con Energy Operating provides a basic benefits package to all its employees, which includes a 401(k) plan and health, dental, and basic term life insurance, and personal accident and short and long-term disability coverage. Employees provided to us under the services agreement will be entitled to the same basic benefits.

Awards under Our Long-Term Incentive Plan

In connection with this offering, the board of directors of our general partner intends to adopt a long-term incentive plan for employees, officers, consultants and directors of our general partner and affiliates, including Mid-Con Energy Operating, who perform services for us. The long-term incentive plan will provide for the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards as described below.

Compensation of Directors

Officers or employees of our general partner or its affiliates, including Mid-Con Energy Operating, who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that each director who is not an officer or employee of our general partner or its affiliates will receive an annual retainer, compensation for attending meetings of the board of directors, as well as committee meetings and an equity grant pursuant to our long-term incentive plan. The amount of compensation to be paid to our general partner’s non-employee directors has not yet been determined.

In addition, each director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Long-Term Incentive Plan

Our general partner intends to adopt a long-term incentive plan for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, who perform services for us.

The description of the long-term incentive plan set forth below is a summary of the anticipated material features of the plan. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the plan. Additionally, our general

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partner is still in the process of implementing the plan and, accordingly, this summary is subject to change prior to the effectiveness of the registration statement of which this prospectus is a part.

We expect that the long-term incentive plan will consist of the following components: restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation, at the discretion of the board, to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan will initially limit the number of units that may be delivered pursuant to vested awards to common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner or a designated committee thereof, which we refer to as the plan administrator. The plan administrator may also delegate its duties as appropriate.

Amendment or Termination of Long-Term Incentive Plan

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest to occur of (i) the date on which all common units available under the plan for grants have been paid to participants, (ii) termination of the plan by the plan administrator or (iii) the date years following its date of adoption.

Restricted Units

A restricted unit is a common unit that vests over a period of time, and during that time, is subject to forfeiture. Forfeiture provisions lapse at the end of the vesting period. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

We intend the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, it is expected that plan participants will not pay any consideration for restricted units they receive, and we will receive no remuneration for the restricted units.

Phantom Units

A phantom unit is a notional common unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives.

We intend the issuance of any common units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, it is

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expected that plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the common units.

Unit Options

The long-term incentive plan will permit the grant of options covering common units. Unit options represent the right to purchase a designated number of common units at a specified price. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options will have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights

The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights will have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

Distribution Equivalent Rights

The plan administrator may, in its discretion, grant distribution equivalent rights, or DERs, in tandem with phantom unit awards or other awards under the long-term incentive plan. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period that the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

Other Unit-Based Awards

The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

Unit Awards

The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service

The plan administrator may provide that awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a “change of control” (as defined in the long-term incentive plan) of us or our general partner. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Source of Common Units

Common units to be delivered pursuant to awards under the long-term incentive plan may be common units already owned by our general partner or us or acquired by our general partner in the open market from any other person, directly from us or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term

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incentive plan, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Relation of Compensation Policies and Practices to Risk Management

We anticipate that our compensation policies and practices will be designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds which qualify them for additional compensation. From a risk management perspective, our policy will be to conduct our commercial activities in a manner intended to control and minimize the potential for unwarranted risk taking. We expect to also routinely monitor and measure the execution and performance of our projects and acquisitions relative to expectations. Additionally, our compensation arrangements may include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our code of conduct.

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SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common and subordinated units that, upon the consummation of this offering and the related transactions and assuming the underwriters do not exercise their option to purchase additional common units, will be owned by:


	•	beneficial owners of more than 5% of our common units;

	•	each executive officer of our general partner; and

	•	all directors, director nominees and executive officers of our general partner as a group.

Percentage of

Total Common

Common

Common Units

Subordinated

and Subordinated

Units to be

to be

Units to be

Beneficially

Name of Beneficial Owner(1)

Owned

Yorktown Energy Partners VI, L.P.(1)(2)

Yorktown Energy Partners VII, L.P.(1)(3)

Yorktown Energy Partners VIII, L.P.(1)(4)

Charles R. Olmstead(5)

Jeffrey R. Olmstead(5)

Robbin W. Jones(5)

David A. Culbertson(5)

S. Craig George(5)

Peter A. Leidel(5)(6)

Peter Adamson, III(5)

Robert W. Berry(5)

Cameron O. Smith(5)

All named executive officers, directors and director nominees as a group ( persons)(5)


(1)		Has a principal business address of 410 Park Avenue, 19th Floor, New York, New York 10022.

(2)		Yorktown VI Company LP is the sole general partner of Yorktown Energy Partners VI, L.P. Yorktown VI Associates LLC is the sole general partner of Yorktown VI Company LP. As a result, Yorktown VI Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VI, L.P. Yorktown VI Company LP and Yorktown VI Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VI, L.P. in excess of their pecuniary interests therein.

(3)		Yorktown VII Company LP is the sole general partner of Yorktown Energy Partners VII, L.P. Yorktown VII Associates LLC is the sole general partner of Yorktown VII Company LP. As a result, Yorktown VII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP and Yorktown VII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VII, L.P. in excess of their pecuniary interests therein.

(4)		Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP and Yorktown VIII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VIII, L.P. in excess of their pecuniary interests therein.

(5)		c/o Mid-Con Energy GP, LLC, 2431 E. 61st Street, Suite 850 Tulsa, Oklahoma 74136.

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(6)		Includes attribution of shares held by Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P. and their affiliates. Mr. Leidel disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.

Mid-Con Energy GP, LLC, our general partner, owns all of our incentive distribution rights and a 2.0% general partner interest in us. The following table sets forth the beneficial ownership of equity interests in our general partner.


	Class A Member			Class B Member
Name of Beneficial Owner	Interest(c)			Interest(c)

Charles R. Olmstead(a)		33.33	%		—
S. Craig George(a)		33.33	%		—
Jeffrey R. Olmstead(a)		33.33	%		—
Yorktown Energy Partners VI, L.P.(b)(d)		—				%
Yorktown Energy Partners VII, L.P.(b)(e)		—				%
Yorktown Energy Partners VIII, L.P.(b)(f)		—				%


(a)		c/o Mid-Con Energy GP, LLC, 2431 E. 61st Street, Suite 850 Tulsa, Oklahoma 74136.

(b)		Has a principal business address at 410 Park Avenue, 19th Floor, New York, New York 10022.

(c)		Our general partner has two classes of member interests. S. Craig George, Charles R. Olmstead and Jeffrey R. Olmstead will each own one-third of the Class A member interests in our general partner. Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., and Yorktown Energy Partners VIII, L.P., will own %, % and %, respectively, of the Class B member interests in our general partner. The Class B member interests have no voting rights. As a result, Messrs. Olmstead, George, and Olmstead, as holders of all of the Class A member interests, will control our general partner and be entitled to appoint its entire board of directors. The Class A member interests and the Class B member interests, each in the aggregate, are entitled to receive 50% of the distributions made by our general partner, which will include proceeds from the distributions our general partner receives in respect of its 2.0% general partner interest in us and the incentive distribution rights.

		Messrs. Olmstead, George, and Olmstead, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the interests in us held by our general partner. Each of Messrs. Olmstead, George and Olmstead disclaims beneficial ownership of these securities in excess of his pecuniary interest in such securities.

(d)		Yorktown VI Company LP is the sole general partner of Yorktown Energy Partners VI, L.P. Yorktown VI Associates LLC is the sole general partner of Yorktown VI Company LP. As a result, Yorktown VI Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VI, L.P. Yorktown VI Company LP and Yorktown VI Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VI, L.P. in excess of their pecuniary interests therein.

(e)		Yorktown VII Company LP is the sole general partner of Yorktown Energy Partners VII, L.P. Yorktown VII Associates LLC is the sole general partner of Yorktown VII Company LP. As a result, Yorktown VII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP and Yorktown VII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VII, L.P. in excess of their pecuniary interests therein.

(f)		Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP and Yorktown VIII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VIII, L.P. in excess of their pecuniary interests therein.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Upon the consummation of this offering, assuming the underwriters do not exercise their option to purchase additional common units, the Founders and Yorktown will own common units and subordinated units representing an approximate % limited partner interest in us. In addition, our general partner will own a 2.0% general partner interest in us, evidenced by general partner units, and all of our incentive distribution rights. These percentages do not reflect any common units that may be issued under the long-term incentive plan that our general partner expects to adopt prior to the closing of this offering.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s length negotiations.


*Formation Stage*

The consideration received by our general partner and the Contributing Parties prior to or in connection with this offering		• common units;

		• subordinated units;

		• general partner units;

		• all of our incentive distribution rights; and

		• approximately $ million in cash.

		To the extent the underwriters exercise their option to purchase up to an additional common units, the number of common units issued to the Contributing Parties (as reflected in the first bullet above) will decrease by the aggregate number of common units purchased by the underwriters pursuant to such exercise. The net proceeds from any exercise of such option will be used to distribute additional cash consideration to the Contributing Parties in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at the closing of this offering.

*Operational Stage*

Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to our unitholders pro rata, including the Contributing Parties as the holder of approximately % of our limited partner interests, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions,

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		up to a maximum of 23% of the distributions above the highest target distribution level.

		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $ million on its general partner units and the Contributing Parties would receive an annual distribution of approximately $ million on their common units and subordinated units.

Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all direct and indirect expenses it incurs and payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Withdrawal or removal of our general partner		In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest for a cash payment equal to the fair market value of such interest. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us for its fair market value.

*Liquidation Stage*

Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with Affiliates in Connection with the Transactions

In connection with the closing of this offering, we, our general partner and its affiliates will enter into the various documents and agreements that will affect the transactions described in “Prospectus Summary—Formation Transactions and Partnership Structure” including the vesting of assets in, and the assumption of liabilities by, us and the application of the net proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently,

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are not the result of arm’s length negotiations. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets to us, will be paid from the proceeds of this offering.

Services Agreement

Contemporaneously with the closing of this offering, we will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will provide management, administrative and operating services to us. Under the services agreement, we will reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. Mid-Con Energy Operating will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. Mid-Con Energy Operating will not be liable to us for its performance of, or failure to perform, services under the services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

Merger Agreement

In connection with the closing of this offering, we will enter into a merger agreement pursuant to which Mid-Con Energy I, LLC and Mid-Con Energy II, LLC will merge into our subsidiary, Mid-Con Energy Properties. The merger agreement will provide for the Contributing Parties, as the owners of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, to receive consideration that includes a combination of common units, subordinated units and cash from the proceeds of this offering. All of the transaction expenses incurred in connection with these transactions will be paid from proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with our general partner pursuant to which our general partner will indemnify us against (i) title defects, subject to a $ per claim de minimis exception, for amounts in excess of a $ million threshold, and (ii) income taxes attributable to pre-closing operations as of the closing date of this offering. Such indemnification obligation will (i) survive for years after the closing of this offering with respect to title, and (ii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. We will indemnify our general partner and its affiliates against certain potential environmental claims, losses and expenses associated with the operation of our business that arise after the consummation of this offering. Any or all of the provisions of the omnibus agreement will terminate upon a change of control of us or our general partner.

Other Transactions with Related Persons

Certain Derivative Transactions

At June 30, 2011, we had a receivable from J&A Oil Company, LLC of $62,000 arising from shared derivative transactions that we jointly entered into with financial institutions.

Review, Approval or Ratification of Transactions with Related Persons

We expect that we will adopt a Code of Business Conduct and Ethics that will set forth our policies for the review, approval and ratification of transactions with related persons. Upon our adoption of a Code of Business Conduct and Ethics, a director would be expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such

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conflict or potential conflict will be addressed in accordance with our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors.

Upon our adoption of a Code of Business Conduct and Ethics, any executive officer of our general partner will be required to avoid conflicts of interest unless approved by the board of directors.

The board of directors of our general partner will have a standing conflicts committee comprised of at least two independent directors. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions of oil and natural gas properties from the Mid-Con Affiliates or any other affiliates of the general partner. In addition to acquisitions from affiliates of our general partner, the board of directors of our general partner will also determine whether to seek conflicts committee approval to the extent we act jointly to acquire additional oil and natural gas properties with affiliates of our general partner. In the case of any sale of equity or debt by us to an owner or affiliate of an owner of our general partner, we anticipate that our practice will be to obtain the approval of the conflicts committee of the board of directors of our general partner for the transaction. The conflicts committee will be entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.

The Mid-Con Affiliates or other affiliates of our general partner are free to offer properties to us on terms they deem acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by affiliates of our general partner. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flow, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.

We expect that the Mid-Con Affiliates or other affiliates of our general partner will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed purchase price of any assets it may offer to us in future periods. In addition to these factors, given that the affiliates of our general partner will own an approximate % limited partner interest in us following the consummation of this offering and through their interests in our general partner, will be entitled to distributions with respect to the incentive distribution rights, they may consider the potential positive impact on their underlying investment in us by causing the Mid-Con Affiliates, who they control, to offer properties to us at attractive purchase prices. Likewise, the affiliates of our general partner may consider the potential negative impact on their underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the Mid-Con Affiliates and Yorktown) on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage the business of our general partner in a manner beneficial to its owners. In addition, all of our general partner’s executive officers and non-independent directors will continue to have economic interests in affiliates of our general partner, which may lead to additional conflicts of interest. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:


	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

	•	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 among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

As required by our partnership agreement, the board of directors of our general partner will maintain a conflicts committee comprised of at least two independent directors. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he or she is acting in our best interest.

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Conflicts of interest could arise in the situations described below, among others:

Affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including the Mid-Con Affiliates and Yorktown, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, Yorktown, through its investment funds and managed accounts, makes investments and purchases entities in various areas of the oil and natural industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, the Mid-Con Affiliates and Yorktown. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, affiliates of our general partner, including the Mid-Con Affiliates and Yorktown, may compete with us for investment opportunities and may own an interest in entities that compete with us.

Our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include our general partners limited call right, its registration rights and its determination whether or not to consent to any merger or consolidation involving us.

All of the executive officers and non-independent directors of our general partner will spend significant time serving entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

To maintain and increase our levels of production, we will need to acquire oil and natural gas properties. All of the executive officers and non-independent directors of our general partner are also officers and/or directors of the Mid-Con Affiliates and will continue to devote significant time to those businesses. Further, all of our executive officers and non-independent directors will continue to have economic interests in, as well as management and fiduciary duties to, the Mid-Con Affiliates. The existing positions held by these directors and officers may give rise to fiduciary duties that are in conflict with fiduciary duties they owe to us. We cannot assure our unitholders that these conflicts will be resolved in our favor. As officers and directors of our general partner, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations and economic interests in

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these and other entities, they may have fiduciary obligations or incentives to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present them to us. For further discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, please read “Business and Properties—Our Principal Business Relationships” and “Management.”


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, which allows our general partner to consider only the interests and factors that it desires, without a duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must either be (i) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (ii) must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	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 any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors 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; and

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “—Fiduciary Duties.”

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

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Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:


	•	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, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and unit appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

	•	the control of any matters affecting our rights and obligations, 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;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement—Limited Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	the manner in which our business is operated;

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	•	the amount, nature and timing of asset purchases and sales, including whether to pursue acquisitions that may also be suitable for affiliates of our general partner;

	•	the amount, nature and timing of our capital expenditures;

	•	the amount of borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights, or accelerating the expiration of the subordination period.

For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Our partnership agreement provides that we and our subsidiary may borrow funds from our general partner and its affiliates. However, our general partner and its affiliates may not borrow funds from us or our operating subsidiaries.

Our general partner determines which costs incurred by it are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating our business, including costs incurred in rendering staff and support services to us pursuant to the services agreement with Mid-Con Energy Operating, an affiliate of our general partner. Our general partner will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. In turn, our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our

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general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or holders of our units. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23.0%, in addition to distributions paid on its 2.0% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Right to Reset Incentive Distribution Levels.”

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a

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result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner and its affiliates, including the Founders and Yorktown, may be able to amend our partnership agreement without the approval of any other unitholder after the subordination period.

Our general partner has the discretion to propose amendments to our partnership agreement, certain of which may be made by our general partner without unitholder approval. Our partnership agreement generally may not be otherwise amended during the subordination period without the approval of a majority of our public common unitholders. However, after the subordination period has ended, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner). Upon the consummation of this offering, the Founders and Yorktown will own approximately common units representing a % limited partnership interest in us. Assuming that the Founders and Yorktown retain a sufficient number of its common units and that we do not issue additional common units, our general partner and its affiliates will have the ability to amend our partnership agreement without the approval of any other unitholder after the subordination period. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner will enter into contractual arrangements on our behalf and intends to limit its liability under such contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. The attorneys, independent accountants and others who perform services for us are selected by our general partner, or the conflicts committee of our general partner’s board of directors, and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the 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.

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Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner and its affiliates to engage in transactions with us that would 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. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted, and engaging in such transactions could result in violations of our general partner’s state-law fiduciary standards. We believe these modifications are appropriate and necessary because our general partner’s board of directors has fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to our unitholders. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the rights and remedies that would otherwise be available to our unitholders 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.

Rights and remedies of unitholders		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. These legal actions include actions against a general partner for breach of fiduciary duty or the partnership agreement. 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

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		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 unitholders 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 or our limited partners 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 our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful.

		Special Provisions Regarding Affiliated Transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest that are not approved by a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner 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).

		If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then 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 us, 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 common unitholder 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 to sign a

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partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, 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 of 1933, 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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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:


	•	surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges;

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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 are reflected in our books and records. Each transferee:


	•	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

	•	automatically agrees to be bound by the terms and conditions of our partnership agreement; and

	•	gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

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Our general partner may request that a transferee of common units certify that such transferee is an Eligible Holder. As of the date of this prospectus, an Eligible Holder means:


	•	a citizen of the United States;

	•	a corporation organized under the laws of the United States or of any state thereof;

	•	a public body, including a municipality; or

	•	an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing transfers of securities.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions;”

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”

	•	with regard to the transfer of common units, please read “Description of the Common Units—Transfer Agent and Registrar—Transfer of Common Units;” and

	•	with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was organized in July 2011 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under our partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may not cause us to engage in any business activity that it 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.

Although our general partner has the ability to cause us and our subsidiary to engage in activities other than the ownership, acquisition, exploitation and development of oil and natural gas properties and the ownership, acquisition and operation of related assets, 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 our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to our unitholders and other partnership interests as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described under “—Limited Liability.”

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For a discussion of our general partner’s right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read “—Issuance of Additional Interests.”

Limited Voting Rights

The following is a summary of the unitholder vote required for each of the matters specified below.

Various matters require the approval of a “unit majority,” which means:


	•	during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates (including the Founders and Yorktown), and a majority of the outstanding subordinated units, each voting as a separate class; and

	•	after the subordination period, the approval of a majority of the outstanding common units.

By virtue of the exclusion of those common units held by our general partner and its affiliates (including the Founders and Yorktown) from the required vote, and by their ownership of all of the subordinated units, during the subordination period, our general partner and its affiliates (including the Founders and Yorktown) do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common and subordinated units, our general partner and its affiliates (including the Founders and Yorktown) will have no 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 our limited partners.


Issuance of additional units		No approval right. Please read “—Issuance of Additional Interests.”

Amendment of the partnership agreement		Certain amendments may be made by our general partner without the approval of any limited partner. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets		Unit majority, in certain circumstances. Please read “—Merger, Consolidation, Sale or Other Disposition of Assets.”

Dissolution of our partnership		Unit majority. Please read “—Dissolution.”

Continuation of our business upon dissolution		Unit majority. Please read “—Dissolution.”

Withdrawal of our general partner		Prior to , 2021, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates (including the Founders and Yorktown), is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

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Removal of our general partner		Not less than 66 2 / 3 % of the outstanding units, including units held by our general partner and its affiliates (including the Founders and Yorktown), voting as a single class. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest		Our general partner may transfer without a vote of our unitholders all, but not less than all, of its general partner interest in us to an affiliate or another person (other than an individual) 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 our general partner and its affiliates (including the Founders and Yorktown), is required in other circumstances for a transfer of the general partner interest to a third party prior to , 2021. Please read ‘‘—Transfer of General Partner Units.”

Transfer of incentive distribution rights		No approval rights. Please read “—Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read “—Transfer of Ownership Interests in Our General Partner.”

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:


	•	arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

	•	brought in a derivative manner on our behalf;

	•	asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

	•	asserting a claim arising pursuant to any provision of the Delaware Act; or

	•	asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware, 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. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

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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 our 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 our limited partners as a group:


	•	to remove or replace our general partner;

	•	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 our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our 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.

Our operating subsidiary conducts business in Oklahoma and Colorado, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of our operating subsidiary may require compliance with legal requirements in the jurisdictions in which our operating subsidiary conducts business, including qualifying our operating subsidiary to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership in our subsidiary 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 our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances.

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We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiary of equity interests, which may effectively rank senior to our common units.

If we issue additional partnership interests (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of partnership interests issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership interests upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% general partner interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by 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 our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. To adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

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Prohibited Amendments

No amendment may:


	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; 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 in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates (including the Founders and Yorktown)). Upon the consummation of this offering, affiliates of our general partner (including the Founders and Yorktown) will own an aggregate of approximately % of our outstanding common units and 100% of our subordinated units, representing an aggregate of approximately % of our outstanding limited partnership units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:


	•	a change in our name, the location of our principal place of business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	•	a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we, nor our subsidiary will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	a change in our fiscal year or taxable year and related changes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership securities or rights to acquire partnership securities;

	•	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, limited liability

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		company, joint venture or other entity, as otherwise permitted by our partnership agreement;


	•	any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to United States federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence;

	•	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 our limited partners (or any particular class of 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 our units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our units 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 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 Unitholder Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes in connection with any of the amendments described above under “—No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding 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 Delaware law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected, but no vote will be required by any class or classes or type or types of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units

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required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

Merger, Consolidation, Sale or Other Disposition of Assets

A merger or consolidation 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 or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us, among other things, to sell, exchange or otherwise dispose of all or substantially all of our and our subsidiary’s assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination or sale of ownership interests of our subsidiary. 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. Finally, our general partner may consummate any merger or consolidation without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in a material amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or our subsidiary 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 our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our 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.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by the holders of a unit majority;

	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

	•	the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; 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

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		interest in us in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor general partner.

Upon a dissolution under the last clause above, the holders of a 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 a 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 under Delaware law of any limited partner; and

	•	neither our partnership nor our subsidiary would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” 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 Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2021 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates (including the Founders and Yorktown), and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2021, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving at least 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates (including the Founders and Yorktown). In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Units.”

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 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 is not obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2 / 3 % of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates (including the Founders and Yorktown), and we receive an opinion of counsel regarding limited liability and tax matters. Any

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removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33 1 / 3 % of our outstanding units by our general partner and its affiliates (including the Founders and Yorktown) would give them the practical ability to prevent our general partner’s removal. Upon the consummation of this offering, affiliates of our general partner (including the Founders and Yorktown) will own an aggregate of approximately % of our outstanding common units and 100% of our subordinated units, representing approximately % of our outstanding limited partnership units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:


	•	all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis;

	•	if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

	•	our general partner will have the right to convert its general partner interest into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and its affiliate and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and its affiliate and the successor general partner will determine the fair market value. If the departing general partner and its affiliate and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for the transfer by our general partner of all, but not less than all, of its general partner units to:


	•	an affiliate of our general partner (other than an individual); or

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	•	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 all or any part of its general partner units to another person prior to , 2021, without the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates (including the Founders and Yorktown). 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 (including the Founders and Yorktown) may at any time transfer common units or subordinated units to one or more persons without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Incentive Distribution Rights

Our general partner or any other holder of incentive distribution rights may transfer any or all of its incentive distribution rights without unitholder approval.

Transfer of Ownership Interests in Our General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates (including the Founders and Yorktown) acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

If our general partner is removed without cause, our partnership agreement provides that, among other things, (i) all outstanding subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately convert into common units on a one-for-one basis, (ii) if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages in payment of the minimum quarterly distribution on the common units will be extinguished and (iii) our general partner will have the right to convert its general partner interest and incentive distribution rights into common units or receive cash in exchange for those interests.

Limited Call Right

If at any time our general partner and its affiliates (including the Founders and Yorktown) own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least

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10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the average of the daily closing prices of the limited partner interests of such class over the 20 trading days preceding the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences—Disposition of Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of common and subordinated 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. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will cast the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding 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 unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates (including the Founders and Yorktown) or a direct or subsequently approved transferee of our general partner or its affiliates and specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. 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. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

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.

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Status as Limited Partner

By transfer of any 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 unitholders will not be required to make additional contributions.

Non-Citizen Unitholders; Redemption

We may acquire interests in oil and natural gas leases on United States federal lands in the future. To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, our general partner, acting on our behalf, may request any unitholder to furnish to the general partner within 30 days of the request a properly completed certificate certifying as to the unitholder’s nationality, citizenship or other related status. If, following a request by our general partner, a unitholder fails to furnish such certification within the 30-day period or if the general partner determines that the unitholder’s nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of property in which the we have an interest, we will have the right to redeem the units held by such unitholder. Further, the units held by such unitholder will not be entitled to any voting rights. The redemption price will be paid in cash or delivery of a promissory note, as determined by our general partner. If our general partner chooses to redeem the units in cash, the redemption price will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. If our general partner chooses to redeem the units with a promissory note, the promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of our general partner or any departing general partner;

	•	any person who is or was a director, officer, manager, managing member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

	•	any person who is or was serving as a director, officer, manager, managing member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

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 covering liabilities asserted against and expenses incurred by persons for our

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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 and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates, including Mid-Con Energy Operating, may be reimbursed. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

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 financial reporting and tax purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 90 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 registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days 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 our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every 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 can, 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, obtain:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	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 any 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 partner’s trade secrets or other information the disclosure of which our general partner believes in good faith is

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not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, our general partner and its affiliates (including the Founders and Yorktown) have the right to cause us to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. In addition, our general partner and its affiliates (including the Founders and Yorktown) have the right to include such securities in a registration by us or any other unitholder, subject to customary exceptions. These registration rights continue for two years following any withdrawal or removal of our general partner. In addition, we are restricted from granting any superior piggyback registration rights during this two-year period. We will pay all expenses incidental to the registration, excluding underwriting fees and discounts. In connection with any registration of this kind, we will indemnify the unitholders participating in the registration and their officers, directors and controlling persons from and against specified liabilities, including under the Securities Act or any applicable state securities laws. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, the Founders, Yorktown and the other Contributing Parties will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1.0% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell his common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement does not restrict our ability to issue any partnership interests. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Under our partnership agreement, our general partner and its affiliates, including the Founders and Yorktown, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership interests that they hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of common units or other partnership interests, including common units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of units held by our general partner or its affiliates, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their common units or other partnership interests in private transactions at any time, subject to compliance with certain conditions and applicable laws.

We, our general partner and certain of its affiliates and the directors and executive officers of our general partner have agreed, subject to certain exceptions, not to sell any common units for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material U.S. federal income, state and local tax consequences that may be relevant to prospective unitholders and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP insofar as it describes legal conclusions with respect to matters of U.S. federal income tax law. Such statements are based on the accuracy of the representations made by our general partner and us to Andrews Kurth LLP, and statements of fact do not represent opinions of Andrews Kurth LLP. To the extent this section discusses U.S. federal income taxes, that discussion is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. 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 Mid-Con Energy Partners, LP and our subsidiary.

This section does not address all U.S. federal, state and local tax matters that affect us or our unitholders. To the extent that this section relates to taxation by a state, local or other jurisdiction within the United States, such discussion is intended to provide only general information. We have not sought the opinion of legal counsel regarding U.S. state, local or other taxation and, thus, any portion of the following discussion relating to such taxes does not represent the opinion of Andrews Kurth LLP or any other legal counsel. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States, whose functional currency is the U.S. dollar and who hold common units as a capital asset (generally, property that is held as an investment). This section has only limited application to corporations, partnerships (and entities treated as partnerships for U.S. federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each prospective unitholder to consult such unitholder’s own tax advisor in analyzing the U.S. federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from his ownership or disposition of his common units.

No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter that affects us or our unitholders. Instead, we will rely on opinions and advice of Andrews Kurth 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 herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which such common units trade. 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 unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific U.S. federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

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Taxation of Mid-Con Energy Partners, LP

Partnership Status

We will be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for U.S. federal income taxes. Instead, each of our unitholders will be required to take into account his respective share of our items of income, gain, loss and deduction in computing his U.S. federal income tax liability as if the unitholder had earned such income directly, even if no cash distributions are made to the unitholder. Distributions by us to a unitholder generally will not be taxable to the unitholder unless the amount of cash distributed to the unitholder exceeds the unitholder’s tax basis in his common units.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from exploration and production of certain natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner, and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiary for U.S. federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP on such matters. It is the opinion of Andrews Kurth LLP that we will be classified as a partnership and our operating subsidiary will be disregarded as an entity separate from us for U.S. federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied include, without limitation:

(a) neither we nor our operating subsidiary has elected or will elect to be treated as a corporation; and

(b) for each taxable year, including short taxable years occurring as a result of a constructive termination, more than 90% of our gross income has been and will be income that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, unless such failure is determined by the IRS to be inadvertent and is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we failed to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to our unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to our unitholders and us so long as we, at that time, do not have liabilities in

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excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for U.S. federal income tax purposes.

If we were taxed as a corporation for U.S. federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return, rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in our common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of our common units.

The discussion below is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for U.S. federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of Mid-Con Energy Partners, LP, as well as unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of common units, will be treated as partners of Mid-Con Energy Partners, LP for U.S. federal income tax purposes. A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for U.S. federal income tax purposes. Please read “—Treatment of Short Sales.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Mid-Con Energy Partners, LP for federal income tax purposes.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes,” neither we nor our subsidiary will pay any U.S. federal income tax. For U.S. federal income tax purposes, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for his taxable year or years ending with or within our taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of the unitholder’s 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 Units” below. Any reduction in a unitholder’s share of our liabilities, including as a result of future issuances of additional common units, will be treated as a distribution of cash to that unitholder. To the

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extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, that unitholder must recapture any losses deducted in previous years. Please read ‘‘—Limitations on Deductibility of Losses.”

A decrease in a 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. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property, including a deemed distribution, may result in ordinary income to a unitholder, regardless of that unitholder’s tax basis in its common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To the extent of such reduction, a unitholder will be treated as having received his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for an allocable portion of the non-pro rata distribution made to such unitholder. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders could substantially increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all common units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure our unitholders that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make minimum quarterly distributions on all common units, yet we only distribute the minimum quarterly distributions on all common units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Units

A unitholder’s initial tax basis in his common units will be the amount he paid for those common units plus his share of our nonrecourse liabilities. That basis generally will be

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(i) increased by the unitholder’s share of our income and by any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to him, 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 adjusted tax basis of the underlying 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. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally, based on his share of our profits, of our nonrecourse liabilities. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of that unitholder’s share of our losses will be limited to the lesser of (i) the tax basis such unitholder has in his common units, and (ii) in the case of an individual, estate, trust or corporate unitholder (if more than 50% of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause the unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a 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 unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a 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 loss previously suspended by the at risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of the unitholder’s common units, excluding any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, reduced by (1) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (2) any amount of money the unitholder borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the common units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the unitholder’s share of our 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 natural 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. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder’s at risk limitation with respect to us. If a unitholder were required to compute his at risk amount separately with respect to each oil or natural gas property we own, he might 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 basis and at risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations

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and personal service corporations may deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly-traded partnerships, or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any U.S. federal, state, local or non-U.S. tax on behalf of any unitholder or our general partner or any former 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 unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund

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Allocation of Income, Gain, Loss and Deduction

In general, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. If we have a net loss for an entire taxable year, the loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of the unitholders’ positive capital accounts as adjusted to take into account the unitholders’ share of nonrecourse debt, and thereafter to our general partner. However, at any time that distributions are made to the common units in excess of distributions to the subordinated common units, or incentive distributions are made, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets, a “Book Tax Disparity,” at the time of this offering and any future offerings or certain other transactions. The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder acquiring common units in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. However, in connection with providing this benefit to any future unitholders, similar allocations will be made to all holders of partnership interests immediately prior to a future offering or certain other transactions, including purchasers of common units in this offering, to account for any Book Tax Disparity at the time of such transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate a Book-Tax Disparity, will generally be given effect for U.S. federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those common units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those common units would be fully taxable; and

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	•	all of these distributions may be subject to tax as ordinary income.

Andrews Kurth LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of our common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult with their tax advisor about modifying any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their common units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account the unitholder’s distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors with respect to the impact of an investment in our common units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

Recently enacted legislation will impose a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds specified threshold levels depending on a unitholder’s federal income tax filing status. In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect the unitholder’s purchase price. The Section 743(b) adjustment separately applies to any transferee of a unitholder who purchases outstanding common units from another unitholder based upon the values and bases of our assets at the time of the transfer to the transferee. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us, and belongs only to the purchaser and not to other unitholders. Please read, however, “—Allocation of Income, Gain, Loss and Deduction.” For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) the unitholder’s share of our tax basis in our assets (“common basis”) and (2) the unitholder’s Section 743(b) adjustment to that basis.

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The timing and calculation of deductions attributable to Section 743(b) adjustments to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Internal Revenue Code Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Internal Revenue Code Section 704(c) principles with respect to an asset to which the adjustment is applicable. Please read “—Allocation of Income, Gain, Loss and Deduction.”

The timing of these deductions may affect the uniformity of our common units. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of common units even if that position is not consistent with these and any other Treasury Regulations or if the position would result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” Andrews Kurth LLP is unable to opine as to the validity of any such alternate tax positions because there is no clear applicable authority. A unitholder’s basis in a unit is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his common units and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his common units is higher than the common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and the transferee’s share of any gain or loss on a sale of assets by us would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his common units is lower than those common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the fair market value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally either non-amortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure our unitholders that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should our general partner determine the expense of compliance exceeds the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than such purchaser would have been allocated had the election not been revoked.

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 federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his

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taxable year. In addition, a 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 income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read ‘‘—Disposition of Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses”), 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 interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. To qualify as an “independent producer” eligible for percentage depletion (and that is not subject to the intangible drilling and development cost deduction limits, please read “—Deductions for Intangible Drilling and Development Costs,”) a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels 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 $5.0 million per year in the aggregate. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel 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.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, 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 unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

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 (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral common units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result

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by the number of mineral common units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a 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 unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion 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 unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, 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 the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (“IDCs”). 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. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each 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. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) 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 oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is does not qualify as an independent producer under the rules disqualifying retailers and refiners from taking percentage depletion. Please read “—Depletion Deductions.”

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted 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 unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as

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allocable to the transferred undivided interest to the extent of any gain recognized. Please read ‘‘—Disposition of Units—Recognition of Gain or Loss.”

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read ‘‘—Recent Legislative Developments.”

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to 9% of our qualified production activities income that is allocated to such unitholder.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. 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 unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each 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 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. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a 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 unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our operating subsidiary will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

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 unitholders. Further, because the Section 199 deduction is required to be computed separately by each 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 the unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” Each prospective 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 oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a

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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 cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred. The amortization period for certain geological and geophysical expenditures may be extended if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read ‘‘—Recent Legislative Developments.”

Operating and Administrative Costs

Amounts paid for operating a producing well 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 will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interests in us prior to such offering. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent applicable, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. We may not be entitled to any amortization deductions with respect to certain goodwill properties conveyed to us or held by us at the time of any future offering. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue 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 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 interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs incurred in selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts we incur will be treated as syndication.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on

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the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of common units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the common units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our liabilities. Because the amount realized includes a unitholder’s share of our 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.

Prior distributions from us that in the aggregate were in excess of the cumulative net taxable income allocated for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in the unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year will generally be taxable as long-term capital gain or loss. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, amortization or IDC recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of common units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of our common units. A unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an

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“appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract;

	•	in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly-traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly-traded partnerships are entitled to rely on those proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until the final Treasury Regulations are issued. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his common units is generally 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). A purchaser of common units who purchases common units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase.

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Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of common units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have terminated our tax partnership for U.S. federal income tax purposes upon the sale or exchange of interests in us that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold has been met, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure for publicly traded partnerships that have technically terminated, the IRS may allow, among other things, that we provide a single Schedule K-1 for the tax year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of common units and because of other reasons, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the common units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our common units even under circumstances like those described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Andrews Kurth LLP is unable to opine as to validity of such filing positions. A unitholder’s basis in common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Units—Recognition of Gain or Loss” and “—Tax Consequences of Unit Ownership—Section 754 Election.” The IRS may challenge one or more of any positions we take to preserve the uniformity of common units. If such a challenge were sustained, the uniformity of common units might be affected, and, under some circumstances, the gain from the sale of common units might be increased without the benefit of additional deductions.

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Tax-Exempt Organizations and Other Investors

Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our common units.

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. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

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 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. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns common units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their common units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain,

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loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we, nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any 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 unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of U.S. federal income 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 Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement designates our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.

A 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 unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a person that is not a U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(3) the amount and description of common units held, acquired or transferred for the beneficial owner; and

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(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.

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 Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of 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 ($10,000 for most corporations). 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 pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) 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, (b) 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 Internal Revenue 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 (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5.0 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. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

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Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly our unitholders and others) 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 tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2.0 million in any single tax year, or $4.0 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our unitholders’ tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following additional consequences:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described in “—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.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

The White House recently released President Obama’s budget proposal for the Fiscal Year 2012 (the “Budget Proposal”). Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and development. Changes in the Budget Proposal include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

In addition, in the last Congressional session, the U.S. House of Representatives passed legislation that would have provided for substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these legislative efforts could result in changes to the existing federal income tax laws that affect publicly traded partnerships. As previously proposed, we do not believe any such legislation would affect our tax treatment as a partnership. However, the proposed legislation could be modified in a way that could affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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State, Local and Other Tax Considerations

In addition to U.S. federal income taxes, unitholders will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which the unitholder is a resident. We currently conduct business or own property in Oklahoma and Colorado, each of which imposes personal income taxes on individuals. These states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file state income tax returns and to pay state income taxes in any state in which we do business or own property, and such unitholder may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections of Unitholder Taxes.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend on, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all tax returns that may be required of him. Andrews Kurth LLP has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in us.

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INVESTMENT IN MID-CON ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements (collectively, “Employee Benefit Plans”). Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

	•	whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

	•	whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans, and IRAs that are not considered part of an Employee Benefit Plan, from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:


	•	the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the

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		issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;


	•	the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

	•	there is no significant investment by “benefit plan investors,” which is generally defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and certain persons, is held by the Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first two bullet points above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

RBC Capital Markets, LLC is acting as book-running manager of the offering and as representative of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, the underwriters set forth below have agreed to purchase from us the number of common units set forth opposite its name.


		Number of
Underwriter		Common Units

RBC Capital Markets, LLC
Total

The underwriting agreement provides that the underwriters’ obligations to purchase the common units depend on the satisfaction of the conditions contained in the underwriting agreement and that if any of our common units are purchased by the underwriters, all of our common units must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by us to the underwriters are true, that there has been no material adverse change in the condition of us or in the financial markets and that we deliver to the underwriters’ customary closing documents.

The following table shows the underwriting fees to be paid to the underwriters by us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. This underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us to purchase the common units. On a per common unit basis, the underwriting fee is % of the initial price to the public.


	Paid by Us
	No Exercise	Full Exercise

Per common unit	$	$
Total	$	$

We estimate that total expenses of the offering, other than underwriting discounts, a structuring fee and commissions, will be approximately $ . We will pay RBC Capital Markets, LLC a structuring fee equal to % of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

We have been advised by the underwriters that the underwriters propose to offer our common units directly to the public at the initial price to the public set forth on the cover page of this prospectus and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $ per common unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $ per common unit to certain brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments that may be required to be made with respect to these liabilities.

We have granted to the underwriters an option to purchase up to an aggregate of additional common units at the initial price to the public less the underwriting discount set forth on the cover page of this prospectus exercisable solely to cover over-allotments, if any. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional common units proportionate to the underwriter’s initial commitment as indicated in the

211

preceding table, and we will be obligated, pursuant to the option, to sell these common units to the underwriters.

We, our general partner and its affiliates, including the directors and executive officers of our general partner have agreed that we will not, directly or indirectly, sell, offer or otherwise dispose of any common units or enter into any derivative transaction with similar effect as a sale of common units for a period of 180 days after the date of this prospectus without the prior written consent of RBC Capital Markets, LLC. The restrictions described in this paragraph do not apply to:


	•	the sale of common units to the underwriters;

	•	restricted common units issued by us under the long-term incentive plan or upon the exercise of options issued under the long-term incentive plan; or

	•	the issuance of common units or securities convertible or exchangeable into common units as payment of any part of the purchase price for businesses that we acquire; provided, that any recipient of such common units must agree to be bound by the restrictions described in this paragraph for the remainder of the 180-day restricted period.

The 180-day restricted period described in the preceding paragraphs will be extended if:


	•	during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or

	•	prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period;

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 16-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

RBC Capital Markets, LLC, in its sole discretion, may release the common units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release common units from lock-up agreements, RBC Capital Markets, LLC will consider, among other factors, the unitholders’ reasons for requesting the release, the number of common units for which the release is being requested and market conditions at the time. However, RBC Capital Markets, LLC has informed us that, as of the date of this prospectus, there are no agreements between them and any party that would allow such party to transfer any common units, nor do they have any intention at this time of releasing any of the common units subject to the lock-up agreements, prior to the expiration of the lock-up period.

Our partnership agreement requires that all common unitholders be Eligible Holders. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

212


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of common units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of common units over-allotted by the underwriters is not greater than the number of common units they may purchase in their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in the underwriters’ option to purchase additional common units. The underwriters may close out any short position by either exercising their option and/or purchasing common units in the open market.

	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option. If the underwriters sell more common units than could be covered by their option to purchase additional common units, which we refer to in this prospectus as a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Market or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

We intend to apply to list our common units on the NASDAQ Global Market under the symbol “MCEP.”

The underwriters may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. Additionally, affiliates of certain of the underwriters will serve as lenders under our new credit facility.

213

Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

No sales to accounts over which any underwriter exercises discretionary authority in excess of 5% of the units offered by them may be made without the prior written approval of the customer.

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, information contained in any other web site maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase any units. The underwriters and selling group members are not responsible for information contained in web sites that they do not maintain.

Offering Price Determination

Prior to this offering, there has been no public market for the common units. The initial public offering price was determined by negotiation between us and the underwriters. The principal factors considered in determining the public offering price included the following:


	•	the information set forth in this prospectus and otherwise available to the underwriters;

	•	our history and prospects and the history and prospects for the industry in which we will compete;

	•	the ability of our management;

	•	our prospects for future cash flow;

	•	the present state of our development and our current financial condition;

	•	market conditions for initial public offerings and the general condition of the securities markets at the time of this offering; and

	•	the recent market prices of, and the demand for, publicly traded units of generally comparable entities.

214

EXPERTS

The audited balance sheet of Mid-Con Energy Partners, LP as of June 30, 2011 included in this prospectus and elsewhere in the registration statement has been so included in reliance on the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in auditing and accounting in giving said report.

The audited financial statements of Mid-Con Energy Corporation and the audited combined financial statements of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in auditing and accounting in giving said reports.

Estimated quantities of our proved oil and natural gas reserves and the net present value of such reserves as of December 31, 2010 and June 30, 2011 set forth in this prospectus are based upon reserve reports prepared by our internal reservoir engineers and audited by Cawley, Gillespie & Associates, Inc.

216

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-l regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and our common units offered in this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. The full registration statement, of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Copies of these materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The registration statement, of which this prospectus forms a part, can also be downloaded from the SEC’s web site on the Internet at http://www.sec.gov. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Additionally, we intend to file other periodic reports with the SEC, as required by the Securities Exchange Act of 1934.

217

FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:


	•	business strategies;

	•	ability to replace the reserves we produce through acquisitions and the development of our properties;

	•	oil and natural gas reserves;

	•	technology;

	•	realized oil and natural gas prices;

	•	production volumes;

	•	lease operating expenses;

	•	general and administrative expenses;

	•	future operating results;

	•	cash flow and liquidity;

	•	availability of production equipment;

	•	availability of oil field labor;

	•	capital expenditures;

	•	availability and terms of capital;

	•	marketing of oil and natural gas;

	•	general economic conditions;

	•	competition in the oil and natural gas industry;

	•	effectiveness of risk management activities;

	•	environmental liabilities;

	•	counterparty credit risk;

	•	governmental regulation and taxation;

	•	developments in oil producing and natural gas producing countries; and

	•	plans, objectives, expectations and intentions.

These types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in “Prospectus Summary,” “Risk Factors,” “Our Cash Distribution Policy and Restrictions on Distributions,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business and Properties” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

218

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Risk Factors” and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

219

Mid-Con Energy Partners, LP

Unaudited Pro Forma Condensed Financial Statements

Introduction

The following unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP (the “Partnership”) are derived from the audited and unaudited historical combined results of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (collectively, the “predecessor”). The pro forma condensed financial statements give pro forma effect to formation and offering related transactions described in Note 1 to these financial statements. The unaudited pro forma condensed financial statements have been prepared on the basis that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma condensed financial statements should be read in conjunction with the notes accompanying these unaudited pro forma condensed financial statements and with the audited and unaudited historical combined financial statements and related notes of the predecessor found elsewhere in this prospectus.

The pro forma adjustments to the audited historical financial statements are based upon currently available information and certain estimates and assumptions. The actual effect of the transactions discussed in the accompanying notes ultimately may differ from the unaudited pro forma adjustments included herein. However, management believes that the assumptions utilized to prepare the pro forma adjustments provide a reasonable basis for presenting the significant effects of the transactions as currently contemplated and that the unaudited pro forma adjustments are factually supportable, give appropriate effect to the expected impact of events that are directly attributable to the transactions, and reflect those items expected to have a continuing impact on the Partnership.

The unaudited pro forma condensed financial statements of the Partnership are not necessarily indicative of the results that actually would have occurred if the Partnership had completed the transactions described above on the dates indicated or that could be achieved in the future.

F-2

Mid-Con Energy Partners, LP

Pro Forma Condensed Balance Sheet
June 30, 2011
(Unaudited)


									Mid-Con
				Offering and					Energy
	Predecessor			Other					Pro Forma,
	Historical			Adjustments					As Adjusted
	(in thousands)

ASSETS
Current Assets:
Cash and cash equivalents	$	440		$	16,690		(a	)	$	440
					120,000		(b	)
					1,873		(c	)
					(138,563	)	(d	)
Accounts receivable:
Oil and natural gas sales		3,619			—					3,619
Affiliate		1,529			—					1,529
Certificate of deposit—government bond		150			—					150
Prepaids and other		66			—					66

Total current assets		5,804			—					5,804

Property and Equipment:
Oil and gas properties, successful efforts method:
Proved properties		72,445			—					72,445
Unproved properties		325			—					325
Accumulated depreciation, depletion and amortization		(6,793	)		—					(6,793	)

Total property and equipment, net		65,977			—					65,977

Other Assets		272			(240	)	(e	)		32
Derivative Financial Instruments		529			—					529

Total assets	$	72,582		$	(240	)			$	72,342


LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable	$	708		$	—				$	708
Accrued liabilities		316			—					316
Revenue payable		10			—					10
Derivative financial instruments		387			—					387

Total current liabilities		1,421			—					1,421

Long-Term Debt		13,310			16,690		(a	)		30,000

Asset Retirement Obligations		1,561			—					1,561

Partners’ Capital:
Contributed capital		58,163			120,000		(b	)		39,360
					(138,563	)	(d	)
					(240	)	(e	)
Notes receivable from officers, directors and employees		(1,873	)		1,873		(c	)		—

Total partners’ capital		56,290			(16,930	)				39,360

Total liabilities and partners’ capital	$	72,582		$	(240	)			$	72,342

The accompanying notes are an integral part of these pro forma financial statements.

F-3

Mid-Con Energy Partners, LP

Pro Forma Condensed Statement of Operations
For the six months ended June 30, 2011
(Unaudited)


															Mid-Con
							Mid-Con			Offering and					Energy
	Predecessor			Disposed			Energy			Other					Pro Forma,
	Historical			Assets			Pro Forma			Adjustments					As Adjusted
	(in thousands)

Revenues:
Oil sales	$	15,609		$	(721	)(f)	$	14,888		$	—				$	14,888
Natural gas sales		657			—			657			—					657
Realized gain (loss) on derivatives, net		(714	)		—			(714	)		—					(714	)
Unrealized gain (loss) on derivatives, net		1,046			(62	)(f)		984			—					984

Total revenues		16,598			(783	)		15,815			—					15,815
Operating costs and expenses:
Lease operating expenses		3,550			(583	)(f)		2,967			—					2,967
Oil and gas production taxes		655			(46	)(f)		609			—					609
Dry holes and abandonments of unproved properties		772			—			772			—					772
Geological and geophysical		58			(58	)(f)		—			—					—
Depreciation, depletion and amortization		2,419			(338	)(g)		2,081			—					2,081
Accretion of discount on asset retirement obligations		32			—			32			—					32
General and administrative		476			—			476			—					476

Total operating costs and expenses		7,962			(1,025	)		6,937			—					6,937

Income (loss) from operations		8,636			242			8,878			—					8,878

Other income (expense):
Interest income and other		62			—			62			(58	)	(h	)		4
Interest expense		(237	)		—			(237	)		(363	)	(i	)		(600	)
Gain on sale of assets		1,209			(1,209	)(f)		—			—					—
Other revenue and expense, net		576			(576	)(f)		—			—					—

Total other income (expenses)		1,610			(1,785	)		(175	)		(421	)				(596	)

Net income (loss)	$	10,246		$	(1,543	)	$	8,703		$	(421	)

Computation of net income per limited partner unit:
General partner’s interest in net income															$	166

Limited partners’ interest in net income															$	8,116

Net income per limited partner unit (basic and diluted)															$

Weighted average number of limited partner units outstanding (basic and diluted)

The accompanying notes are an integral part of these pro forma financial statements.

F-4

Mid-Con Energy Partners, LP

Pro Forma Condensed Statement of Operations
For the twelve months ended December 31, 2010
(Unaudited)


															Mid-Con
							Mid-Con			Offering and					Energy
	Predecessor			Disposed			Energy			Other					Pro Forma,
	Historical			Assets			Pro Forma			Adjustments					As Adjusted
	(in thousands)

Revenues:
Oil sales	$	16,853		$	(1,337	)(f)	$	15,516		$	—				$	15,516
Natural gas sales		1,418			(26	)(f)		1,392			—					1,392
Realized gain (loss) on derivatives, net		(90	)		—			(90	)		—					(90	)
Unrealized gain (loss) on derivatives, net		(707	)		—			(707	)		—					(707	)

Total revenues		17,474			(1,363	)		16,111			—					16,111
Operating costs and expenses:
Lease operating expenses		6,237			(1,449	)(f)		4,788			—					4,788
Oil and gas production taxes		822			(81	)(f)		741			—					741
Dry holes and abandonments of unproved properties		1,418			(904	)(f)		514			—					514
Geological and geophysical		394			(394	)(f)		—			—					—
Depreciation, depletion and amortization		6,217			(2,940	)(g)		3,277			—					3,277
Accretion of discount on asset retirement obligations		127			(64	)(f)		63			—					63
General and administrative		982			—			982			—					982
Impairment of proved oil and gas properties		1,831			(597	)(f)		1,234			—					1,234

Total operating costs and expenses		18,028			(6,429	)		11,599			—					11,599

Income (loss) from operations		(554	)		5,066			4,512			—					4,512

Other income (expense):
Interest income and other		218			—			218			(92	)	(h	)		126
Interest expense		(98	)		—			(98	)		(1,102	)	(i	)		(1,200	)
Gain on sale of assets		354			(354	)(f)		—			—					—
Other revenue and expense, net		847			(847	)(f)		—			—					—

Total other income (expenses)		1,321			(1,201	)		120			(1,194	)				(1,074	)

Net income (loss)	$	767		$	3,865		$	4,632		$	(1,194	)			$	3,438

Computation of net income per limited partner unit:
General partner’s interest in net income															$	69

Limited partners’ interest in net income															$	3,369

Net income per limited partner unit (basic and diluted)															$

Weighted average number of limited partner units outstanding (basic and diluted)

The accompanying notes are an integral part of these pro forma financial statements.

F-5

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS


1.	Basis of Presentation

The unaudited pro forma condensed balance sheet of the Partnership as of June 30, 2011 is based on the unaudited historical combined balance sheet of the predecessor and includes pro forma adjustments to give effect to the formation and the offering as described below as if they occurred on June 30, 2011.

The unaudited pro forma condensed statement of operations of the Partnership is based on the unaudited historical combined statement of operations of the predecessor for the six months ended June 30, 2011 and the audited historical combined statement of operations of the predecessor for the year ended December 31, 2010 and includes pro forma adjustments to give effect to the transactions described below as if they occurred on January 1, 2010.

The unaudited pro forma condensed financial statements give pro forma effect to:


	•	the sale by the predecessor as of June 30, 2011 of certain oil and natural gas properties representing approximately 2% of its proved reserves by value, as calculated using the standardized measure, as of such date, and certain subsidiaries that do not own oil and natural gas reserves, including Mid-Con Energy Operating, Inc. (collectively, the “Disposed Assets”), to Mid-Con Energy III, LLC and Mid-Con Energy IV, LLC (collectively, the “Mid-Con Affiliates”) for aggregate consideration of $7.5 million;

	•	the merger of the predecessor with the Partnership’s wholly owned subsidiary (the “Merger”) in exchange for aggregate consideration of common units, subordinated units and $ million in cash;

	•	the issuance to Mid-Con Energy GP, LLC, the Partnership’s general partner, of general partner units, representing a 2.0% general partner interest in the Partnership, and the incentive distribution rights;

	•	the issuance and sale by the Partnership to the public of common units (the “Offering”) and the application of the net proceeds as described in “Use of Proceeds;” and

	•	the Partnership’s borrowing of approximately $ million under its new credit facility and the application of the proceeds as described in “Use of Proceeds.”

The Merger has been accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed will be recorded based on the predecessor’s historical cost.

The historical balance sheet at June 30, 2011 of the predecessor reflects the sale of Disposed Assets. Because the sale was effective as of June 30, 2011, no pro forma adjustments to the historical balance sheet of the predecessor are necessary to reflect the sale. However, the historical statements of operations of the predecessor for the year ended December 31, 2010 and the six months ended June 30, 2011 include the results of operations attributable to the Disposed Assets. Accordingly, the Partnership’s unaudited pro forma condensed statements of operations for the year ended December 31, 2010 and the six months ended June 30, 2011 include adjustments to reflect the sale of the Disposed Assets.

The Partnership’s unaudited pro forma condensed statements of operations do not reflect the incremental general and administrative expenses of approximately $3.0 million that the Partnership expects to incur annually as a result of being a publicly traded partnership.

F-6

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS— (continued)


2.	Pro Forma Adjustments and Assumptions

Unaudited pro forma condensed balance sheet

(a) Pro forma adjustment to reflect the cash proceeds from borrowings by the Partnership of $30.0 million under its new revolving credit facility. Pro forma adjustment reflects additional amount to reflect the new credit facility.

(b) Pro forma adjustment to reflect gross cash proceeds of approximately $120.0 million from the issuance and sale of common units in the offering at an assumed initial public offering of $ per unit.

(c) Pro forma adjustment to record the net proceeds from the payment of the notes receivable of the predecessor’s members.

(d) Pro forma adjustment to record the use of the net proceeds from the offering and borrowings under the Partnership’s new credit facility, after underwriting discounts and commissions, a structuring fee and estimated offering and borrowing expenses of approximately $12.0 million, to repay $13.3 million in outstanding indebtedness under the predecessor’s credit facilities and to make a $123.1 million cash distribution to the owners of the predecessor.

(e) Pro forma adjustment to record retirement of interest on notes receivable from members.

Unaudited pro forma statements of operations

(f) Pro forma adjustment to reflect the revenues and direct operating expenses excluding the Disposed Assets. These adjustments are based on the actual results of the Disposed Assets. Historical lease operating statements by individual asset were used as the basis for the revenues and direct lease operating expenses.

(g) Pro forma adjustment to reflect the depreciation, depletion and amortization expenses associated with the Disposed Assets. The calculations based on the actual allocated costs of the Disposed Assets and the associated production and reserves as if the sale of the Disposed Assets had occurred on January 1, 2010.

(h) Pro forma adjustment to reflect interest income on the notes receivables from officers, directors and employees from the issuances of the predecessor’s units.

(i) Pro forma adjustment to reflect interest expense and amortization of deferred financing costs on $30.0 million of borrowings by the Partnership under a new credit facility assuming an interest rate of 4.0%. A one-eighth percentage point change in the interest rate would change pro forma interest expense by less than $20,000 for the six months ended June 30, 2011.


3.	Pro Forma Net Income Per Limited Partner Unit

Pro forma net income per limited partner unit is determined by dividing the pro forma net income available to the holders of common units, after deducting the general partner’s 2.0% interest in pro forma net income, by the number of common units and subordinated units expected to be outstanding at the closing of the Offering. For purposes of this calculation, management assumed the aggregate number of common units was and subordinated units was . All units were assumed to have been outstanding since January 1, 2010.

F-7

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS— (continued)


4.	Pro Forma Standardized Measure of Discounted Future Net Cash Flow

Standardized Measure of Future Net Cash Flow

The table below reflects the pro forma standardized measure of discounted future net cash flow related to the Partnership’s interest in proved reserves as of December 31, 2010:


	December 31,
	2010
	(in thousands)

Future cash flow	$	523,095
Future production costs		(149,591	)
Future development costs		(26,802	)

Future net cash flow		346,702
10% discount for estimated timing of cash flow		(164,563	)

Standardized measure of discounted future net cash flow	$	182,139

The principal changes in the pro forma standardized measure of discounted future net cash flow attributable to the Partnership’s proved reserves as of December 31, 2010 are as follows:


	December 31,
	2010
	(in thousands)

Standardized measure of discounted future net cash flow, beginning of period	$	98,036
Changes in the year resulting from:
Sales, less production costs		(11,379	)
Revisions of previous quantity estimates		3,964
Extensions and discoveries, and improved recovery		16,562
Net changes in prices and production costs		41,030
Changes in estimated future development costs		(5,232	)
Previously estimated development costs incurred during the period		9,343
Purchase of minerals in place		22,330
Accretion of discount		9,804
Timing differences and other		(2,319	)

Standardized measure of discounted future net cash flow, end of period	$	182,139

F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Mid-Con Energy GP, LLC

We have audited the accompanying balance sheet of Mid-Con Energy Partners, LP (a Delaware limited partnership) as of July 29, 2011. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

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

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Mid-Con Energy Partners, LP as of July 29, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

August 12, 2011

F-9

Mid-Con Energy Partners, LP
Note to Balance Sheet
July 29, 2011


1.	Organization and Operations

Mid-Con Energy Partners, LP (the “Partnership”) is a Delaware limited partnership formed on July 29, 2011 to own, operate, acquire, exploit and develop producing oil and natural gas properties in the Mid-Continent region of the United States. In connection with its formation, the Partnership issued (a) a 2% general partner interest to Mid-Con Energy GP, LLC, its general partner, and (b) a 98% limited partner interest to Mr. S. Craig George, its organizational limited partner.

Mid-Con Energy GP, LLC, as general partner, contributed $20 and S. Craig George, as the organizational limited partner, contributed $980 to the Partnership as of July 29, 2011. The accompanying balance sheet reflects the financial position of the Partnership immediately subsequent to this initial capitalization. There have been no other transactions involving the Partnership as of July 29, 2011.

F-11

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Balance Sheets


	As of			As of
	December 31,			June 30,
	2010			2011
	(unaudited, in thousands)

ASSETS
Current Assets:
Cash and cash equivalents	$	222		$	440
Accounts receivable:
Oil and gas sales		2,134			3,619
Joint operations and other		1,548			1,529
Certificate of deposit—government bond		150			150
Inventory		771			—
Prepaids and other		147			66

Total current assets		4,972			5,804

Property and Equipment:
Oil and gas properties, successful efforts method:
Proved properties		57,873			72,445
Unproved properties		446			325
Other property and equipment		2,324			—
Accumulated depreciation, depletion and amortization		(8,795	)		(6,793	)

Total property and equipment, net		51,848			65,977

Other Assets		239			272
Derivative Financial Instruments		—			529

Total assets	$	57,059		$	72,582


LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities:
Accounts payable	$	2,785		$	708
Accrued liabilities		399			316
Revenue payable		182			10
Advance billings and other		1,864			—
Current portion of long-term debt		5,354			—
Derivative financial instruments		904			387

Total current liabilities		11,488			1,421

Long-Term Debt		159			13,310

Asset Retirement Obligations		2,148			1,561

Members’ Equity:
Contributed capital		52,933			55,753
Notes receivable from officers, directors and employees		(1,833	)		(1,873	)
(Accumulated deficit) retained earnings		(7,836	)		2,410

Total members’ equity		43,264			56,290

Total liabilities and members’ equity	$	57,059		$	72,582

The accompanying notes are an integral part of these combined balance sheets.

F-12

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Statements of Operations


	Six Months Ended June 30,
	2010			2011
	(unaudited, in thousands)

Revenues:
Oil sales	$	7,482		$	15,609
Natural gas sales		803			657
Realized loss on derivatives, net		(91	)		(714	)
Unrealized gain on derivatives, net		545			1,046

Total revenues		8,739			16,598

Operating costs and expenses:
Lease operating expenses		3,038			3,550
Oil and gas production taxes		384			655
Dry holes and abandonments of unproved properties		44			772
Geological and geophysical		287			58
Depreciation, depletion and amortization		3,629			2,419
Accretion of discount on asset retirement obligations		64			32
General and administrative		587			476

Total operating costs and expenses		8,033			7,962

Income from operations		706			8,636

Other income (expense):
Interest income and other		151			62
Interest expense		(17	)		(237	)
Gain on sale of assets		353			1,209
Other revenue and expense, net		299			576

Total other income (expenses)		786			1,610

Net income	$	1,492		$	10,246

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

F-13

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Statements of Cash Flow


	Six Months Ended
	June 30,
	2010			2011
	(unaudited, in thousands)

Cash Flows From Operating Activities:
Net income	$	1,492		$	10,246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		3,629			2,419
Accretion of discount on asset retirement obligations		64			32
Dry holes and abandonments of unproved properties		44			772
Unrealized loss (gain) on derivative instruments, net		(545	)		(1,046	)
Gain on sale of assets		(353	)		(1,209	)
Changes in operating assets and liabilities:
Accounts receivable		(553	)		(2,163	)
Prepaids and other		579			54
Other assets		(92	)		(75	)
Inventory		(148	)		(27	)
Accounts payable		75			(4,187	)
Accrued liabilities		(94	)		454
Revenue payable		(38	)		42
Advance billings and other		2,625			(120	)

Net cash provided by operating activities		6,685			5,192

Cash Flows From Investing Activities:
Additions to oil and natural gas properties		(4,335	)		(11,825	)
Additions to other property and equipment		(250	)		(679	)
Proceeds from sale of other property and equipment		607			1,219
Proceeds from sale of property and equipment to affiliate		—			4,000
Proceeds from sale of subsidiary, net of cash sold		—			2,095
Acquisitions of oil and natural gas properties		(4,306	)		(8,161	)

Net cash used in investing activities		(8,284	)		(13,351	)

Cash Flows From Financing Activities:
Proceeds from credit facilities		2,300			15,950
Payments on credit facilities		(1,200	)		(7,900	)
Borrowings on note payable		5			412
Payments on note payable		(47	)		(84	)
Repurchase member units		—			(1	)

Net cash provided by financing activities		1,058			8,377

Net increase (decrease) in cash and cash equivalents		(541	)		218
Beginning Cash and Cash Equivalents		763			222

Ending Cash and Cash Equivalents	$	222		$	440

Supplemental Cash Flow Information:
Cash paid for interest	$	12		$	189

Non-Cash Investing and Financing Activities:
Accrued capital expenditures—oil and gas properties	$	1,257		$	310

Accounts and notes receivable from officers, directors and employees	$	—		$	58

Deferred gain on sale of property and equipment to affiliate	$	—		$	2,766

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

F-15

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited)


1.	Organization and Nature of Operations

Mid-Con Energy, I LLC and Mid-Con Energy II, LLC (collectively, with subsidiaries of Mid-Con Energy II, LLC, the “predecessor”) are Delaware limited liability companies. The predecessor’s principal business is the acquisition, development and production of existing oil and natural gas properties in the Mid-Continent region of the United States. The predecessor uses secondary oil recovery techniques, such as waterflooding, to increase production from mature oil fields. Mid-Con Energy II, LLC’s wholly owned subsidiaries are RDT Properties, Inc. (“RDT”) and ME3 Oilfield Services, LLC (“ME3”). RDT is the sole operator of mineral properties owned by the predecessor, and ME3 provides oil field construction and maintenance services, as well as oil and water transportation services, to the predecessor and to third parties.

On June 30, 2011, Mid-Con Energy III, LLC, an affiliate of our predecessor, purchased RDT, ME3 and certain oil and gas properties from the predecessor. Because this was a transaction of companies under common control, the excess of the cash that our predecessor received over the book value of the net assets transferred to Mid-Con Energy III, LLC was recorded as a capital contribution and no gain was recognized. The accompanying balance sheet as of June 30, 2011, reflects the sale of these subsidiaries and properties. The results of operations for these subsidiaries and properties are included in the accompanying statements of operations and cash flows for all periods presented.

In connection with the closing of the initial public offering of common units of Mid-Con Energy Partners, LP (the “Partnership”), the predecessor will merge with and into a wholly owned subsidiary of the Partnership in exchange for a combination of common and subordinated units issued, and cash consideration paid, to the predecessor’s owners.


2.	Summary of Significant Accounting Policies

Basis of presentation and principles of combination

The accompanying combined financial statements were derived from the historical accounting records of the predecessor and reflect the historical financial position, results of operations and cash flow for the periods described herein. All intercompany transactions and account balances have been eliminated. The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The predecessor operates oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. The predecessor’s management evaluates performance based on one business segment as there are not different economic environments within the operation of the oil and natural gas properties.

The accompanying combined financial statements of the predecessor have not been audited, except that the combined balance sheet at December 31, 2010 is derived from the predecessor’s audited combined financial statements. In the opinion of management, the accompanying combined financial statements reflect all adjustments necessary to present fairly the predecessor’s financial position at June 30, 2011, and its results of operations and cash flow for the six months ended June 30, 2010 and 2011. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these combined financial statements. Accordingly, these combined financial statements should be read with the audited combined financial statements and notes included elsewhere in this prospectus.

F-16

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

Use of estimates

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of business combinations and fair value of derivative financial instruments.

Accounts receivable

The predecessor sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and gas wells. The predecessor’s joint interest and oil and gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Amounts are considered past due after 30 days. The predecessor determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the predecessor’s ability to realize the receivables through netting of anticipated future production revenues. The predecessor had no allowance for doubtful accounts at December 31, 2010 and June 30, 2011 and there were no provisions for bad debts or write-offs of accounts receivable for the six months ended June 30, 2010 or 2011.

Revenue recognition

The predecessor uses the sales method of accounting for crude oil and natural gas revenues. Under this method, revenues are recognized based on the predecessor’s share of actual proceeds from oil and gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. The predecessor had no significant natural gas imbalances at December 31, 2010 or June 30, 2011.

Oil and natural gas properties

The predecessor utilizes the successful efforts method of accounting for its oil and gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs relating to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. The predecessor had no exploratory wells in progress and no capitalized exploratory well costs pending determination of reserves at December 31, 2010 or June 30, 2011.

Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are

F-17

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned.

Costs of significant nonproducing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depreciation until the related project is completed. The predecessor capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. At December 31, 2010 and June 30, 2011, the predecessor had no capitalized interest.

The predecessor reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves based on the predecessor’s expectations of future oil and gas prices and costs. The predecessor reviews its oil and gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base. The predecessor did not recognize any impairments of proved oil and gas properties for the six months ended June 30, 2010 or 2011.

Unproved oil and gas properties are each periodically assessed for impairment by comparing their costs to their estimated values on a project-by-project basis. The estimated value is affected by the results of exploration activities, future drilling plans, commodity price outlooks, planned future sales or expiration of all or a portion of leases on such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the predecessor recognizes an impairment loss at that time. The predecessor recognized approximately $44,000 and $0.8 million as abandonment expense for the six months ended June 30, 2010 and 2011, related to its unproved oil and gas properties.

Other property and equipment

Other property and equipment is stated at historical cost and is comprised of software, vehicles, office equipment, and field service equipment. Costs incurred for normal repairs and maintenance are charged to expense as incurred, unless they extend the useful life of the asset. Depreciation is calculated using the straight-line method based on useful lives of the assets ranging from three to fifteen years and is included in the accumulated depreciation, depletion and amortization totals. Depreciation expense related to other property and equipment for the six months ended June 30, 2010 and 2011 totaled approximately $0.5 million and $0.3 million, respectively. All of the other property and equipment was sold to Mid-Con Energy III, LLC at June 30, 2011.

Derivatives and hedging

All derivative instruments are recorded on the balance sheet as either assets or liabilities at fair value. Derivative instruments that do not meet specific hedge accounting criteria must be adjusted to fair value through net income. Effective changes in the fair value of derivative instruments that are accounted for as cash flow hedges are recognized in other accumulated comprehensive income in members’ equity until such time as the hedged items are recognized in net income. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income.

F-18

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

None of the predecessor’s derivatives held during 2010 and 2011 were designated as hedges for financial statement purposes; therefore, the adjustments to fair value are included in net income. Realized and unrealized gains and losses on derivatives are included in cash flow from operating activities.

Inventory

Inventory consists primarily of oilfield equipment and is valued at the lower of cost or market. No excess or obsolete reserve has been recorded at December 31, 2010. All of the predecessor’s inventory was sold to Mid-Con Energy III, LLC at June 30, 2011.

Other revenue and expense, net

The predecessor receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of other revenue and expense, net. Such fees totaled approximately $1.5 million and $2.1 million for the six months ended June 30, 2010 and 2011, respectively.

Income taxes

The entities comprising the predecessor are two limited liability companies, and, as such, their earnings or losses for federal and state income tax purposes are generally included in the tax returns of the individual unitholders of the predecessor. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the limited liability agreements of the predecessor.

The predecessor evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the predecessor determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The predecessor had no uncertain tax positions that required recognition in the financial statements at December 31, 2010 or June 30, 2011. Any interest or penalties would be recognized as a component of income tax expense.

New accounting pronouncements

F-19

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

annual reporting period. In practice, some preparers have presented the pro forma information in their comparative financial statements as if the business combination that occurred in the current reporting period had occurred as of the beginning of each of the current and prior annual reporting periods. Other preparers have disclosed the pro forma information as if the business combination occurred at the beginning of the prior annual reporting period only, and carried forward the related adjustments, if applicable, through the current reporting period. The predecessor plans to adopt the updated rules in relation to all future business combinations.

In January 2010, the FASB issued an accounting standards update for improving disclosure about fair value measurements. This amendment provides guidance that clarifies and requires new disclosures about fair value measurements. The clarifications and requirement to disclose the amounts and reasons for significant transfers between Level 1 and Level 2, as well as significant transfers in and out of Level 3 of the fair value hierarchy, were adopted by the predecessor in 2010. Note 4—Fair Value Measurements reflects the amended disclosure requirements. The new guidance also requires that purchases, sales, issuances, and settlements be presented on a gross basis in the Level 3 reconciliation and that requirement is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years, with early adoption permitted. Since this new guidance only amends the disclosures requirements, it did not impact the predecessor’s statement of financial position, statement of operations, or cash flow statement.


3.	Acquisitions

On June 30, 2011, the predecessor acquired two waterflood units, the War Party I and II Units, for a purchase price of $7.2 million. The predecessor is currently engaged in a workover program to return a number of inactive wells in these units to production, optimize producing well rates and increase injection. The predecessor expects that this program will be substantially completed by September 30, 2011.


4.	Fair Value Measurement

The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts payable and derivative financial instruments approximate their fair values. The recorded values of the predecessor’s credit facilities approximate fair value as the interest rate is variable and the terms of the credit facilities are similar to what the predecessor believes comparable companies would receive.

The predecessor accounts for its oil and gas commodity derivatives at fair value. The fair value of derivative financial instruments is determined utilizing the New York Mercantile Exchange (“NYMEX”) closing prices for the contract period.

The predecessor has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

F-20

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

Financial assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation techniques as follows:

Level 1 —Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2 —Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

Level 3 —Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. The following presents the predecessor’s fair value hierarchy for assets and liabilities measured at fair value on June 30, 2011:


	Level 1		Level 2		Level 3
	(in thousands)

June 30, 2011
Assets and Liabilities Measured as Fair Value on a Recurring Basis
—Derivative financial instruments—asset	$	—	$	529	$	—
—Derivative financial instruments—liability	$	—	$	387	$	—
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
—Asset retirement obligations	$	—	$	—	$	405

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the predecessor’s combined balance sheet.

The predecessor estimates the fair value of the asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 5 for a summary of changes in AROs.

F-21

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

carrying amount of the asset. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.


5.	Asset Retirement Obligations

Asset retirement obligations are recorded as a liability at their estimated present value at the various assets’ inception, with the offsetting charge to oil and gas properties. Periodic accretion of the discounted estimated liability is recorded in the statement of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves.

The predecessor’s asset retirement obligations primarily represent the estimated present value of the amount the predecessor will incur to plug, abandon and remediate its producing properties at the end of their production lives, in accordance with applicable state laws. The predecessor has determined its asset retirement obligations by calculating the present value of estimated cash flow related to the liability. The following is a reconciliation of the asset retirement obligation at June 30, 2011 (in thousands):


Asset retirement obligations at December 31, 2010	$	2,148
Liabilities incurred for new wells		311
Disposition of wells		(1,024	)
Revision in estimates		94
Accretion expense		32

Asset retirement obligations at June 30, 2011	$	1,561


6.	Derivative Financial Instruments

The predecessor is exposed to commodity price risk and considers it prudent to periodically reduce the predecessor’s exposure to cash flow variability resulting from commodity price change fluctuations. Accordingly, the predecessor enters into derivative instruments to manage its exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices.

At December 31, 2010 and June 30, 2011 the predecessor’s open positions consisted of crude oil price collar contracts and crude oil price swap contracts. Under commodity swap agreements, the predecessor exchanges a stream of payments over time according to specified terms with another counterparty. In a typical commodity swap agreement, the predecessor agrees to pay an adjustable or floating price tied to an agreed upon index for the oil commodity and in return receives a fixed price based on notional quantities. A collar is a combination of a put purchased by a party and a call option written by the same party. In a typical collar transaction, if the floating price based on a market index is below the floor price, the predecessor receives from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, the predecessor must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

F-22

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

The predecessor elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the statement of operations. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, the predecessor presents the fair value of derivative financial instruments on a net basis.

At June 30, 2011 the predecessor had the following commodity derivative open positions:


	Settlement						Instrument	Total		NYMEX
Months Outstanding	Price		Floor		Ceiling		Type	Bbls		Index	Fair Value
											(in thousands)

Jul-Dec 2011	$	83.25					Price Swap		18,000	WTI	$	(248	)
Jul-Dec 2011	$	86.75					Price Swap		18,000	WTI		(181	)
Jul-Dec 2011	$	85.30					Price Swap		12,000	WTI		(139	)
Jul-Dec 2011	$	89.55					Price Swap		18,000	WTI		(129	)
Jul-Dec 2011	$	100.25					Price Swap		36,000	WTI		163
Jan-Dec 2012	$	104.28					Price Swap		72,000	WTI		297
Jan-Dec 2012	$	100.00					Price Swap		96,000	WTI		6
Jan-Dec 2012			$	100.00	$	117.00	Collar		72,000	WTI		(23	)
Jan-Dec 2013	$	105.80					Price Swap		72,000	WTI		396
Jan-Dec 2013			$	100.00	$	111.00	Collar		72,000	WTI		—

At June 30, 2011, the predecessor recorded the estimated fair value of the derivative contracts as $0.5 million as a long-term asset and $0.4 million as a short term liability.

The predecessor’s derivative contracts are secured by an agreement with one of the predecessor’s purchasers; whereby, the derivative counterparty can seek payment directly from the predecessor’s purchaser on the predecessor’s oil production under the contract, should the predecessor be in default of the contract.

A certain officer and member of the predecessor is entitled to, or responsible for, as applicable, 10% of the receivable or payable, respectively, on the monthly settlement from or to, as applicable, the derivative counterparty.


7.	Members Equity

Membership Units

In June 2011, certain employees of the predecessor purchased a total of 5,770 Class C Units of Mid-Con Energy I, LLC. The employees paid a purchase price of $10 per unit, consisting of 25% cash and a full recourse note for the remaining 75%. The aggregate amount of the notes was $43,000. The units are subject to a restricted period of four years, beginning on the date the individual began serving as an employee of the predecessor. During the restricted period, the employee may not sell, transfer, pledge, exchange or otherwise dispose of the units. The units vest ratably over the restricted period. All awards immediately vest upon a change of control of the predecessor. If the individual’s employment or service to the predecessor is terminated prior to vesting, the individual has no further rights to the unvested units and the predecessor has the right to repurchase any or all of the vested and unvested units.

In June 2011, certain employees of the predecessor were granted a total of 13,760 non-vested Class C Units of Mid-Con Energy II, LLC. These unit awards are subject to a restricted period of four years, beginning on the date of grant. During the restricted period, the employees may not

F-23

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

sell, transfer, pledge, exchange or otherwise dispose of the units. The units vest ratably over the restricted period. All awards immediately vest upon a change of control of the predecessor. If the employee’s employment or service to the predecessor is terminated prior to vesting, that person has no further rights to the Class C units.

The following is an analysis of non-vested Class C Units for the six month ended June 30, 2011:


Beginning non-vested Class C Units outstanding			35,254
Awards granted			13,760
Awards cancelled			—
Awards vested			—

Ending non-vested Class C Units outstanding			49,014

Notes Receivable from Officers, Directors and Employees

At June 30, 2011, the predecessor had notes receivable from various officers, directors and employees totaling $2.1 million, including accrued interest. The maturity date of the notes is defined as the earlier of the date upon which the predecessor or any successor to the predecessor registers any class of its stock under Section 12 of the Securities Exchange Act of 1934 (the “Exchange Act”); is required to file periodic reports under Section 15(d) of the Exchange Act; the date a registration statement filed under the Securities Act of 1933 is declared effective; or April 2, 2013 for Mid-Con Energy I, LLC units and June 15, 2016 for Mid-Con Energy II, LLC units. The stated annual interest rate on all notes is 6%. Interest is compounded annually. All accrued and unpaid interest on the notes is due and payable at maturity. All such notes receivable were originally issued in conjunction with purchases of the predecessor’s membership units by the predecessor’s officers, directors and employees. Performance of the predecessor’s officers’, directors’ and employees’ obligations under these notes is secured by security interests granted by each of them to the predecessor in all of the membership units purchased. Additionally, the predecessor has full recourse against the assets of the predecessor’s officers, directors and employees for collection of amounts due upon the occurrence of a default that is not remedied.


8.	Debt

Debt at December 31, 2010 and June 30, 2011 consisted of the following:


	December 31,		June 30,
	2010		2011
	(in thousands)
Revolving credit facilities	$	5,260	$	13,310
Term loans		253		—

		5,513		13,310
Less: Current portion		5,354		—

Long-term debt	$	159	$	13,310

The predecessor has a borrowing capacity of $22.0 million under two revolving credit facilities with a financial institution. The total borrowing base is also $22.0 million, re-determined semi-annually based on the predecessor’s oil and natural gas reserves. Interest is payable

F-24

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) — (continued)

monthly and charged at the financial institution’s prime rate (4% at June 20, 2011). The predecessor’s oil properties located in southern Oklahoma are pledged as security under the agreements. The predecessor had approximately $5.3 million and $13.3 million borrowed against their credit facilities at December 31, 2010 and June 30, 2011, respectively. Any amounts outstanding are due at maturity in December 2013. There were no outstanding letters of credit as of December 31, 2010 or June 30, 2011.

During 2009, the predecessor entered into a variable rate term loan for approximately $350,000. The loan bears interest at New York Prime Rate (3.25% at June 30, 2011) and matures on October 9, 2013. During 2011, the predecessor entered into an additional variable rate term loan for approximately $400,000. The loan bears interest at Wall Street Journal Prime rate plus 1% (5.5% at June 30, 2011) and matures on February 9, 2015. These term loans were assumed by Mid-Con Energy III, LLC on June 30, 2011 in connection with the transfer of ME3 from the predecessor to Mid-Con Energy III, LLC.

F-25

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Mid-Con Energy GP, LLC

We have audited the accompanying combined balance sheets of Mid-Con Energy I, LLC (a Delaware limited liability company) and Mid-Con Energy II, LLC (a Delaware limited liability company) and subsidiaries as of December 31, 2009 and 2010, and the related combined statements of operations, members’ equity and cash flow for the period from inception (July 1, 2009) to December 31, 2009 and for the year ended December 31, 2010. These financial statements are the responsibility of the Companies’ 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. The Companies are not required to have, nor were we engaged to perform audits of their internal control over financial reporting. Our audits 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 Companies’ 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 combined financial statements referred to above present fairly, in all material respects, the combined financial position of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC and subsidiaries as of December 31, 2009 and 2010, and the results of their operations and their cash flow for the period from inception (July 1, 2009) to December 31, 2009 and for the year ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

August 12, 2011

F-26

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Balance Sheets


	As of December 31,
	2009			2010
	(in thousands)

ASSETS
Current Assets:
Cash and cash equivalents	$	763		$	222
Accounts receivable:
Oil and gas sales		1,321			2,134
Joint operations and other		913			1,548
Certificate of deposit—government bond		150			150
Inventory		259			771
Prepaids and other		751			147

Total current assets		4,157			4,972

Property and Equipment:
Oil and gas properties, successful efforts method:
Proved properties		37,523			57,873
Unproved properties		397			446
Other property and equipment		1,482			2,324
Accumulated depreciation, depletion and amortization		(2,677	)		(8,795	)

Total property and equipment, net		36,725			51,848

Other Assets		117			239

Total assets	$	40,999		$	57,059


LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities:
Accounts payable	$	404		$	2,785
Accrued liabilities		392			399
Revenue payable		136			182
Advance billings and other		489			1,864
Current portion of long-term debt		94			5,354
Derivative financial instruments		222			904

Total current liabilities		1,737			11,488

Long-Term Debt		243			159

Asset Retirement Obligations		1,737			2,148

Members’ Equity:
Contributed capital		47,083			52,933
Notes receivable from officers, directors and employees		(1,198	)		(1,833	)
Accumulated deficit		(8,603	)		(7,836	)

Total members’ equity		37,282			43,264

Total liabilities and members’ equity	$	40,999		$	57,059

The accompanying notes are an integral part of these combined balance sheets.

F-27

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Statements of Operations


	Period from
	Inception			Year
	(July 1, 2009) to			Ended
	December 31,			December 31,
	2009			2010
	(in thousands)

Revenues:
Oil sales	$	5,729		$	16,853
Natural gas sales		743			1,418
Realized loss on derivatives, net		(350	)		(90	)
Unrealized loss on derivatives, net		(147	)		(707	)

Total revenues		5,975			17,474

Operating costs and expenses:
Lease operating expenses		2,431			6,237
Oil and gas production taxes		269			822
Dry holes and abandonments of unproved properties		—			1,418
Geological and geophysical		979			394
Depreciation, depletion and amortization		2,503			6,217
Accretion of discount on asset retirement obligations		58			127
General and administrative		704			982
Impairment of proved oil and gas properties		7,785			1,831

Total operating costs and expenses		14,729			18,028

Loss from operations		(8,754	)		(554	)

Other income (expense):
Interest income and other		35			218
Interest expense		(2	)		(98	)
Gain on sale of assets		—			354
Other revenue and expense, net		118			847

Total other income (expenses)		151			1,321

Net income (loss)	$	(8,603	)	$	767

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

F-28

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Statements of Members’ Equity


				Notes
				Receivable
				from Officers,						Total
	Contributed			Directors and			Accumulated			Members’
	Capital			Employees			Deficit			Equity
	(in thousands)

Beginning LLC Balances at July 1, 2009:
Mid-Con Energy I, LLC	$	42,002		$	(552	)	$	—		$	41,450
Mid-Con Energy II, LLC		6,580			(646	)		—			5,934

		48,582			(1,198	)		—			47,384
Distributions		(1,499	)		—			—			(1,499	)
Net loss		—			—			(8,603	)		(8,603	)

Balance at December 31, 2009:		47,083			(1,198	)		(8,603	)		37,282
Contributions		10,646			(646	)		—			10,000
Distributions		(4,785	)		—			—			(4,785	)
Repurchase of member units		(15	)		11			—			(4	)
Other		4			—			—			4
Net income		—			—			767			767

Balance at December 31, 2010:	$	52,933		$	(1,833	)	$	(7,836	)	$	43,264

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

F-29

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Combined Statements of Cash Flow


	Period from
	Inception			Year
	(July 1, 2009) to			Ended
	December 31,			December 31,
	2009			2010
	(in thousands)

Cash Flows From Operating Activities:
Net income (loss)	$	(8,603	)	$	767
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		2,503			6,217
Accretion of discount on asset retirement obligations		58			127
Dry holes and abandonments of unproved properties		—			1,418
Impairment of proved oil and gas properties		7,785			1,831
Unrealized loss on derivative instruments, net		147			707
Gain on sale of assets		—			(354	)
Changes in operating assets and liabilities:
Accounts receivable		(198	)		(1,473	)
Prepaids and other		(649	)		539
Other assets		(100	)		(134	)
Inventory		37			(512	)
Accounts payable		(381	)		1,172
Accrued liabilities		(418	)		7
Revenue payable		5			46
Advance billings and other		(200	)		1,440

Net cash provided by (used in) operating activities		(14	)		11,798

Cash Flows From Investing Activities:
Additions to oil and gas properties		(2,660	)		(15,936	)
Additions to other property and equipment		(734	)		(922	)
Proceeds from sale of other property and equipment		—			608
Acquisitions of oil and natural gas properties		(645	)		(6,484	)
Other		—			8

Net cash used in investing activities		(4,039	)		(22,726	)

Cash Flows From Financing Activities:
Proceeds from line of credit		—			15,760
Payments on line of credit		—			(10,500	)
Borrowings on note payable		351			10
Payments on note payable		(16	)		(94	)
Members’ contribution		—			10,000
Distributions paid		(1,499	)		(4,785	)
Repurchase member units		—			(4	)

Net cash provided by (used in) financing activities		(1,164	)		10,387

Net decrease in cash and cash equivalents		(5,217	)		(541	)

Beginning Cash and Cash Equivalents		5,980			763

Ending Cash and Cash Equivalents	$	763		$	222

Supplemental Cash Flow Information:
Cash paid for interest	$	2		$	95

Non-Cash Investing and Financing Activities:
Accrued capital expenditures—oil and gas properties	$	178		$	1,209

Notes receivable from officers, directors and employees	$	—		$	635

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

F-30

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010


1.	Organization and Nature of Operations

Mid-Con Energy, I LLC and Mid-Con Energy II, LLC (collectively, with their subsidiaries of Mid-Con Energy II, LLC, the “predecessor”) are Delaware limited liability companies. The predecessor’s principal business is the acquisition, development and production of existing oil and natural gas properties in the Mid-Continent region of the United States. The predecessor uses secondary oil recovery techniques, such as waterflooding to increase production from mature oil fields. Mid-Con Energy II, LLC’s wholly owned subsidiaries are RDT Properties, Inc. (“RDT”) and ME3 Oilfield Services, LLC (“ME3”). RDT is the sole operator of mineral properties owned by the predecessor and ME3 provides oil field construction and maintenance services, as well as oil and water transportation services, to the predecessor and third parties.

On June 30, 2009, Mid-Con Energy Corporation and its subsidiaries (collectively, the “Corporation”), reorganized to form the predecessor. As a result of this reorganization, the mineral properties were transferred to the predecessor, along with the related accounts receivable, accounts payable and cash. RDT and ME3 were transferred to Mid-Con Energy II, LLC. The reorganization also resulted in issuance of notes receivable from certain officers, directors and shareholders, for the purchase of membership units.


2.	Summary of Significant Accounting Policies

Basis of presentation and principles of combination

In the reorganization of the Corporation into the predecessor, the majority owner of the Corporation became the majority owner in the predecessor and made additional cash contributions to the predecessor. Therefore, management of the predecessor determined that the reorganization constituted a transaction between entities under common control. In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the predecessor based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to members’ equity.

In addition to the cash contributions from the majority owner, in the reorganization of the Corporation into the predecessor, certain officers and directors of the predecessor purchased Class A Units in consideration of full recourse notes payable to the predecessor (see Note 6.) The predecessor also recognized an increase to equity of approximately $0.5 million related to elimination of deferred tax balances of the Corporation. As discussed below, as limited liability companies, the earnings or losses of the predecessor for federal and some state income tax purposes will generally be included in the tax returns of the individual unitholders of the predecessor.

F-31

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The predecessor operates oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. The predecessor’s management evaluates performance based on one business segment as there are not different economic environments within the operation of the oil and natural gas properties.

Use of estimates

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, purchase price allocations and fair value of derivative financial instruments.

Cash and cash equivalents

The predecessor considers all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.

Accounts receivable

The predecessor sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and gas wells. The predecessor’s joint interest and oil and gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Amounts are considered past due after 30 days. The predecessor determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the predecessor’s ability to realize the receivables through netting of anticipated future production revenues. The predecessor had no allowance for doubtful accounts at December 31, 2009 or 2010, and there were no provisions for bad debts or write-offs of accounts receivable for the periods then ended.

Revenue recognition

The predecessor uses the sales method of accounting for crude oil and natural gas revenues. Under this method, revenues are recognized based on the predecessor’s shares of actual proceeds from oil and gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. The predecessor had no significant natural gas imbalances at December 31, 2009 or 2010.

F-32

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

Oil and natural gas properties

Capitalized costs of individual properties abandoned or retired are charged to accumulated depreciation, depletion and amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned.

Costs of significant nonproducing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depreciation until the related project is completed. The predecessor capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. At December 31, 2009 and December 31, 2010, the predecessor had no significant amount of capitalized interest.

The predecessor recognized approximately $7.8 million and $1.8 million as impairment charges against earnings for the periods ended December 31, 2009 and 2010, respectively, related to its proved oil and gas properties due to a significant decline in estimated proved and probable reserves values. These non-cash charges are included in the “Impairment of proved oil and gas properties” line item in the accompanying statements of operations. The fair value of the properties was measured by estimated cash flow reported in the audited reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs in the fair value hierarchy described in Note 3. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and development costs, future commodity prices and market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Corporation’s estimated cash flow are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities,

F-33

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

anticipated drilling and operating costs, anticipated production taxes, future expected oil and natural gas prices. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future oil and natural gas prices. The impairments were caused by below expected performance for some of the waterflood units and other producing properties and revisions to the future expected drilling schedules. These impairments have no impact on the predecessor’ cash flow, liquidity position, or debt covenants.

Unproved oil and gas properties are each periodically assessed for impairment by comparing their costs to their estimated values on a project-by-project basis. The estimated value is affected by the results of exploration activities, future drilling plans, commodity price outlooks, planned future sales or expiration of all or a portion of leases on such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the predecessor recognizes an impairment loss at that time. The predecessor had no abandonments for the period from inception (July 1, 2009) to December 31, 2009. The predecessor recognized approximately $1.4 million as abandonment expenses for the year ended December 31, 2010, related to its unproved oil and gas properties.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that aligns the oil and natural gas reserve estimation and disclosure requirements of GAAP with the requirements in the final rule, Modernization of the Oil and Gas Reporting Requirements , issued in December 31, 2008 by the United States Securities and Exchange Commission (“SEC”) and effective for fiscal years ending on or after December 31, 2009. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies. The new rules permit the use of new technologies to determine proved reserves estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. The new rules will also allow, but not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The predecessor adopted the updated requirements as of December 31, 2009, which had the effect of adding 307 MBoe of proved reserves. See reserves information in Note 11.

Oil and gas property is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following:


	December 31,
	2009		2010
	(in thousands)

Oil and gas properties
Proved properties	$	37,523	$	57,873
Unproved properties		397		446

		37,920		58,319
Less: Accumulated depletion, depreciation and amortization		2,309		7,838

Oil and gas properties, net	$	35,611	$	50,481

F-34

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

Other property and equipment

Depreciation expense related to other property and equipment for the periods ended December 31, 2009 and 2010 totaled $0.2 million and $0.6 million, respectively. Other property and equipment consist of the following:


	December 31,
	2009		2010
	(in thousands)

Land	$	19	$	19
Leasehold improvements (15 years)		33		33
Hardware and software (3-5 years)		249		282
Furniture and fixtures (5 years)		88		88
Machinery and equipment (5 years)		1,073		1,882
Field building (15 years)		20		20

		1,482		2,324
Less: accumulated depreciation		368		957

Other property, plant and equipment, net	$	1,114	$	1,367

Asset retirement obligations

The predecessor has obligations under its lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal 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. The predecessor is required to record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. The predecessor typically incurs this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.

Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted

F-35

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the combined statements of operations.

Derivatives and hedging

None of the predecessor’s derivatives held during 2010 and 2009 were designated as hedges for financial statement purposes; therefore, the adjustments to fair value are included in net income. Realized and unrealized gains and losses on derivatives are shown separately in the statement of operations and are included in cash flow from operating activities.

Inventory

Inventory consists primarily of oilfield equipment and is valued at the lower of cost or market. No excess or obsolete reserve has been recorded at December 31, 2009, or December 31, 2010.

Deferred financing costs

Costs incurred in connection with the execution or modification of the predecessor’s credit facilities were expensed as incurred based on the immateriality of costs.

Other noncurrent assets

The predecessor has accrued interest receivable related to notes receivable from officers, directors and employees, which is classified as other noncurrent assets on the combined balance sheet.

Other revenue and expense, net

The predecessor receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of other revenue and expense, net. Such fees totaled $1.2 million and $3.1 million for the period from inception (July 1, 2009) to December 31, 2009, and the year ended December 31, 2010, respectively.

Unit-based compensation

The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value of compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. Compensation for these awards is recorded upon vesting, based on their grant-date fair value. Generally, no compensation expense is recognized for equity instruments that do not vest. The unit-based compensation expense was not significant for either of the periods presented.

F-36

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

Income taxes

The entities comprising the predecessor are two limited liability companies, and, as such, their earnings or losses for federal and some state income tax purposes will generally be included in the tax returns of the individual unitholders of the predecessor. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the limited liability agreement of the predecessor.

The predecessor evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the predecessor determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The predecessor had no uncertain tax positions that required recognition in the financial statements at December 31, 2009 or 2010. Any interest or penalties would be recognized as a component of income tax expense.

New Accounting Pronouncements

In December 2010, the FASB issued an accounting standards update regarding disclosure of supplementary pro forma information for business combinations. This update was issued in order to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements. The update requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. If comparative financial statements are presented, the pro forma revenue and earnings of the combined entity for the comparable prior reporting period should be reported as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period. In practice, some preparers have presented the pro forma information in their comparative financial statements as if the business combination that occurred in the current reporting period had occurred as of the beginning of each of the current and prior annual reporting periods. Other preparers have disclosed the pro forma information as if the business combination occurred at the beginning of the prior annual reporting period only, and carried forward the related adjustments, if applicable, through the current reporting period. The predecessor plans to adopt the updated rules in relation to all future business combinations.

In January 2010, the FASB issued an accounting standards update for improving disclosure about fair value measurements. This amendment to the disclosure requirements provides guidance that clarifies and requires new disclosures about fair value measurements. The clarifications and requirement to disclose the amounts and reasons for significant transfers between Level 1 and Level 2, as well as significant transfers in and out of Level 3 of the fair value hierarchy, were adopted by the predecessor in the last quarter of 2010. Note 3— Fair Value Measurements reflects the amended disclosure requirements. The new guidance also requires that purchases, sales, issuances, and settlements be presented gross in the Level 3 reconciliation and that requirement is effective for fiscal years beginning after December 15, 2010 and for

F-37

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

interim periods within those years, with early adoption permitted. Since this new guidance only amends the disclosures requirements, it did not impact the statement of financial position, statement of operations, or cash flow statement.


3.	Fair Value Measurement

The predecessor accounts for its oil and gas commodity derivatives at fair value. The fair value of derivative financial instruments is determined utilizing the NYMEX closing prices for the contract period.

The predecessor has categorized their financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation techniques as follows:

Level 1 —Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

F-38

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

or liabilities. The following presents the predecessor’s fair value hierarchy for assets and liabilities measured at fair value on December 31, 2009 and December 31, 2010.


	Level 1		Level 2		Level 3
	(in thousands)

December 31, 2009
Assets and Liabilities Measured at Fair Value on a Recurring Basis
—Derivative financial instruments—liability	$	—	$	222	$	—
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
—Asset retirement obligations	$	—	$	—	$	1,679
—Impairment of proved oil and gas properties	$	—	$	—	$	7,785
December 31, 2010
Assets and Liabilities Measured at Fair Value on a Recurring Basis
—Derivative financial instruments—liability	$	—	$	904	$	—
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
—Asset retirement obligations	$	—	$	—	$	319
—Impairment of proved oil and gas properties	$	—	$	—	$	1,831

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the predecessor’s combined balance sheet.

The predecessor reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the predecessor recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset and reduces the carrying amount of the asset. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.


4.	Asset Retirement Obligations

F-39

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

The predecessor’s asset retirement obligations primarily represent the estimated present value of the amount the predecessor will incur to plug, abandon and remediate its producing properties at the end of its production lives, in accordance with applicable state laws. The predecessor has determined their asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The following is a reconciliation of the asset retirement obligations at December 31, 2010 and 2009 (in thousands):


Asset retirement obligations at July 1, 2009	$	1,569
Liabilities incurred for new wells		115
Revision in estimates		(5	)
Accretion expense		58

Asset retirement obligations at December 31, 2009		1,737
Liabilities incurred for new wells		265
Disposition of wells		(35	)
Revision in estimates		54
Accretion expense		127

Asset retirement obligations at December 31, 2010	$	2,148


5.	Derivative Financial Instruments

The predecessor is exposed to oil commodity price risk and considers it prudent to periodically reduce its exposure to cash flow variability resulting from commodity price change fluctuations. Accordingly the predecessor enters into derivative instruments to manage its exposure to commodity price fluctuations, and fluctuations in location differences between published index prices and the NYMEX futures prices.

At December 31, 2009 and 2010, the predecessor’s open positions consisted of crude oil price collar contracts and crude oil price swap contracts. Under commodity swap agreements, the predecessor exchanges a stream of payments over time according to specified terms with another counterparty. In a typical commodity price swap agreement, the predecessor agrees to pay an adjustable or floating price tied to an agreed upon index for the oil commodity and in return receives a fixed price based on notional quantities. A collar is a combination of a put purchased by a party and a call option written by the same party. In a typical collar transaction, if the floating price based on a market index is below the floor price, the predecessor receives from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, the predecessor must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

The predecessor elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the statement of operations. The predecessor recorded its derivative activities on a mark-to-market or fair value basis. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, the predecessor presents the fair value of derivative financial instruments on a net basis.

F-40

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

At December 31, 2009 the predecessor had the following commodity derivative open positions:


	Settlement						Instrument	Total		NYMEX
Months Outstanding	Price		Floor		Ceiling		Type	Bbls		Index		Fair Value
												(in thousands)

Jan 2010 – Dec 2010			$	72.50	$	83.00	Collar		5,000		WTI	$	(184	)
Jan 2011 – June 2011	$	77.45					Price Swap		2,000		WTI		(38	)

At December 31, 2010 the predecessor had the following commodity derivative open positions:


	Settlement				Instrument	Total		NYMEX
Months Outstanding	Price		Floor	Ceiling	Type	Bbls		Index		Fair Value
										(in thousands)

Jan 2011 – Dec 2011	$	83.25			Price Swap		18,000		WTI	$	(357	)
Jan 2011 – Dec 2011	$	86.75			Price Swap		12,000		WTI		(227	)
Jan 2011 – Dec 2011	$	85.30			Price Swap		12,000		WTI		(183	)
Jan 2011 – Dec 2011	$	89.55			Price Swap		18,000		WTI		(137	)

At December 31, 2010 and 2009, the predecessor recorded the estimated fair value of $0.9 million and $0.2 million, respectively, for these swaps and collars as current liabilities on the balance sheet.

A certain officer and unitholder of the predecessor is entitled to, or responsible for, as applicable, 10% of the receivable or payable, respectively, on the monthly settlement from or to, as applicable, the derivative counterparty.


6.	Members’ Equity

Membership Units

On July 1, 2009, Mid-Con Energy I, LLC issued Class A Units, Class B Units and Class C Units. Class A and Class B Units have voting rights. Class C Units are not entitled to voting rights. At December 31, 2010, 332,500 Class A Units, 384,022, Class B Units and 31,437 Class C Units were issued and outstanding. The Class B Units and the Class C Units will be allocated value upon all Class A Unitholders recouping their investment, plus 6%.

On July 1, 2009, Mid-Con Energy II, LLC issued Class A Units, Class B Units and Class C Units. Class A and Class B Units have voting rights. Class C Units are not entitled to voting rights. At December 31, 2010, 212,926 Class A Units, 745,674 Class B Units and 51,406 Class C Units were issued and outstanding. The Class B Units and the Class C Units will be allocated value upon all Class A Unitholders recouping their investment, plus 6%.

F-41

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

Upon formation of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, certain officers and directors purchased 6,463 Class A Units of Mid-Con Energy II, LLC at $100 per unit in consideration of full recourse notes totaling approximately $0.6 million.

In 2010, Mid-Con Energy II, LLC sold an additional 100,000 Class A Units for $100 per unit. At that time, the officers and directors holding Class A Units of Mid-Con Energy II, LLC purchased an additional 6,463 Class A Units at $100 per unit in consideration of full recourse notes totaling approximately $0.6 million.

In 2009, certain employees of the predecessor were granted a total of 51,406 non-vested Class C Units of Mid-Con Energy II, LLC. These unit awards are subject to a restricted period of four years, beginning on the date of grant. During the restricted period, the employees may not sell, transfer, pledge, exchange or otherwise dispose of the units. The units vest ratably over the restricted period. All awards immediately vest upon a change of control, of the predecessor. If the employee’s employment or service to the predecessor is terminated prior to vesting, that person has no further rights to the Class C Units. No unit awards were granted in 2010.

The following is an analysis of non-vested Class C Units for 2009 and 2010:


	Period from Inception
	(July 1, 2009) to		Year Ended
	December 31, 2009		December 31, 2010

Beginning non-vested Class C Units outstanding		—		51,406
Awards granted		51,406		—
Awards cancelled		—		(4,400	)
Awards vested		—		(11,752	)

Ending non-vested Class C Units outstanding		51,406		35,254

Notes Receivable from Officers, Directors and Employees

In the aggregate at December 31, 2009 and 2010, the predecessor had notes receivable from officers, directors and employees of $1.2 million and $1.8 million, respectively, plus accrued interest of $0.1 million and $0.2 million, respectively. The notes mature at the earlier of the date upon which the predecessor or any successor to the predecessor registers any class of its membership units under Section 12 of the Securities Exchange Act of 1934 (the “Exchange Act”); is required to file periodic reports under Section 15(d) of the Exchange Act; the date a registration statement filed under the Securities Act of 1933 is declared effective; or April 2, 2013 for Mid-Con Energy I, LLC units and June 15, 2016 for Mid-Con Energy II, LLC units. The stated annual interest rate on all notes is 6%. Interest is compounded annually. All accrued and unpaid interest on the notes is due and payable at maturity. All such notes receivable were originally issued in conjunction with purchases of the predecessor’s membership units by the predecessor’s officers, directors and employees. Performance of the predecessor’s officers, directors and employees obligations under these notes is secured by security interests granted by each of them to the predecessor in all of the membership units purchased. Additionally, the predecessor has full recourse against the assets of the predecessor’s officers, directors and employees for collection of amounts due upon the occurrence of a default that is not remedied.

F-42

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)


7.	Debt

Debt at December 31, 2009 and 2010 consisted of the following:


	December 31,
	2009		2010
	(in thousands)
Revolving credit facilities	$	—	$	5,260
Term loan		337		253

		337		5,513
Less: Current portion		94		5,354

Long-term debt	$	243	$	159

The predecessor has borrowing capacity of $17 million under two revolving credit facilities with a financial institution. The total borrowing base is also $17 million, re-determined semi-annually based on the predecessor’s oil and natural gas reserves. Interest is payable monthly and charged at LIBOR, at the financial institution’s prime rate, or 4.0%, whichever is greatest. The predecessor’s oil properties located in southern Oklahoma are pledged as security under the agreements. The predecessor had approximately $5.3 million borrowed against the lines of credit at December 31, 2010. There were no outstanding letters of credit as of December 31, 2010. The predecessor had no outstanding borrowings and no outstanding letters of credit at December 31, 2009. The revolving credit facility matures at December 31, 2011.

During 2009, the predecessor entered into a variable rate term loan for approximately $350,000. The loan bears interest at New York Prime Rate (3.25% at December 31, 2010) and matures on October 9, 2013. Payments due on the term loan are approximately $87,000 in 2011, $90,000 in 2012 and $76,000 in 2013.


8.	Credit Risk

Financial instruments which potentially subject the predecessor to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. The predecessor maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The predecessor has not experienced any significant losses from such investments.

For the six months ended December 31, 2009, purchases by Sunoco Logistics Partners L.P., ScissorTail Energy, LLC and Teppco Crude Oil, LLC accounted for 78%, 11% and 5%, respectively of the predecessor’s total sales revenues. These purchasers represented 74%, 12% and 3%, respectively, of the outstanding oil and natural gas accounts receivable for the six months ended December 31, 2009.

For the year ended December 31, 2010, purchases by Sunoco Logistics Partners L.P., ScissorTail Energy, LLC and Teppco Crude Oil, LLC accounted for 76%, 8% and 5%, respectively of the predecessor’s total sales revenues. These purchasers represented 83%, 9% and 6%, respectively, of the outstanding oil and natural gas accounts receivable for the year ended December 31, 2010.

Management believes that the loss of any one purchaser would not have an adverse effect on the ability of the predecessor to sell its oil and gas production because management believes market conditions are such that the predecessors could sell to other purchasers at market-based

F-43

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

prices. The predecessor has not experienced any significant losses due to uncollectible accounts receivable from these purchasers.


9.	Commitments and Contingencies

In the normal course of business, the predecessor enters into contracts that contain a variety of representations and warranties and provide general indemnifications. The predecessor’s maximum exposure under these arrangements is unknown as this would involve future claims that may be made against the predecessor that have not yet occurred. The predecessor does not expect to suffer any material losses in connection with these contracts.

Various federal, state and local laws and regulations covering, among other things, the release of waste materials into the environment and state and local taxes affect the predecessor’s operations and costs. Management believes the predecessor is in substantial compliance with applicable federal, state and local laws, and management expects that the ultimate resolution of any claims or legal proceedings instituted against the predecessor will not have a material effect on its financial position or results of operations.

The predecessor is party to a non-cancelable operating lease for office space for its office in Tulsa, Oklahoma. Rent expense was approximately $0.1 million and $0.2 million for the periods ended December 31, 2009 and 2010. Future minimum lease commitments under this lease at December 31, 2010, are approximately $90,000 per year in 2011 and 2012.


10.	Defined Contribution Plans

The predecessor maintains a 401(k) contribution plan (the “Plan”). Employees must be 21 years of age or older and have worked for 90 days to be eligible to participate. Employees may contribute 15% of their compensation up to the annual IRS limitation. The predecessor makes contributions of 3% of an employee’s pay and employees are 100% vested at all times. For the period from inception (July 1, 2009) to December 31, 2009, and the year ended December 31, 2010, the predecessor contributed approximately $44,000 and $107,000, respectively, to the Plan.


11.	Supplemental Oil and Gas Disclosures

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Costs incurred in the acquisition and development of oil and gas assets are presented below for the period from inception (July 1, 2009) through December 31, 2009 and for the year ended December 31, 2010 (in thousands):


	2009		2010
	(in thousands)

Property acquisition costs:
Proved	$	642	$	6,483
Unproved		4		1
Exploration		—		912
Development		3,099		16,843
Asset retirement obligations		101		353

Total costs incurred	$	3,846	$	24,592

F-44

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

Net Proved Oil and Gas Reserves—(Unaudited)

The predecessor’s proved oil and gas reserves as of December 31, 2009 were prepared by the predecessor’s reservoir engineers. The predecessor’s proved oil and gas reserves as of December 31, 2010 were audited by Cawley, Gillespie & Associates, Inc., independent third party petroleum consultants. In accordance with the updated SEC regulations, reserves at December 31, 2010 and 2009 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12—month period for oil and natural gas. Reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, for the period from inception (July 1, 2009) through December 31, 2009 and for the year ended December 31, 2010, are as follows:


	Period from Inception (July 1, 2009)
	to December 31, 2009
	Oil			Gas
	(MBbls)			(MMcf)			MBoe

Proved developed and undeveloped reserves:
Beginning of period		4,868			916			5,021
Revisions of previous estimates		1,293			29			1,298
Extensions, discoveries and other additions		113			4			114
Purchases of minerals in place		12			—			12
Production		(87	)		(140	)		(110	)

End of period		6,199			809			6,335

Proved developed reserves:
Beginning of period		2,489			834			2,628
End of period		2,513			809			2,649
Proved undeveloped reserves:
Beginning of period		2,379			82			2,393
End of period		3,686			—			3,686

F-45

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)


	Year Ended
	December 31, 2010
	Oil			Gas
	(MBbls)			(MMcf)			MBoe

Proved developed and undeveloped reserves:
Beginning of year		6,199			809			6,335
Revisions of previous estimates		(469	)		728			(347	)
Extensions, discoveries and other additions		765			—			765
Purchases of minerals in place		740			—			740
Production		(228	)		(191	)		(260	)

End of year		7,007			1,346			7,231

Proved developed reserves:
Beginning of year		2,513			809			2,649
End of year		3,601			1,346			3,825
Proved undeveloped reserves:
Beginning of year		3,686			—			3,686
End of year		3,406			—			3,406

The tables above include changes in estimated quantities of oil and natural gas reserves shown in MBoe equivalents at a rate of six Mcf per Boe.

Estimates of economically recoverable oil and natural gas 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 oil and natural gas may differ materially from the amounts estimated.

Standardized Measure of Discounted Future Net Cash Flow—(Unaudited)

The estimates of future cash flow and future production and development costs as of December 31, 2010 and 2009 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. No future income tax expenses are computed because the predecessor entities are pass-through entities for federal income tax purposes. Prices used were $61.18 and $79.43 per Bbl of oil and $3.83 and $4.37 per Mcf of natural gas for December 31, 2009 and 2010, respectively. All wellhead prices are held flat over the life of the properties for all reserve categories. The estimated future net cash flow is then discounted at a rate of 10%.

The standardized measure of discounted future net cash flow does not purport to be, nor should it be interpreted to represent, the fair market value of the proved oil and natural gas reserves of the predecessor. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In

F-46

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Notes to Combined Financial Statements

December 31, 2009 and 2010—(continued)

addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

The standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is as follows at December 31:


	2009			2010
	(in thousands)

Future cash inflows	$	343,595		$	529,309
Future production costs		(109,344	)		(152,913	)
Future development costs		(26,447	)		(26,802	)

Future net cash flow		207,804			349,594
10% discount for estimated timing of cash flow		(102,004	)		(165,932	)

Standardized measure of discounted future net cash flow	$	105,800		$	183,662

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2010 and 2009 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month in such period. Future costs of developing and producing the proved oil and reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

Changes in the standardized measure of discounted future net cash flow relating to proved oil and gas reserves for the periods form inception (July 1, 2009) to December 31, 2009 and for the year ended December 31, 2010 are as follows:


	2009			2010
	(in thousands)

Standardized measure of discounted future net cash flow, beginning of period	$	77,880		$	105,800
Changes in the year resulting from:
Sales, less production costs		(3,772	)		(11,212	)
Revisions of previous quantity estimates		24,394			(9,278	)
Extensions, discoveries and improved recovery		280			16,562
Net change in prices and production costs		(16,860	)		44,773
Net change in income taxes		36,447			—
Changes in estimated future development costs		(11,081	)		(2,170	)
Previously estimated development costs incurred during the period		2,212			9,242
Purchases of minerals in place		161			22,330
Accretion of discount		11,433			10,580
Timing differences and other		(15,294	)		(2,965	)

Standardized measure of discounted future net cash flow, end of year	$	105,800		$	183,662

F-47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Mid-Con Energy GP, LLC

We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flow of Mid-Con Energy Corporation (a Delaware corporation), and subsidiaries for the years ended June 30, 2008 and 2009. These financial statements are the responsibility of the Company’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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’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 consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flow of Mid-Con Energy Corporation and subsidiaries for the years ended June 30, 2008 and 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

August 12, 2011

F-48

Mid-Con Energy Corporation and Subsidiaries

Consolidated Statements of Operations


	Year Ended June 30,
	2008			2009
	(in thousands)

Revenues:
Oil sales	$	13,667		$	10,246
Natural gas sales		618			2,172
Realized loss on derivatives, net		(804	)		(669	)
Unrealized gain (loss) on derivatives, net		(2,035	)		1,679

Total revenues		11,446			13,428

Operating costs and expenses:
Lease operating expenses		5,005			5,369
Oil and gas production taxes		946			631
Geological and geophysical		1,296			507
Depreciation, depletion and amortization		1,786			2,802
Accretion of discount on asset retirement obligations		56			78
General and administrative		1,871			1,767

Total operating costs and expenses		10,960			11,154

Income from operations		486			2,274

Other income (expense):
Interest income and other		115			119
Interest expense		(3	)		(93	)
Other revenue and expense, net		108			298

Total other income (expense)		220			324

Income before income taxes		706			2,598

Income tax (expense) benefit:
Current		—			(625	)
Deferred		(194	)		686

Total income tax (expense) benefit		(194	)		61

Net income	$	512		$	2,659

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

F-49

Mid-Con Energy Corporation and Subsidiaries

Consolidated Statements of Stockholders’ Equity


											Notes
											Receivable
											from
											Officers,								Retained
	Series A								Additional		Director								Earnings			Total
	Preferred Stock				Common Stock				Paid-In		and			Treasury Stock					(Accumulated			Stockholders’
	Shares		Amount		Shares		Amount		Capital		Employees			Shares		Amount			Deficit)			Equity
	(in thousands)

Balance at June 30, 2007		282	$	3		344	$	3	$	28,021	$	(394	)		—	$	—		$	(619	)	$	27,014
Stock issuance		—		—		3		—		26		(25	)		—		—			—			1
Stock repurchase		—		—		—		—		—		—			—		(4	)		—			(4	)
Excess tax expense for restricted stock grants		—		—		—		—		21		—			—		—			—			21
Net income		—		—		—		—		—		—			—		—			512			512

Balance at June 30, 2008		282		3		347		3		28,068		(419	)		—		(4	)		(107	)		27,544
Stock issuance		50		—		72		1		5,165		(156	)		—		—			—			5,010
Stock repurchase		—		—		—		—		—		19			3		(38	)		—			(19	)
Net income		—		—		—		—		—		—			—		—			2,659			2,659

Balance at June 30, 2009		332	$	3		419		4	$	33,233	$	(556	)		3	$	(42	)	$	2,552		$	35,194

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

F-50

Mid-Con Energy Corporation and Subsidiaries

Consolidated Statements of Cash Flow


	For the Year Ended June 30,
	2008			2009
	(in thousands)

Cash Flow From Operating Activities:
Net income	$	512		$	2,659
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		1,786			2,802
Accretion of discount on asset retirement obligations		56			78
Bad debt expense		159			—
Unrealized (gain) loss on derivatives, net		2,035			(1,679	)
Gain on sale of assets		—			(1	)
Deferred income taxes		194			(686	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(1,255	)		373
Prepaids and other		(20	)		21
Other assets		(125	)		(54	)
Inventory		—			(299	)
Accounts payable		555			(549	)
Accrued liabilities		88			664
Revenue payable		82			(140	)
Advance billings and other		154			7,978
Derivative financial instruments		—			(232	)

Net cash provided by operating activities		4,221			10,935

Cash Flow From Investing Activities:
Additions to oil and natural gas properties		(5,555	)		(11,008	)
Additions to other property and equipment		(235	)		(360	)
Acquisitions of oil and natural gas properties		(1,856	)		(1,080	)

Net cash used in investing activities		(7,646	)		(12,448	)

Cash Flow From Financing Activities:
Proceeds from credit facilities		300			12,635
Payments on credit facilities		(150	)		(12,785	)
Purchase of treasury stock		(4	)		(19	)
Proceeds from issuance of common and Series A preferred stock		1			5,010

Net cash provided by financing activities		147			4,841

Net (decrease) increase in cash and cash equivalents		(3,278	)		3,328
Beginning Cash and Cash Equivalents		3,427			149

Ending Cash and Cash Equivalents	$	149		$	3,477

Supplemental Cash Flow Information:
Cash paid for interest	$	3		$	96

Non-Cash Investing and Financing Activities:
Accrued capital expenditures—oil and gas properties	$	308		$	2

Notes receivable from officers, directors and employees	$	25		$	137

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

F-51

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009


1.	Organization and Nature of Operations

Mid-Con Energy Corporation (collectively, with its subsidiaries, the “Corporation”) is a Delaware corporation formed on July 1, 2004. The Corporation’s principal business is the acquisition, development and production of existing oil and natural gas properties in the Mid-Continent region of the United States. The Corporation uses secondary oil recovery techniques, such as waterflooding to increase production from mature fields. The Corporation’s wholly owned subsidiaries are RDT Properties, Inc. (“RDT”) and ME3 Oilfield Services, LLC (“ME3”). RDT is the sole operator of mineral properties owned by the Corporation and ME3 provides oil field construction and maintenance services, as well as oil and water transportation services, to the Corporation and to third parties.

On June 30, 2009, the Corporation and its subsidiaries, reorganized to form two separate companies, Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (collectively, the “predecessor”). As a result of this reorganization, the mineral properties were transferred to the predecessor, along with the related accounts receivable, accounts payable and cash. RDT and ME3 were transferred to Mid-Con Energy II, LLC. The reorganization also resulted in issuance of notes receivable from certain officers, director and shareholders, for the purchase of ownership units. See further discussion of these notes receivable in Note 5.


2.	Summary of Significant Accounting Policies

Basis of presentation and principles of consolidation

The accompanying consolidated financial statements were derived from the historical accounting records of the Corporation and its wholly owned subsidiaries, RDT and ME3, and reflect the historical results of operations and cash flow for the periods described herein. All intercompany transactions and account balances have been eliminated. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Corporation operates oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. The Corporation’s management evaluates performance based on one business segment as there are not different economic environments within the operation of the oil and natural gas properties.

Use of estimates

F-52

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

not limited to, asset retirement obligations, fair value of business combinations and fair value of derivative financial instruments.

Cash and cash equivalents

The Corporation considers all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.

Accounts receivable

The Corporation sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and gas wells. The Corporation’s oil and gas sales receivables and joint interest receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts. Amounts are considered past due after 30 days. The Corporation determines joint interest operations accounts receivable allowances based on management’s assessment of the creditworthiness of the joint interest owners and the Corporation’s ability to realize the receivables through netting of anticipated future production revenues. The Corporation had bad debt expense of $0.2 million for the year ended June 30, 2008 and there were no provisions for bad debts or write-offs of accounts receivable for the year then ended June 30, 2009.

Revenue recognition

The Corporation uses the sales method of accounting for crude oil and natural gas revenues. Under this method, revenues are recognized based on the Corporation’s share of actual proceeds from oil and gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. The Corporation had no significant natural gas imbalances at June 30, 2008 or 2009.

Oil and natural gas properties

The Corporation utilized the successful efforts method of accounting for its oil and gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs relating to proved properties were depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment was based on the units-of-production method using proved developed reserves on a field basis. The Corporation had no exploratory wells in progress and no capitalized exploratory well costs pending determination of reserves at June 30, 2008 and 2009.

Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned.

Costs of significant nonproducing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depreciation until the related project is completed. The Corporation capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. The Corporation did not capitalize any interest for the years ended June 30, 2008 and 2009.

F-53

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

The Corporation reviewed its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicated that the carrying value of those assets may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves, based on the Corporation’s expectations of future oil and gas prices and costs. The Corporation reviews its oil and gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base. The Corporation did not recognize any impairments of proved oil and gas properties for the years ended June 30, 2008 or 2009.

Unproved oil and gas properties are each periodically assessed for impairment by comparing their costs to their estimated values on a project-by-project basis. The estimated value is affected by the results of exploration activities, future drilling plans, commodity price outlooks, planned future sales or expiration of all or a portion of leases on such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Corporation recognizes an impairment loss at that time. The Corporation did not have any abandonments expense for the years ended June 30, 2008 or 2009.

Other property and equipment

Depreciation expense related to other property and equipment for the years ended June 30, 2008 and 2009 totaled approximately $0.1 million and $0.2 million, respectively.

Asset retirement obligations

The Corporation has obligations under its lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal 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. The Corporation is required to record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. The Corporation typically incurs this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.

F-54

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time are reflected as additional accretion and depreciation expense in the consolidated statements of operations.

Derivatives and hedging

All derivative instruments are recorded on the balance sheet as either assets or liabilities at fair value. Derivative instruments that do not meet specific hedge accounting criteria were adjusted to fair value through net income. Effective changes in the fair value of derivative instruments that are accounted for as cash flow hedges are recognized in other accumulated comprehensive income in stockholders’ equity until such time as the hedged items are recognized in net income. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income.

None of the Corporation’s derivatives outstanding at June 30, 2008 or 2009 or during the years ended June 30, 2008 and 2009 were designated as hedges for financial statement purposes; therefore, the adjustments to fair value are included in net income. Realized and unrealized gains and losses on derivatives are shown separately in the statement of operations and were included in cash flow from operating activities in the statement of cash flow.

Other revenue and expense, net

The Corporation receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of other revenue and expense, net. Such fees totaled $1.1 million and $1.5 million for the years ended June 30, 2008 and 2009, respectively.

Treasury stock

Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury stock is reduced by the average price per share of the aggregated treasury shares held. During the years ended June 30, 2008 and 2009, the Corporation did not retire any treasury stock.

Income taxes

The Corporation accounts for income taxes in accordance with the asset and liability method under which deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date.


3.	Asset Retirement Obligations

The Corporation records asset retirement obligations as liabilities at the estimated present value at the related asset’s inception, with the offsetting charge to property costs. Periodic accretion of the discounted estimated liability is recorded in the statement of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves.

F-55

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

The Corporation’s asset retirement obligations primarily represent the estimated present value of the amount the Corporation will incur to plug, abandon and remediate its producing properties at the end of their production lives, in accordance with applicable state laws. The Corporation determined its asset retirement obligation by calculating the present value of estimated cash flow related to the liability. The following is a reconciliation of the asset retirement obligation for the years ended June 30, 2008 and 2009 (in thousands):


Asset retirement obligations at, July 1, 2007	$	672
Liabilities incurred for new wells		48
Revision in estimates		174
Accretion expense		56

Asset retirement obligations at June 30, 2008		950
Liabilities incurred for new wells		70
Revision in estimates		471
Accretion expense		78

Asset retirement obligations at June 30, 2009	$	1,569


4.	Derivative Financial Instruments

The Corporation is exposed to commodity price risk and considers it prudent to periodically reduce the Corporation’s exposure to cash flow variability resulting from commodity price change fluctuations. Accordingly, the Corporation enters into derivative instruments to manage their exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the New York Mercantile Exchange (“NYMEX”) futures prices.

Under commodity swap agreements, one party exchanges a stream of payments over time according to specified terms with another counterparty. In a typical commodity swap agreement, the Corporation agrees to pay an adjustable or floating price tied to an agreed upon index for the oil commodity and in return receives a fixed price based on notional quantities. A collar is a combination of a put purchased by a party and a call option written by the same party. In a typical collar transaction, if the floating price based on a market index is below the floor price, the Corporation receives from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, the Corporation must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

The Corporation elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the statement of operations.

The Corporation entered into a crude oil fixed price swap contract for the period of January 2008 through December 2008, with a notional amount of 5,000 barrels per month. The Corporation received a fixed price of $73.80 per Bbl and paid the average monthly NYMEX price. The swap was settled monthly and marked to market at each reporting date and all unrealized gains and losses were recognized in current earnings.

In May 2009, the Corporation entered into a crude oil fixed price swap contract for the period of June 2009 through December 2009, with a notional amount of 5,000 barrels per month. The Corporation receives a fixed price of $58.45 per Bbl and pays the average monthly NYMEX price.

F-56

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

The swap is settled monthly, marked to market at each reporting date, and all unrealized gains and losses are recognized in current earnings.

The Corporation’s derivative contracts are secured by an agreement with one of the Corporation’s purchasers whereby the derivative counterparty can seek payment directly from the Corporation’s purchaser on the Corporation’s oil production under the contract, should the Corporation be in default of the contract.

A certain officer and stockholder of the Corporation is entitled to, or responsible for, as applicable, 10% of the receivable or payable, respectively, on the monthly settlement from or to, as applicable, the derivative counterparty.


5.	Stockholders’ Equity

Preferred stock

The Corporation is authorized to issue 332,500 shares of Series A Preferred Stock, $0.01 par value. As of June 30, 2008 and 2009, 282,085 shares and 332,500, respectively, were issued and outstanding. The Series A Preferred Stock bears a 6.00% dividend payable annually in arrears. The Corporation has the election to pay the dividend in whole or in part in cash or in additional shares of Series A Preferred Stock at a redemption value of $90.00 per share. Upon liquidation, the Series A Preferred Stock is ranked senior to all other classes of shares. Dividends in arrears at June 30, 2008 and 2009, were $4.1 million and $6.3 million, respectively.

Common stock

The Corporation is authorized to issue 450,000 shares of common stock, $0.01 par value and there were 346,525 and 418,851 shares issued and outstanding at June 30, 2008 and 2009, respectively.

Under the Mid-Con Energy Corporation 2006 Stock Incentive Plan (the “Stock Plan”), shares of the Corporation’s common stock are available for issuance to key employees and directors of the Corporation. The Stock Plan permits the granting of any or all of the following types of awards: (a) stock options, (b) stock appreciation rights, (c) restricted stock awards, (d) performance awards and (e) stock awards and other incentive awards.

The Stock Plan is administered by the Corporation’s Board of Directors (the “Board”). Subject to the terms of the Stock Plan, the Board has the authority to determine plan participants, the types and amounts of awards to be granted and the terms, conditions and provisions of awards. Options granted pursuant to the Stock Plan may, at the discretion of the Board, be either incentive stock options or non-qualified stock options. The exercise price of incentive stock options generally may not be less than the fair market value of the common stock on the date of grant and the term of the option may not exceed 10 years. Any stock appreciation rights granted under the Stock Plan gives the holder the right to receive cash in an amount equal to the difference between the fair market value of the share of common stock on the date of exercise and the exercise price. Non-vested stock under the Stock Plan will generally consist of shares which may not be disposed of by participants until certain restrictions established by the Board lapse. The Board may require a participant to pay a stipulated purchase price for each share of restricted stock. Restricted stock rights under the Stock Plan will generally represent the right to receive shares of common stock when certain restrictions, established by the Board, lapse.

Through June 30, 2008, certain officers, directors and employees purchased common stock of the Corporation for $10 per share, consisting of 25% cash and a full recourse note for the

F-57

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

remaining 75%. The purchased stock is subject to a restricted period of four to six years, beginning on the date the participant began serving as an employee or director of the Corporation. During the restricted period, the individual may not sell, transfer, pledge, exchange or otherwise dispose of the common stock. The common stock vests ratably over the restricted period. All common stock immediately vests upon a change of control of the Corporation. If the individual’s employment or service to the Corporation is terminated prior to vesting, the individual has no further rights to the common stock and the Corporation has the right to repurchase any or all of the common stock.

During the year ended June 30, 2008, the Corporation issued a total of 2,575 shares of common stock to various employees for cash consideration and purchase notes in the aggregate principal amount of $25,750 and the Corporation repurchased 361 shares of its common stock for an aggregate purchase price of $3,614, none of which was retired during the year and all of which are held in treasury.

On October 31, 2008, the Corporation completed an offering of 50,415 units (“Subscribed Units”) to an investor at a price of $100.00 per unit for aggregate consideration of $5.0 million. Each Subscribed Unit consists of one share of common stock, par value $0.01 per share, of the Corporation and one share of Series A Preferred Stock.

During the year ended June 30, 2009, the Corporation issued a total of 10,797 common shares to various employees for cash consideration of $27,285 and purchase notes in the aggregate principal amount of $80,685. The Corporation repurchased 2,933 shares of its common stock for an aggregate purchase price of $37,928, none of which was retired during the year and all of which are held in treasury.

Notes receivable from officers, director and employees

In the aggregate, at June 30, 2008 and 2009, the Corporation had notes receivable from officers, a director and employees totaling $0.4 million and $0.6 million, respectively, including accrued interest. The maturity date of the notes is defined as the earlier of the date upon which the Corporation or any successor to the Corporation registers any class of its stock under Section 12 of the Securities Exchange Act of 1934 (the “Exchange Act”); is required to file periodic reports under Section 15(d) of the Exchange Act, the date a registration statement filed under the Securities Act of 1933 is declared effective; or July 28, 2011. The stated annual interest rate on all notes is 6.00%. Interest is compounded annually. All accrued and unpaid interest on the notes is due and payable at maturity. All such notes receivable were originally issued in conjunction with purchases of the Corporation’s common stock by the officers, employees and a director. Performance of the officers’ and director’s obligations under these notes is secured by security interests granted by each of the officers and director to the Corporation in all of the common stock purchased. Additionally, the Corporation has full recourse against the assets of the officers and director for collection of amounts due upon the occurrence of a default that was not remedied.

LLC conversion

As described in Note 1, on June 30, 2009, the Corporation and its subsidiaries reorganized to form the predecessor. Upon formation of Mid-Con Energy I, LLC each holder of Preferred Stock, Common Stock and Restricted Common Stock of Mid-Con Energy Corporation received an equal number of Class A Units, Class B units and Class C units, respectively, in Mid-Con Energy I, LLC.

F-58

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)


6.	Debt

The Corporation has a $10 million revolving credit facility with a financial institution. The borrowing base is $5 million, re-determined annually based on the Corporation’s oil and natural gas reserves. Interest is payable monthly and charged at LIBOR plus 2.75% or the financial institution’s prime rate. All of the Corporation’s oil and natural gas properties are pledged as security under the agreement. The Corporation did not have any outstanding borrowings at June 30, 2009, but had $0.2 million in outstanding borrowings and $25,000 in letters of credit as of June 30, 2008. The revolving credit facility matures at the end of each fiscal year ending June 30.


7.	Income Taxes

The Corporation and its subsidiaries file consolidated United States federal and state income tax returns. The tax returns and the amount of taxable income or loss reflected thereon are subject to examination by United States federal and state taxing authorities. An estimated tax payment of $0.6 million was made for the year ended June 30, 2009. There were no current or estimated tax payment made for the year ended June 30, 2008.

The reconciliation between the tax benefit (expense) computed by multiplying pretax income by the U.S. federal statutory rate and the reported amounts of income tax benefit (expense) for the period ended June 30 is as follows:


	2008			2009

U.S. federal statutory income tax rate		34.0	%		34.0	%
State income taxes		4.0	%		4.0	%
Percentage depletion in excess of tax basis		(14.3	)%		(39.2	)%
Non-deductible permanent differences		1.1	%		(1.2	)%
Other		2.6	%		—

		27.4	%		(2.4	)%


8.	Credit Risk

Financial instruments which potentially subject the Corporation to credit risk consisted principally of cash balances, accounts receivable and derivative financial instruments. The Corporation maintains cash and cash equivalents in bank deposit accounts which, at times, may have exceed the federally insured limits. The Corporation has not experienced any significant losses from such investments.

For the year ended June 30, 2008, purchases by Sunoco Logistics, Partners L.P., Teppco Crude Oil, LLC and High Sierra Crude Oil and Marketing, LLC accounted for 53%, 14% and 9%, respectively of the Corporation’s total sales revenues.

For the year ended June 30, 2009, purchases by Sunoco Logistics Partners L.P., ScissorTail Energy, LLC and Teppco Crude Oil, LLC accounted for 69%, 16% and 5% of the Corporation’s total sales revenues.

Management believes that the loss of any one purchaser would not have an adverse effect on the ability of the predecessor to sell its oil and gas production because management believes market conditions are such that other purchasers would be willing to buy from the predecessor

F-59

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

at market based prices. The predecessor has not experienced any significant losses due to uncollectible accounts receivable from the purchasers.


9.	Commitments and Contingencies

In the normal course of business, the Corporation enters into contracts that contain a variety of representations and warranties and provide general indemnifications. The Corporation’s maximum exposure under these arrangements is unknown as this would involve future claims that may be made against the Corporation that have not yet occurred. The Corporation does not expect to suffer any material losses in connection with these contracts.

Various federal, state and local laws and regulations covering, among other things, the release of waste materials into the environment and state and local taxes affect the Corporation’s operations and costs. Management believes the Corporation is in substantial compliance with applicable federal, state and local laws, and management expects that the ultimate resolution of any claims or legal proceedings instituted against the Corporation will not have a material effect on its financial position or results of operations.

The Corporation is a party to a non-cancelable operating lease for office space for its office in Tulsa, Oklahoma through 2012. The Corporation recognizes expense on a straight-line basis in equal amounts over the lease term. Rent expense was approximately $0.2 million for each of the years ended June 30, 2008 and 2009. Future minimum lease commitments under this lease at June 30, 2009, are approximately $0.2 million for fiscal 2010, $0.2 million for fiscal 2011 and $0.1 million for fiscal 2012.

The Corporation had an employment contract with an employee. The contract provides for an annual bonus determined upon secondary reserves identified, acquired and developed. The bonus equals $0.15 per net barrel developed for the Corporation and is paid as follows: one third upon approval of unitization, one third upon achieving payout of the project and one third upon achieving a second payout of the project. The employment contract guarantees $24,000 annually to the employee to be paid quarterly.


10.	Defined Contribution Plan

The Corporation maintains a 401(k) contribution plan (the “Plan”) for its employees. Employees must be 21 years of age or older and have worked for 90 days to be eligible to participate. All employees that were employed prior to adoption of the Plan on December 31, 2006, became an active member of the Plan as of December 31, 2006. Employees may contribute 15% of their compensation up to the annual IRS limitation. The Corporation makes contributions of 3% of an employee’s pay and employees are 100% vested at all times.

For each of the years ended June 30, 2008 and 2009, the Corporation contributed $0.1 million to the defined contribution plans.


11.	Supplemental Oil and Gas Disclosures

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

F-60

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

Costs incurred in the acquisition and development of oil and gas assets are presented below for the years ended June 30:


	2008		2009
	(in thousands)

Property acquisition costs:
Proved	$	1,758	$	1,080
Unproved		98		—
Development		5,555		11,570
Asset retirement obligations		249		36

Total costs incurred	$	7,660	$	12,686

Net Proved Oil and Gas Reserves—(Unaudited)

The Corporation’s proved oil and gas reserves as of June 30, 2007, 2008 and 2009 were prepared by the Corporation’s reservoir engineers. These reserve estimates have been prepared in compliance with the rules of the United States Securities and Exchange Commission at those dates. The Corporation emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, for the years ended June 30, are as follows:


	Year Ended June 30, 2008
	Oil			Gas
	(MBbls)			(MMcf)			MBoe

Proved developed and undeveloped reserves:
Beginning of year		4,250			228			4,288
Revisions of previous estimates		184			(27	)		179
Extensions, discoveries and other additions		997			1,650			1,272
Purchases of minerals in place		53			7			54
Production		(145	)		(86	)		(159	)

End of year		5,339			1,772			5,634

Proved developed reserves:
Beginning of year		2,108			228			2,146
End of year		2,855			976			3,018
Proved undeveloped reserves:
Beginning of year		2,142			—			2,142
End of year		2,484			796			2,616

F-61

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)


	Year Ended June 30, 2009
	Oil			Gas
	(MBbls)			(MMcf)			MBoe

Proved developed and undeveloped reserves:
Beginning of year		5,339			1,772			5,634
Revisions of previous estimates		(618	)		(517	)		(704	)
Extensions, discoveries and other additions		300			2			301
Purchases of minerals in place		—			—			—
Production		(153	)		(341	)		(210	)

End of year		4,868			916			5,021

Proved developed reserves:
Beginning of year		2,855			976			3,018
End of year		2,489			834			2,628
Proved undeveloped reserves:
Beginning of year		2,484			796			2,616
End of year		2,379			82			2,393

The tables above include changes in estimated quantities of oil and natural gas reserves shown in MBoe equivalents at a rate of six Mcf per Boe.

Standardized Measure of Discounted Future Net Cash Flow—(Unaudited)

The estimates of future cash flow and future production and development costs as of June 30, 2008 and 2009 are based on year-end sales prices for oil and natural gas. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flow from proved oil and natural gas reserves, less the tax basis of the Corporation’s oil and natural gas properties. Prices used were $140.00 and $69.89 per Bbl of oil and $13.85 and $3.84 per Mcf of natural gas for June 30, 2008 and 2009, respectively. All wellhead prices are held flat over the life of the properties for all reserve categories. The estimated future net cash flow is then discounted at a rate of 10%.

The standardized measure of discounted future net cash flow does not purport to be, nor should it be interpreted to represent, the fair market value of the proved oil and natural gas reserves of the Corporation. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The Corporation cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10%

F-62

Mid-Con Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 — (continued)

discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

The standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is as follows at June 30:


	2008			2009
	(in thousands)

Future cash inflows	$	728,296		$	320,413
Future production costs		(167,642	)		(101,045	)
Future development costs		(17,223	)		(13,673	)
Future income tax expenses		(198,854	)		(66,268	)

Future net cash flow		344,577			139,427
10% discount for estimated timing of cash flow		(155,240	)		(61,547	)

Standardized measure of discounted cash flow	$	189,337		$	77,880

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas were adjusted NYMEX prices at year end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions.

Changes in the standardized measure of discounted future net cash flow relating to proved oil and gas reserves are as follows:


	2008			2009
	(in thousands)

Standardized measure of discounted future net cash flow, beginning of year	$	77,526		$	189,337
Changes in the year resulting from:
Sales, less production costs		(8,334	)		(6,418	)
Revisions of previous quantity estimates		10,581			(16,928	)
Extensions, discoveries and improved recovery		51,014			3,264
Net change in prices and production costs		129,894			(172,916	)
Net change in income taxes		(69,207	)		72,238
Changes in estimated future development costs		(6,666	)		(2,795	)
Previously estimated development costs incurred during the period		5,241			10,795
Accretion of discount		11,700			29,802
Timing differences and other		(12,412	)		(28,499	)

Standardized measure of discounted future net cash flow, end of year	$	189,337		$	77,880

F-63

Injection Well: A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure.

MBbls: One thousand Bbls.

MBoe: One thousand Boe.

MBoe/d One thousand Boe per day.

MBtu: One thousand Btu.

Mcf: One thousand cubic feet of natural gas.

Mcf/d One thousand cubic feet of natural gas per day.

MMBoe: One million Boe.

MMBtu: One million Btu.

MMcf: One million cubic feet of natural gas.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NYMEX: New York Mercantile Exchange.

Oil: Oil, condensate and natural gas liquids.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserves: 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. 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 gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, 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, HKO, elevation and the potential exists for an associated 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. 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

B-2

twelve-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.

Proved Undeveloped Reserves: Proved oil and natural gas reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed. Reserves associated with recompletion are also referred to as “Behind Pipe.”

Reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Unit: A contiguous geographic area that was established and approved by state oil and gas commissions for the express purpose of secondary recovery.

Unitization: The process of obtaining approval from working interest owners, mineral owners and regulatory agencies to conduct secondary (e.g., water flooding) or tertiary operations.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

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.

Workover: Operations on a producing well to restore or increase production.

WTI: A crude oil produced in West Texas that is used as a benchmark for oil prices in the United States.

B-3

APPENDIX C—CAWLEY, GILLESPIE & ASSOCIATES, INC.
SUMMARY OF JUNE 30, 2011 RESERVES

August 8, 2011

Mr. Robbin W. Jones

Vice President & COO

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

2431 E. 61st St., Suite 850

Tulsa, OK 74136


	Re:	Reserve Audit Mid-Con Energy I, LLC and Mid-Con Energy II, LLC Interests Total Proved Reserves Certain Properties in Oklahoma As of June 30, 2011

Dear Mr. Jones:

At your request, Cawley, Gillespie & Associates, Inc. have examined the estimates as of June 30, 2011 set forth in the attached table as prepared by Mid-Con Energy I, LLC and Mid-Con Energy II, LLC with respect to the total proved reserves of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC. Our examination included such tests and procedures as we considered necessary under the circumstances to render the opinion set forth herein. These estimates are summarized as follows:


							Cumulative
	Net		Net				Cash Flow
	Oil		Gas		Net		Disc. @ 10%
	(Mbbls)		(MMcf)		MBOE		(M$)

Total Proved		7,733		1,053		7,907		233,147
Proved Developed Producing		3,928		1,051		4,103		117,124
Proved Developed Non-Producing		1,295		2		1,295		51,832
Proved Developed Behind Pipe		207		0		207		7,076
Proved Undeveloped		2,302		0		2,302		57,115

We are independent with respect to Mid-Con Energy I, LLC and Mid-Con Energy II, LLC as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject properties. Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties. We have not made any field examination of the subject properties.

C-1

Mid-Con Energy I, LLC and Mid-Con Energy II, LLC

Reserve Audit

August 8, 2011

Page 2

It should be understood that our audit and the development of our reserves forecasts do not constitute a complete reserve study of the oil and gas properties of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC. In the conduct of our report, we have not independently verified the accuracy and completeness of information and data furnished by Mid-Con Energy I, LLC and Mid-Con Energy II, LLC with respect to ownership interests, oil and gas production, historical costs of operation and developments, product prices, agreements relating to current and future operations and sales of production. Furthermore, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

The forecasts described herein are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered. Moreover, these estimates may increase or decrease as a result of future operations.

Please be advised that, based upon the foregoing, in our opinion the above-described estimates of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC’s total proved reserves are, in the aggregate, reasonable within the established audit tolerance guidelines of (+ or -) 10% and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers.

Our work papers and related data are available for inspection and review by authorized, interested parties. The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.

Sincerely,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

/s/ ROBERT D. RAVNAAS, P.E.

Robert D. Ravnaas, P.E.
Executive Vice President

RDR:rtp

C-2

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than underwriting discounts, a structuring fee and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NASDAQ Global Market listing fee, the amounts set forth below are estimates. The underwriters have agreed to reimburse us for a portion of our expenses.


SEC registration fee	$	16,254
FINRA filing fee	$	14,500
NASDAQ Global Market listing fee		*
Printing and engraving expenses		*
Accounting fees and expenses		*
Legal fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*


	*	To be provided by amendment.


Item 14.	Indemnification of Directors and Officers

The partnership agreement of Mid-Con Energy Partners, LP provides that the partnership will, to the fullest extent permitted by law but subject to the limitations expressly provided therein, indemnify and hold harmless its general partner, any Departing Partner (as defined therein), any person who is or was an affiliate of the general partner, including any person who is or was a member, partner, officer, director, fiduciary or trustee of the general partner, any Departing Partner, any Group Member (as defined therein) or any affiliate of the general partner, any Departing Partner or any Group Member, or any person who is or was serving at the request of the general partner, including any affiliate of the general partner or any Departing Partner or any affiliate of any Departing Partner as an officer, director, member, partner, fiduciary or trustee of another person, or any person that the general partner designates as a Partnership Indemnitee for purposes of the partnership agreement (each, a “Partnership Indemnitee”) 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 Partnership Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as a Partnership Indemnitee, provided that the Partnership 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 Partnership Indemnitee is seeking indemnification, the Partnership Indemnitee engaged in fraud, willful misconduct or gross negligence or, a breach of its obligations under the partnership agreement of Mid-Con Energy Partners, LP or a breach of its fiduciary duty in the case of a criminal matter, acted with knowledge that the Partnership Indemnitee’s conduct was unlawful. This indemnification would under certain circumstances include indemnification for liabilities under the Securities Act. To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by a Partnership Indemnitee who is indemnified pursuant to the partnership agreement 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 Partnership Indemnitee is not entitled to be

II-1

indemnified upon receipt by the partnership of any undertaking by or on behalf of the Partnership Indemnitee to repay such amount if it shall be determined that the Partnership Indemnitee is not entitled to be indemnified under the partnership agreement provided, however , there shall be no advancement of costs or fees to any Partnership Indemnitee in the event of a derivative or direct action against such Person brought by at least a Majority in Interest of the Limited Partners. Any indemnification under these provisions will be only out of the assets of the partnership. 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.

Mid-Con Energy Partners, LP is authorized to purchase (or to reimburse its general partner for the costs of) insurance against liabilities asserted against and expenses incurred by its general partner, its affiliates and such other persons as the respective general partners may determine and described in the paragraph above in connection with their activities, whether or not they would have the power to indemnify such person against such liabilities under the provisions described in the paragraphs above. The general partner has purchased insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Any underwriting agreement entered into in connection with the sale of the securities offered pursuant to this registration statement will provide for indemnification of officers and directors of our general partner, including liabilities under the Securities Act.


Item 15.	Recent Sales of Unregistered Securities.

On July 27, 2010, in connection with the formation of Mid-Con Energy Partners, LP, we issued (i) the 2.0% general partner interest in us to Mid-Con Energy GP, LLC for $20 and (ii) the 98% limited partner interest in us to S. Craig George for $980, in each case, in an offering 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) Exhibit Index


Exhibit
Number				Description

	1	.1*	—	Form of Underwriting Agreement
	3	.1	—	Certificate of Limited Partnership of Mid-Con Energy Partners, LP
	3	.2	—	Agreement of Limited Partnership of Mid-Con Energy Partners, LP
	3	.3*	—	Form of First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP (included as Appendix A to the prospectus)
	3	.4	—	Certificate of Formation of Mid-Con Energy GP, LLC
	3	.5	—	Limited Liability Company Agreement of Mid-Con Energy GP, LLC
	3	.6*	—	Form of Amended and Restated Limited Liability Company Agreement of Mid-Con Energy GP, LLC
	5	.1*	—	Opinion of GableGotwals as to the legality of the securities being registered
	8	.1*	—	Opinion of Andrews Kurth LLP relating to tax matters
	10	.1*	—	Form of Credit Agreement
	10	.2*	—	Form of Merger Agreement
	10	.3*	—	Form of Mid-Con Energy GP, LLC Long-Term Incentive Plan
	10	.4*	—	Form of Omnibus Agreement

II-2


Exhibit
Number				Description

	10	.5*	—	Form of Services Agreement
	21	.1	—	List of Subsidiaries of Mid-Con Energy Partners, LP
	23	.1	—	Consent of Grant Thornton LLP
	23	.2	—	Consent of Cawley, Gillespie & Associates, Inc.
	23	.3*	—	Consent of GableGotwals (contained in Exhibit 5.1)
	23	.4*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
	24	.1	—	Powers of Attorney (included on signature page)
	99	.1	—	Report of Cawley, Gillespie & Associates, Inc. (included as Appendix C to the prospectus) of reserves as of June 30, 2011
	99	.2		Report of Cawley, Gillespie & Associates, Inc. of reserves as of December 31, 2011


*		To be filed by amendment.


Item 17.	Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act 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 Securities 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 of the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus 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.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Mid-Con Energy GP, LLC, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Mid-Con Energy GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on August 12, 2011.

MID-CON ENERGY PARTNERS, LP

By: Mid-Con Energy GP, LLC, its general partner


	By:	/s/ CHARLES R. OLMSTEAD

Charles R. Olmstead, Chief Executive
Officer and Director

POWER OF ATTORNEY

Each person whose signature appears below appoints Charles R. Olmstead and Jeffrey R. Olmstead, and each of them, either of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933 and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates presented.


Name	Title	Date

/s/ S. CRAIG GEORGE	Executive Chairman of the Board of Directors	August 12, 2011
/s/ CHARLES R. OLMSTEAD	Chief Executive Officer and Director (Principal Executive Officer)	August 12, 2011

/s/ JEFFREY R. OLMSTEAD	Chief Financial Officer and Director (Principal Financial Officer)	August 12, 2011
/s/ DAVID A. CULBERTSON	Chief Accounting Officer (Principal Accounting Officer)	August 12, 2011
/s/ PETER A. LEIDEL	Director	August 12, 2011
/s/ CAMERON O. SMITH	Director	August 12, 2011
/s/ ROBERT W. BERRY	Director	August 12, 2011
/s/ PETER ADAMSON, III	Director	August 12, 2011

II-4

EXHIBIT INDEX


Exhibit
Number				Description

	1	.1*	—	Form of Underwriting Agreement
	3	.1	—	Certificate of Limited Partnership of Mid-Con Energy Partners, LP
	3	.2	—	Agreement of Limited Partnership of Mid-Con Energy Partners, LP
	3	.3*	—	Form of First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP (included as Appendix A to the prospectus)
	3	.4	—	Certificate of Formation of Mid-Con Energy GP, LLC
	3	.5	—	Limited Liability Company Agreement of Mid-Con Energy GP, LLC
	3	.6*	—	Form of Amended and Restated Limited Liability Company Agreement of Mid-Con Energy GP, LLC
	5	.1*	—	Opinion of GableGotwals as to the legality of the securities being registered
	8	.1*	—	Opinion of Andrews Kurth LLP relating to tax matters
	10	.1*	—	Form of Credit Agreement
	10	.2*	—	Form of Merger Agreement
	10	.3*	—	Form of Mid-Con Energy GP, LLC Long-Term Incentive Plan
	10	.4*	—	Form of Omnibus Agreement
	10	.5*	—	Form of Services Agreement
	21	.1	—	List of Subsidiaries of Mid-Con Energy Partners, LP
	23	.1	—	Consent of Grant Thornton LLP
	23	.2	—	Consent of Cawley, Gillespie & Associates, Inc.
	23	.3*	—	Consent of GableGotwals (contained in Exhibit 5.1)
	23	.4*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
	24	.1	—	Powers of Attorney (included on signature page)
	99	.1	—	Report of Cawley, Gillespie & Associates, Inc. (included as Appendix C to the prospectus) of reserves as of June 30, 2011
	99	.2		Report of Cawley, Gillespie & Associates, Inc. of reserves as of December 31, 2011


*		To be filed by amendment.


	Per
	Common
	Unit	Total

Public offering price	$	$
Underwriting discount(1)	$	$
Proceeds, before expenses	$	$


	•	Common units held by persons who our general partner determines are not eligible holders will be subject to redemption.


(1)		Excludes a structuring fee equal to % of the gross proceeds of this offering payable to RBC Capital Markets, LLC.


PROSPECTUS SUMMARY			1
Mid-Con Energy Partners, LP			1
Our Principal Business Relationships			5
Risk Factors			5
Formation Transactions and Partnership Structure			8
Ownership and Organizational Structure of Mid-Con Energy Partners, LP			9
Management of Mid-Con Energy Partners, LP			9
Principal Executive Offices and Internet Address			10
Summary of Conflicts of Interest and Fiduciary Duties			10
The Offering			12
Summary Historical and Pro Forma Financial Data			17
Non-GAAP Financial Measures			19
Summary Pro Forma and Historical Reserve and Operating Data			21
RISK FACTORS			23
Risks Related to Our Business			23
Risks Inherent in an Investment in Us			35
Tax Risks to Unitholders			45
USE OF PROCEEDS			51
CAPITALIZATION			52
DILUTION			53
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			54
General			54
Our Minimum Quarterly Distribution			57
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended June 30, 2011			59
Mid-Con Energy Partners, LP Unaudited Pro Forma Available Cash			61
Estimated Adjusted EBITDA for the Year Ending December 31, 2012			62
Mid-Con Energy Partners, LP Statement of Estimated Adjusted EBITDA			64
Assumptions and Considerations			65
Sensitivity Analysis			70
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			74
Distributions of Available Cash			74
Operating Surplus and Capital Surplus			75
Capital Expenditures			78
Subordination Period			80
Distributions of Available Cash from Operating Surplus During the Subordination Period			82
Distributions of Available Cash from Operating Surplus After the Subordination Period			82
General Partner Interest and Incentive Distribution Rights			82
Percentage Allocations of Available Cash From Operating Surplus			83
Right to Reset Incentive Distribution Levels			84
Distributions from Capital Surplus			86
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			87
Distributions of Cash Upon Liquidation			88
Adjustments to Capital Accounts			89
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA			91
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			94
Overview			94
How We Evaluate Our Operations			94
Historical Financial and Operating Data			99
Results of Operations			100
Liquidity and Capital Resources			104
Contractual Obligations			108
Quantitative and Qualitative Disclosure about Market Risk			108
Critical Accounting Policies and Estimates			109
Recently Issued Accounting Pronouncements			112
Internal Controls and Procedures			112
Inflation			113
Off-Balance Sheet Arrangements			113


BUSINESS AND PROPERTIES			114
Overview			114
Our Hedging Strategy			116
Our Business Strategies			116
Our Competitive Strengths			118
Our Principal Business Relationships			119
Oil Recovery Overview			120
Our Properties			121
Oil and Natural Gas Reserves and Production			127
Operations			133
Environmental Matters and Regulation			137
Other Regulation of the Oil and Natural Gas Industry			141
Employees			142
Offices			142
Legal Proceedings			142
MANAGEMENT			143
Management of Mid-Con Energy Partners, LP			143
Directors and Executive Officers of Mid-Con Energy GP, LLC			144
Reimbursement of Expenses of Our General Partner			146
Director Independence			147
Committees of the Board of Directors			147
Compensation of Executive Officers			148
Compensation Discussion and Analysis			149
Compensation of Directors			150
Long-Term Incentive Plan			150
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			154
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			156
Distributions and Payments to Our General Partner and Its Affiliates			156
Agreements with Affiliates in Connection with the Transactions			157
Other Transactions with Related Persons			158
Review, Approval or Ratification of Transactions with Related Persons			158
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			160
Conflicts of Interest			160
Fiduciary Duties			166
DESCRIPTION OF THE COMMON UNITS			170
The Units			170
Transfer Agent and Registrar			170
THE PARTNERSHIP AGREEMENT			172
Organization and Duration			172
Purpose			172
Cash Distributions			172
Capital Contributions			172
Limited Voting Rights			173
Applicable Law; Forum, Venue and Jurisdiction			174
Limited Liability			175
Issuance of Additional Interests			176
Amendment of the Partnership Agreement			176
Merger, Consolidation, Sale or Other Disposition of Assets			179
Dissolution			179
Liquidation and Distribution of Proceeds			180
Withdrawal or Removal of Our General Partner			180
Transfer of General Partner Units			181
Transfer of Incentive Distribution Rights			182
Transfer of Ownership Interests in Our General Partner			182
Change of Management Provisions			182
Limited Call Right			182
Meetings; Voting			183
Status as Limited Partner			184
Non-Citizen Unitholders; Redemption			184
Indemnification			184
Reimbursement of Expenses			185
Books and Reports			185
Right to Inspect Our Books and Records			185
Registration Rights			186
UNITS ELIGIBLE FOR FUTURE SALE			187
MATERIAL TAX CONSEQUENCES			188


Taxation of Mid-Con Energy Partners, LP			189
Tax Consequences of Unit Ownership			190
Tax Treatment of Operations			196
Disposition of Units			201
Uniformity of Units			203
Tax-Exempt Organizations and Other Investors			204
Administrative Matters			204
Recent Legislative Developments			207
State, Local and Other Tax Considerations			208
INVESTMENT IN MID-CON ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS			209
UNDERWRITING			211
VALIDITY OF THE COMMON UNITS			215
EXPERTS			216
WHERE YOU CAN FIND MORE INFORMATION			217
FORWARD-LOOKING STATEMENTS			218
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A—FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MID-CON ENERGY PARTNERS, LP			A-1
APPENDIX B—GLOSSARY OF TERMS			B-1
APPENDIX C—CAWLEY, GILLESPIE & ASSOCIATES, INC. SUMMARY OF JUNE 30, 2011 RESERVES			C-1
EX-3.1
EX-3.2
EX-3.4
EX-3.5
EX-21.1
EX-23.1
EX-23.2
EX-99.2


	•	We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.


	•	Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

	•	Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.


	Page

MID-CON ENERGY PARTNERS, LP
Unaudited Pro Forma Condensed Financial Statements:
Introduction		F-2
Unaudited Pro Forma Condensed Balance Sheet as of June 30, 2011		F-3
Unaudited Pro Forma Condensed Statement of Operations for the Six Months Ended June 30, 2011		F-4
Unaudited Pro Forma Condensed Statement of Operations for the Twelve Months Ended December 31, 2010		F-5
Notes to Unaudited Pro Forma Condensed Financial Statements		F-6
Historical Balance Sheet:
Report of Independent Registered Public Accounting Firm		F-9
Balance Sheet as of July 29, 2011		F-10
Note to Balance Sheet		F-11
PREDECESSOR
Unaudited Historical Combined Financial Statements as of December 31, 2010 and June 30, 2011 and for the Six Months Ended June 30, 2010 and 2011:
Unaudited Combined Balance Sheets		F-12
Unaudited Combined Statements of Operations		F-13
Unaudited Combined Statements of Members’ Equity		F-14
Unaudited Combined Statements of Cash Flows		F-15
Notes to Unaudited Combined Financial Statements		F-16
Historical Combined Financial Statements as of December 31, 2009 and 2010 and for the period from inception (July 1, 2009) to December 31, 2009 and for the year ended December 31, 2010:
Report of Independent Registered Public Accounting Firm		F-26
Combined Balance Sheets		F-27
Combined Statements of Operations		F-28
Combined Statements of Members’ Equity		F-29
Combined Statements of Cash Flows		F-30
Notes to Combined Financial Statements		F-31
Historical Consolidated Financial Statements for the years ended June 30, 2008 and 2009:
Report of Independent Registered Public Accounting Firm		F-48
Consolidated Statements of Operations		F-49
Consolidated Statements of Stockholders’ Equity		F-50
Consolidated Statements of Cash Flows		F-51
Notes to Consolidated Financial Statements		F-52


Assets:
Cash	$	1,000

Total Assets	$	1,000

Partners’ Capital:
Limited Partners’ Capital	$	980
General Partner’s Capital		20

Total Partners’ Capital	$	1,000

	1.		The name of the limited partnership is Mid-Con Energy Partners, LP

	2.		The address of the registered office of the Partnership in the State of Delaware and the name and address of the registered agent of the Partnership required to be maintained by Section 17-104 of the Act at such address are as follows:


Name and Address of Registered		Address of
Agent		Registered Office
The Corporation Trust Company Corporation Trust Center 1209 Orange Street Wilmington, DE 19801		Corporation Trust Center 1209 Orange Street Wilmington, DE 19801


General Partner: MID-CON ENERGY GP, LLC
By:	/s/ Charles R. Olmstead
	Name:	Charles R. Olmstead
	Title:	Chief Executive Officer


GENERAL PARTNER: MID-CON ENERGY GP, LLC
By:	/s/ Charles R. Olmstead
	Name:	Charles R. Olmstead
	Title:	Chief Executive Officer

LIMITED PARTNER: S. CRAIG GEORGE
By:	/s/ S. Craig George
	Name:	S. Craig George


Sincerely,
/s/ Cawley, Gillespie & Associates, Inc.
Cawley, Gillespie & Associates, Inc. Texas Registered Engineering Firm F-693


		Re:		Reserve Audit Mid-Con Energy I, LLC and Mid-Con Energy II, LLC Interests Total Proved Reserves Certain Properties in Oklahoma As of December 31, 2010


							Cumulative
	Net		Net				Cash Flow
	Oil		Gas		Net		Disc. @ 10%
	(Mbbls)		(MMcf)		MBOE		(M$)
Total Proved		6,938		1,070		7,116		183,204
Proved Developed Producing		2,559		1,083		2,738		66,150
Proved Developed Non-Producing		870		-1		870		31,578
Proved Developed Behind Pipe		102		0		102		2,601
Proved Undeveloped		3,407		-12		3,406		82,876


	Sincerely, CAWLEY, GILLESPIE & ASSOCIATES, INC.
	/s/ Robert D. Ravnaas, P.E.
	Robert D. Ravnaas, P.E.
	Executive Vice President