Mid-Con Energy Partners, LP - FORM S-1

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

As filed with the Securities and Exchange Commission on September 26, 2012

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

1311

45-2842469

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification Number)

2501 North Harwood Street, Suite 2410

Dallas, Texas 75201

(972) 479-5980

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

Nathan P. Pekar

Mid-Con Energy GP, LLC

2501 North Harwood, Suite 2410

Dallas, Texas 75201

(972) 479-5980

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

Copies to:

Richard M. Carson

Jordan B. Edwards

Gable & Gotwals, A Professional Corporation

1100 ONEOK Plaza

100 W. Fifth Street

Tulsa, Oklahoma 74103

(918) 595-4800

Brett E. Braden

Latham & Watkins LLP

811 Main Street, Suite 3700

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. ¨

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. ¨

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. ¨

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):

CALCULATION OF REGISTRATION FEE



Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee
Common units representing limited partner interests	$106,214,000	$12,172.13

(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.

Subject to Completion, dated September 26, 2012

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where such offer or sale is not permitted.

PROSPECTUS

LOGO

Mid-Con Energy Partners, LP

4,000,000 Common Units

Representing Limited Partner Interests

We are offering 1,000,000 common units and Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P. are offering an aggregate of 3,000,000 common units in this offering.

Our common units are traded on the NASDAQ Global Market under the symbol “MCEP.” On September 25, 2012, the last reported sales price of our common units on the NASDAQ Global Market was $22.84 per common unit.

We are an “emerging growth company” as defined in Section 101 of the Jumpstart Our Business Startups Act, or JOBS Act.

Investing in our common units involves risks. See “Risk Factors” beginning on page 23.

These risks include the following:

•

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

•

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.

•

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.

•

Our general partner, who controls us, has conflicts of interest with, and owes limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

•

Neither we nor our general partner have any employees, and we rely solely on an affiliate of our general partner to manage and operate our business. The individuals who manage us also provide substantially similar services to affiliates of our general partner, and thus are not solely focused on our business.

•

Common 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.

•

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

•

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.

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

PRICE $ PER COMMON UNIT


	Per Common Unit	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to Mid-Con Energy Partners, LP	$	$
Proceeds, before expenses, to Selling Unitholders	$	$

The Selling Unitholders have granted the underwriters a 30-day option to purchase up to an additional 600,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 4,000,000 common units in this offering.

The underwriters expect to deliver the common units on or about , 2012.


RBC CAPITAL MARKETS		RAYMOND JAMES		UBS INVESTMENT BANK		WELLS FARGO SECURITIES


BAIRD		OPPENHEIMER & CO.		STEPHENS INC.

September 26, 2012

LOGO

As of December 31, 2011, we had total estimated proved reserves of 10.0 MMBoe, 99% of which were oil and 69% of which were proved developed, both on a Boe basis. As of December 31, 2011, Mid-Con Energy Operating operated 99% of our reserves and 96% of such reserves were being operated under waterflood, both on a Boe basis.

As of June 30, 2012, we had 320 gross producing wells (224 net wells), 149 gross injection wells (97 net wells), and 81 gross wells (67 net wells) shut-in or waiting on completion.

TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
MID-CON ENERGY PARTNERS, LP			1
OUR PRINCIPAL BUSINESS RELATIONSHIPS			5
RISK FACTORS			6
OWNERSHIP AND ORGANIZATIONAL STRUCTURE OF MID-CON ENERGY PARTNERS, LP			8
MANAGEMENT OF MID-CON ENERGY PARTNERS , LP			9
PRINCIPAL EXECUTIVE OFFICES AND INTERNET ADDRESS			9
SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			10
THE OFFERING			12
SUMMARY HISTORICAL FINANCIAL DATA			15
NON-GAAP FINANCIAL MEASURES			18
SUMMARY HISTORICAL RESERVE AND OPERATING DATA			20
RISK FACTORS			23
RISKS RELATED TO OUR BUSINESS			23
RISKS INHERENT IN AN INVESTMENT IN US			33
TAX RISKS TO UNITHOLDERS			41
USE OF PROCEEDS			45
CAPITALIZATION			46
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS			47
SELECTED HISTORICAL FINANCIAL DATA			48
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			50
OVERVIEW			50
HOW WE EVALUATE OUR OPERATIONS			50
HISTORICAL FINANCIAL AND OPERATING DATA			55
RESULTS OF OPERATIONS			56
LIQUIDITY AND CAPITAL RESOURCES			61
CONTRACTUAL OBLIGATIONS			66
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK			66
CRITICAL ACCOUNTING POLICIES AND ESTIMATES			68
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS			70
INTERNAL CONTROLS AND PROCEDURES			70


INFLATION			70
OFF-BALANCE SHEET ARRANGEMENTS			70
BUSINESS AND PROPERTIES			71
OVERVIEW			71
OUR HEDGING STRATEGY			72
OUR BUSINESS STRATEGIES			73
OUR COMPETITIVE STRENGTHS			74
OUR PRINCIPAL BUSINESS RELATIONSHIPS			76
OIL RECOVERY OVERVIEW			77
OUR PROPERTIES			78
OIL AND NATURAL GAS RESERVES AND PRODUCTION			83
OPERATIONS			89
ENVIRONMENTAL MATTERS AND REGULATION			94
OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY			99
EMPLOYEES			101
OFFICES			101
LEGAL PROCEEDINGS			101
MANAGEMENT			102
MANAGEMENT OF MID-CON ENERGY PARTNERS , LP			102
DIRECTORS AND EXECUTIVE OFFICERS OF MID -CON ENERGY GP, LLC			102
REIMBURSEMENT OF EXPENSES OF OUR GENERAL PARTNER			105
DIRECTOR INDEPENDENCE			106
COMMITTEES OF THE BOARD OF DIRECTORS			106
COMPENSATION DISCUSSION AND ANALYSIS			107
LONG-TERM INCENTIVE PROGRAM			115
COMPENSATION OF DIRECTORS			117
SELLING UNITHOLDERS			119
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			120
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			122
DISTRIBUTIONS AND PAYMENTS TO OUR GENERAL PARTNER AND ITS AFFILIATES			122
AGREEMENTS WITH AFFILIATES			123
OTHER TRANSACTIONS WITH RELATED PERSONS			123


REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS			123
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			125
CONFLICTS OF INTEREST			125
FIDUCIARY DUTIES			131
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			134
DISTRIBUTIONS OF AVAILABLE CASH			134
DISTRIBUTIONS OF CASH UPON LIQUIDATION			134
ADJUSTMENTS TO CAPITAL ACCOUNTS			135
DESCRIPTION OF THE COMMON UNITS			136
THE UNITS			136
TRANSFER AGENT AND REGISTRAR			136
THE PARTNERSHIP AGREEMENT			138
ORGANIZATION AND DURATION			138
PURPOSE			138
CASH DISTRIBUTIONS			138
CAPITAL CONTRIBUTIONS			138
LIMITED VOTING RIGHTS			139
APPLICABLE LAW; FORUM, VENUE AND JURISDICTION			140
LIMITED LIABILITY			140
ISSUANCE OF ADDITIONAL INTERESTS			141
AMENDMENT OF THE PARTNERSHIP AGREEMENT			142
MERGER, CONSOLIDATION, SALE OR OTHER DISPOSITION OF ASSETS			144
DISSOLUTION			145
LIQUIDATION AND DISTRIBUTION OF PROCEEDS			146
WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER			146
TRANSFER OF GENERAL PARTNER INTEREST			147
TRANSFER OF OWNERSHIP INTERESTS IN OUR GENERAL PARTNER			147


CHANGE OF MANAGEMENT PROVISIONS			148
LIMITED CALL RIGHT			148
MEETINGS; VOTING			148
STATUS AS LIMITED PARTNER			149
NON-CITIZEN UNITHOLDERS; REDEMPTION			149
INDEMNIFICATION			150
REIMBURSEMENT OF EXPENSES			150
BOOKS AND REPORTS			150
RIGHT TO INSPECT OUR BOOKS AND RECORDS			151
REGISTRATION RIGHTS			151
UNITS ELIGIBLE FOR FUTURE SALE			152
MATERIAL TAX CONSEQUENCES			153
TAXATION OF MID-CON ENERGY PARTNERS , LP			154
TAX CONSEQUENCES OF UNIT OWNERSHIP			155
TAX TREATMENT OF OPERATIONS			161
DISPOSITION OF UNITS			166
UNIFORMITY OF UNITS			168
TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS			169
ADMINISTRATIVE MATTERS			170
RECENT LEGISLATIVE DEVELOPMENTS			172
STATE, LOCAL AND OTHER TAX CONSIDERATIONS			173
INVESTMENT IN MID-CON ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS			174
UNDERWRITING			176
VALIDITY OF THE COMMON UNITS			180
EXPERTS			180
WHERE YOU CAN FIND MORE INFORMATION			180
FORWARD-LOOKING STATEMENTS			181
INDEX TO FINANCIAL STATEMENTS
APPENDIX A — GLOSSARY OF TERMS			A-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters and Selling Unitholders 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 and Selling Unitholders are not, making an offer to sell these securities in any jurisdiction where such 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.

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.

iii

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 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 from the Selling Unitholders, unless otherwise indicated. As used in this prospectus, unless we indicate otherwise:

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

“initial public offering” refers to our December 2011 initial public offering of 5,400,000 of our common units and subsequent over-allotment offering of 810,000 of our common units;

“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 Yorktown;

“Mid-Con Energy Partners,” the “partnership,” “we,” “our,” “us” or like terms when referring to periods prior to our initial public offering generally refer to our predecessor, which was merged with and into Mid-Con Energy Properties, LLC, our wholly owned subsidiary, in connection with our initial public offering. When used in reference to periods after our initial public offering 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 entity owned by Yorktown and the Founders;

“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;

“Selling Unitholders” refers to Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P.; and

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

We include a glossary of some of the oil and natural gas terms used in this prospectus in Appendix A.

Mid-Con Energy Partners, LP

Overview

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 generally intend to hedge a significant portion of our production volumes through various commodity derivative contracts.

As of December 31, 2011, our total estimated proved reserves were 10.0 MMBoe, of which approximately 99% were oil and 69% were proved developed, both on a Boe basis. As of December 31, 2011, Mid-Con Energy Operating operated 99% of our properties and 96% of our properties were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended June 30, 2012 was approximately 1,844 Boe per day and based on our December 31, 2011 audited reserves, as adjusted for average net production for the six months ended June 30, 2012, our total estimated proved reserves had a reserve-to-production ratio of approximately 15 years. As of December 31, 2011, our management team developed approximately 59% 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 December 31, 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 December 31, 2011 audited reserve report, the average estimated decline rate for our proved developed producing reserves is approximately 8.0% for 2012 and, on a compounded average decline basis, approximately 11% for the subsequent five years and approximately 10% thereafter.

The following table summarizes information by core area regarding our estimated oil and natural gas reserves as of December 31, 2011 and our average net production for the month ended June 30, 2012.


	Estimated Net Proved Reserves as of December 31, 2011											Average Net Production for the Month Ended June 30, 2012				Reserve-to-		Gross Active Wells as of June 30, 2012				Shut-in/ Waiting on Completion
																Reserve-to-		Oil and
	(MBoe)		% Operated			% Oil			% Proved Developed			Boe/d Gross		Boe/d Net		Production Ratio(1)		Natural Gas Wells		Injection Wells
Southern Oklahoma		5,528		100	%		100	%		68	%		2,600		1,128		13		79		53		12
Northeastern Oklahoma		3,179		100	%		99	%		69	%		742		447		19		201		76		54
Hugoton Basin		1,060		100	%		99	%		69	%		340		219		13		29		15		13
Other		282		77	%		77	%		100	%		140		50		15		11		5		2

Total		10,049		99	%		99	%		69	%		3,822		1,844		15		320		149		81

(1)

The reserve-to-production ratio is calculated by subtracting net production for the six months ended June 30, 2012 from estimated net proved reserves as of December 31, 2011 and dividing the result by average net production for the month ended June 30, 2012.

The following chart summarizes our total average net Boe production volumes on a monthly basis, and illustrates the 47% increase in our production volumes over the twelve months ended June 30, 2012. We achieved this production increase primarily through ongoing waterflood response from existing development activities and from workovers and acquisitions.

LOGO

Our Hedging Strategy

Our hedging strategy is to enter into various commodity derivative contracts intended to achieve more predictable cash flows and to reduce exposure to fluctuations in the price of oil. Our hedging program’s objective is to protect our ability to make current distributions, and to allow us to be better positioned to increase our quarterly distribution over time, while retaining some ability to participate in upward movements in oil prices. We use a phased approach, looking approximately 36 months forward while targeting a higher hedged percentage in the near 12 months of the period. As of September 25, 2012, for the three months ending December 31, 2012 and the years ending December 31, 2013 and 2014, we have commodity derivative contracts covering approximately 69.9%, 69.6% and 57.0%, respectively, of our fourth quarter 2012 and calendar years 2013 and 2014 average daily oil production (as estimated from the projection of our oil production in our audited proved reserves as of December 31, 2011). All of our derivative contracts for 2012, 2013 and 2014 are either swaps with fixed settlements or collars. The weighted average minimum prices on all of our derivative contracts for 2012, 2013 and 2014 are $101.59, $99.66 and $94.30, respectively. A “collar” is a combination of a put option we purchase and a call option

we sell. The put option portion of a collar is also referred to as a “floor.” A floor establishes a minimum average sale price for future oil production.

In addition to our primary hedging strategy as described above, we also 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 manage our oil and natural gas properties for the purpose of generating stable cash flows, which we expect will provide stability and, over time, growth of distributions to our unitholders. In addition to our hedging strategy described above, 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 proved reserves which are 99% oil, that have and 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;

Mid-Con Energy Operating operates 99% of our properties, which allows them to control our operating costs and capital expenditures;

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 will 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 identifying 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 investment firm founded in 1991 and focused on investments in the energy sector. Yorktown made several equity investments in our predecessor. Prior to this offering, Yorktown owned an approximate 48.5% limited partner interest in us, making it our largest unitholder. Immediately following this offering, Yorktown will own an approximate 30.1% limited partner interest in us (or an approximate 26.9% limited partner interest in us if the underwriters exercise their option to purchase additional common units in full), and will continue to be our largest unitholder. Yorktown Energy Partners IX, L.P. will continue to own a 50% interest in our affiliate Mid-Con Energy Operating. Also, Peter A. Leidel, a principal of Yorktown, serves 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, including the Mid-Con Affiliates, that are engaged in the oil and natural gas industry and, as a result, Yorktown may present acquisition opportunities to other Yorktown portfolio companies, including the Mid-Con Affiliates, 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 any quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.

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.

Our business depends in part on transportation, pipelines and refining facilities owned by others. Any limitation in the availability of those facilities, or increase in their costs, could interfere with our ability to market our production and adversely affect our revenues.

Risks Inherent in an Investment in Us

Our general partner controls us, and following this offering, the Founders and Yorktown will own a 36.0% limited partner interest in us, or a 32.8% limited partner interest in us if the underwriters exercise their option to purchase additional common units in full. They 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.

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 manage us, also provides substantially similar services to the Mid-Con Affiliates, and thus is not solely focused on our business.

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.

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.

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.

Tax Risks to Unitholders

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

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 assumes that the underwriters do not exercise their option to purchase additional common units from the Selling Unitholders.


Common units held by the public			53.4%
Common units held by the Founders			5.8%
Common units held by Yorktown			29.5%
Common units held by our executive officers, employees and other individuals and entities, other than the Founders and Yorktown who held membership interests in our predecessor			9.4%
General partner units			1.9%

Total			100.0%

LOGO

(1)

The Founders are S. Craig George, Charles R. Olmstead and Jeffrey R. Olmstead.

(2)

Yorktown Energy Partners IX, L.P. owns a 50% interest in Mid-Con Energy Operating. Yorktown IX Company LP is the sole general partner of Yorktown Energy Partners IX, L.P. Yorktown Associates LLC is the sole general partner of Yorktown IX Company LP. Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., and Yorktown Energy Partners VIII, L.P. own common units in us. For more information on the entities that control Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., and Yorktown Energy Partners VIII, L.P., please see “Security Ownership of Certain Beneficial Owners and Management.”

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 are not 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.”

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, and Jeffrey R. Olmstead, the President and Chief Financial Officer and a director of our general partner, each own one-third of the member interests in our general partner. As the holders of all of the member interests of our general partner, the Founders control our general partner, are entitled to appoint its entire board of directors and receive all of the distributions our general partner receives in respect of its approximate 2.0% general partner interest in us. Please see “Security Ownership of Certain Beneficial Owners and Management.”

Neither we, our general partner, nor our subsidiary have any employees. We and our general partner are parties to a services agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides management, administrative and operational 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 have one subsidiary, Mid-Con Energy Properties, that holds title to our properties.

Principal Executive Offices and Internet Address

Our headquarters are located at 2501 North Harwood Street, Suite 2410, Dallas, Texas 75201. Our principal operating office is located at 2431 East 61st Street, Suite 850, Tulsa, Oklahoma 74136, and our telephone number is (972) 479-5980. Our website address is www.midconenergypartners.com. We 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 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. All of the executive officers of our general partner are also officers and/or directors of the Mid-Con Affiliates and have economic interests in the Mid-Con Affiliates. In addition, Peter A. Leidel, a principal of Yorktown, serves 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.”

Generally, our partnership agreement can be amended in a manner that materially adversely affects our limited partners only 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). Following this offering, our general partner will continue to be owned by the Founders, and the Founders and Yorktown collectively will own and control the voting of an aggregate of approximately 36.0% of our outstanding common units, or approximately 32.8% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full. 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.

Implication of Being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements for up to five years that are otherwise applicable generally to public companies. These provisions include:

a requirement to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis;

exemption from the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

reduced disclosure about executive compensation arrangements.

We will cease to be an emerging growth company if we have more than $1.0 billion in annual revenues, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

We have elected to take advantage of the applicable JOBS Act provisions, except for the following:

we have elected to present three years of audited financial statements and three years of related Management’s Discussion and Analysis rather than only two years;

we have elected to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable);

we have elected to comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

we have elected to make full disclosure about executive compensation arrangements.

Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

The Offering

Common units offered by us

1,000,000 common units. As described below, if the underwriters exercise their option to purchase additional common units, such units will be offered exclusively by the Selling Unitholders on a pro rata basis.

Common units offered by the Selling Unitholders

3,000,000 common units, or 3,600,000 common units if the underwriters exercise in full their option to purchase additional common units, which in each case will be offered by the Selling Unitholders on a pro rata basis, in proportion to their interests in us.

Immediately before this offering, Yorktown owned 8,691,468 common units, representing an approximate 48.5% limited partner interest in us. Following this offering, Yorktown will own 5,691,468 common units, or 5,091,468 common units if the underwriters exercise in full their option to purchase additional common units, representing an approximate 30.1% and 26.9% limited partner interest in us, respectively.

Units outstanding after this offering

18,939,549 common units.

Use of proceeds

We intend to use the net proceeds of approximately $ million from this offering, after deducting underwriting discounts and estimated expenses, to repay $ million of indebtedness outstanding under our credit facility.

We will not receive any proceeds from the sale of common units by the Selling Unitholders, including any proceeds from the sale of common units by the Selling Unitholders if the underwriters exercise in whole or in part their option to purchase additional common units.

Affiliates of certain of the underwriters are lenders under our credit facility and accordingly, will receive a substantial portion of the proceeds from this offering. Please read “Underwriting.”

Cash distributions

We paid a quarterly distribution of $0.475 per unit for the second quarter of 2012 on all common and general partner units ($1.90 per unit on an annualized basis) on August 14, 2012 to unitholders of record as of August 7, 2012. Distributions on our units are generally paid approximately 45 days following the end of a fiscal quarter to the extent we have sufficient cash from operations, after the establishment of cash reserves and the payment of fees and expenses.

There is no guarantee that unitholders will receive a quarterly distribution from us. We do not have a legal obligation to pay

distributions at our current quarterly distribution rate or at any other rate except as provided in our partnership agreement.

Assuming our general partner maintains its approximate 2.0% general partner interest in us, our partnership agreement requires that we distribute approximately 98.0% of our available cash each quarter to the holders of our common units, pro rata, and approximately 2.0% to our general partner.

Unlike many publicly traded limited partnerships, our general partner is not entitled to any incentive distributions, and we do not have any subordinated units.

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 manages us and operates our business. Unlike stockholders of a corporation, our unitholders have only limited voting rights on matters affecting our business. Our unitholders 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 66²/₃% of the outstanding units, including any units owned by our general partner and its affiliates. Following this offering, the Founders and Yorktown will own an aggregate of approximately 36.0% of our common units (or approximately 32.8% of our common units if the underwriters exercise their option to purchase additional common units in full) 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. Following this offering, the Founders will own an aggregate of approximately 5.9% of our common 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 December 31, 2014, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 45% 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

Our common units are listed on the NASDAQ Global Market under the symbol “MCEP.”

Summary Historical Financial Data

The following table shows summary financial data of us and our predecessor for the periods and as of the dates indicated. The summary financial data as of and for the year ended June 30, 2009 are derived from the audited consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary financial data as of and for the years ended December 31, 2010 and 2011 and the six months ended December 31, 2009 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary financial data as of and for the six months ended June 30, 2011 and 2012 are derived from our unaudited consolidated financial statements included elsewhere in this prospectus.

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the audited historical consolidated financial statements of Mid-Con Energy Partners, LP and our predecessor and the unaudited consolidated financial statements of Mid-Con Energy Partners, LP and the notes thereto included elsewhere in this prospectus. Among other things, those historical consolidated financial statements and unaudited consolidated 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 Corporation (consolidated)			Mid-Con Energy Partners, LP
	Year Ended June 30,			Six Months Ended December 31,			Year Ended December 31,						Six Months Ended June 30,
	2009			2009			2010			2011			2011			2012
													(unaudited)			(unaudited)
	(in thousands)
Statement of Operations Data:
Revenues:
Oil sales	$	10,246		$	5,729		$	16,853		$	36,813		$	15,609		$	28,998
Natural gas sales		2,172			743			1,418			1,218			658			353
Realized gain (loss) on derivatives, net		(669	)		(350	)		(90	)		(2,157	)		(715	)		769
Unrealized gain (loss) on derivatives, net		1,679			(147	)		(707	)		3,437			1,046			9,741

Total revenues		13,428			5,975			17,474			39,311			16,598			39,861

Operating costs and expenses:
Lease operating expenses		5,369			2,431			6,237			8,491			3,550			4,725
Oil and gas production taxes		631			269			822			1,869			656			713
Dry holes and abandonments of unproved properties		—			—			1,418			813			772			—
Geological and geophysical		507			—			394			172			—			—
Depreciation, depletion and amortization		2,293			2,552			5,851			7,160			2,418			4,709
Accretion of discount on asset retirement obligations		78			58			127			78			32			57
General and administrative		1,767			704			982			1,924			534			4,869
Impairment of proved oil and gas properties		—			9,208			1,886			—			—			—

Total operating costs and expenses		10,645			15,222			17,717			20,507			7,962			15,073

Income (loss) from operations		2,783			(9,247	)		(243	)		18,804			8,636			24,788

Other income (expenses):
Interest income and other		118			35			218			216			62			5
Interest expense		(93	)		(2	)		(98	)		(578	)		(237	)		(703	)
Gain on sale of assets		1			—			354			1,621			1,209			—
Equity-based compensation		—			—			—			(1,671	)		—			—
Other revenue and expenses, net		298			118			847			576			576			—
Tax expense — current		(625	)		—			—			—			—			—
Tax (expense) benefit — deferred		502			—			—			—			—			—

Net income (loss)	$	2,984		$	(9,096	)	$	1,078		$	18,968		$	10,246		$	24,090

Net income per limited partner unit (basic and diluted)				$	(0.51	)	$	0.06		$	1.05		$	0.57		$	1.33

Weighted average number of limited partner units outstanding (basic and diluted)					17,640			17,640			17,640			17,640			17,790

Other Financial Data:
Adjusted EBITDA	$	3,773		$	2,836		$	10,593		$	23,994		$	11,388		$	22,503
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	10,935		$	965		$	11,798		$	24,113		$	5,192		$	24,384
Investing activities		(12,448	)		(5,018	)		(22,726	)		(42,045	)		(13,351	)		(23,992	)
Financing activities		4,841			(1,164	)		10,387			17,938			8,377			3,344


	Mid-Con Energy Partners, LP
	As of December 31,							As of June 30,
	2009		2010			2011		2011		2012
								(unaudited)		(unaudited)
			(in thousands)
Balance Sheet Data:
Working capital(1)	$	2,420	$	(1,256	)	$	2,361	$	4,383	$	11,879
Total assets		40,496		56,867			96,611		72,390		125,148
Total debt		337		5,513			45,000		13,310		58,000
Total Equity		36,779		43,072			43,349		56,098		60,473

(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;

equity-based compensation; 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

our ability to incur and service debt and fund capital expenditures.

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 Corporation (consolidated)			Mid-Con Energy Partners, LP
	Year Ended June 30,			Six Months Ended December 31,			Year Ended December 31,						Six Months Ended June 30,
	2009			2009			2010			2011			2011			2012
													(unaudited)			(unaudited)
	(in thousands)
Net income (loss)	$	2,984		$	(9,096	)	$	1,078		$	18,968		$	10,246		$	24,090
Tax expense (benefit) — deferred		(502	)		—			—			—			—			—
Tax expense — current		625			—			—			—			—			—
Interest expense		93			2			98			578			237			703
Depreciation, depletion and amortization		2,293			2,552			5,851			7,160			2,418			4,709
Accretion of discount on asset retirement obligations		78			58			127			78			32			57
Unrealized (gain) loss on derivatives, net		(1,679	)		147			707			(3,437	)		(1,046	)		(9,741	)
Impairment of proved oil and gas properties		—			9,208			1,886			—			—			—
Dry holes and abandonments of unproved properties		—			—			1,418			813			772			—
Gain on sale of assets		(1	)		—			(354	)		(1,621	)		(1,209	)		—
Equity-based compensation		—			—			—			1,671			—			2,690
Interest income		(118	)		(35	)		(218	)		(216	)		(62	)		(5	)

Adjusted EBITDA	$	3,773		$	2,836		$	10,593		$	23,994		$	11,388		$	22,503

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities


	Mid-Con Energy Corporation (consolidated)			Mid-Con Energy Partners, LP
	Year Ended June 30,			Six Months Ended December 31,			Year Ended December 31,						Six Months Ended June 30,
	2009			2009			2010			2011			2011			2012
													(unaudited)			(unaudited)
	(in thousands)
Net cash provided by operating activities	$	10,935		$	965		$	11,798		$	24,113		$	5,192		$	24,384
Amortization of debt placement fees		—			—			—			—			—			(54	)
Change in working capital		(7,762	)		1,904			(1,085	)		(481	)		6,021			(2,525	)
Tax expense — current		625			—			—			—			—			—
Interest expense		93			2			98			578			237			703
Interest income		(118	)		(35	)		(218	)		(216	)		(62	)		(5	)

Adjusted EBITDA	$	3,773		$	2,836		$	10,593		$	23,994		$	11,388		$	22,503

Summary Historical Reserve and Operating Data

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves that we own and the standardized measure amounts associated with those estimated proved reserves as of December 31, 2010 and as of December 31, 2011, both based on reserve reports prepared by our internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc., our independent reserve engineers.

These reserve estimates were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. From December 31, 2010 to December 31, 2011 our proved reserves increased by approximately 2.8 MMBoe, or 39%. Total proved reserves increased by approximately 0.9 MMBoe from acquisitions in the Hugoton Basin and Northeastern Oklahoma core areas; 0.8 MMBoe from waterflood expansion in the Northeastern Oklahoma core area; 0.7 MMBoe from infill drilling in the Southern Oklahoma core area; 0.7 MMBoe from drilling and workovers in the Northeastern Oklahoma core area and (0.3) MMBoe in net performance revisions for all of our properties. We spent a total of $19.3 million and $30.0 million in capital expenditures for the year ended December 31, 2010 and the year ended December 31, 2011, respectively, which contributed to the increase in our December 31, 2011 proved reserves.

From December 31, 2010 to December 31, 2011 our proved developed reserves increased by approximately 3.1 MMBoe, or 82%. Proved developed reserves increased in our Southern Oklahoma core area by 0.9 MMBoe from development drilling and 0.7 MMBoe in performance revisions; in the Hugoton Basin core area by 0.7 MMBoe from the acquisition of the War Party I and II Units; in our Northeastern Oklahoma core area by 0.2 MMBoe from acquisitions, 0.7 MMBoe from infill drilling and workovers and (0.1) MMBoe in net performance revisions for the Hugoton Basin and Northeastern Oklahoma core areas and Other Properties.

During the year ended December 31, 2011, we spent approximately $21.9 million in our Southern Oklahoma core area resulting in production increases and reclassifications of 0.9 MMBoe from proved undeveloped reserves to proved developed reserves, which contributed to the 1.6 MMBoe increase in proved developed reserves in our Southern Oklahoma core area discussed in the prior paragraph. Additionally, we spent approximately $13.2 million during the year ended December 31, 2011 to acquire new leases in the Hugoton Basin and Northeastern Oklahoma. We spent another $2.4 million on workover activities and $3.4 million on drilling during the year ended December 31, 2011 in Northeastern Oklahoma.

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 audits dated December 31, 2010 and December 31, 2011 in evaluating the material presented below.


	As of December 31, 2010			As of December 31, 2011
Reserve Data:
Estimated proved reserves:
Oil (MBbl)		7,007			9,936
Natural Gas (MMcf)		1,346			676

Total (MBoe)		7,231			10,049

Proved developed (MBoe)		3,825			6,948
Oil (MBbl)		3,601			6,835
Natural Gas (MMcf)		1,346			676
Proved undeveloped (MBoe)		3,406			3,101
Oil (MBbl)		3,406			3,101
Natural Gas (MMcf)		—			—
Proved developed reserves as a percentage of total proved reserves		52.9	%		69.1	%
Standardized Measure (in millions)(1)	$	183.7		$	328.2
Oil and Natural Gas Prices(2):
Oil — NYMEX — WTI per Bbl	$	79.43		$	96.19
Natural gas — NYMEX — Henry Hub per MMBtu	$	4.37		$	4.11

(1)

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.”

(2)

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 $96.19 per Bbl for oil and $4.11 per MMBtu for natural gas at December 31, 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 $73.92

per Bbl and $7.42 per Mcf, respectively. For the year ended December 31, 2011, the relevant average realized prices for oil and natural gas were $90.45 per Bbl and $7.43 per Mcf, respectively. Realized natural gas sales price per Mcf includes the sale of natural gas liquids for both the year ended December 31, 2010 and the year ended December 31, 2011.


	Year Ended December 31, 2011		Six Months Ended June 30, 2012
Production and operating data:
Net production volumes:
Oil (MBbls)		407		304
Natural gas (MMcf)		164		60
Total (MBoe)		434		314
Average net production (Boe/d)		1,191		1,725
Average sales price:(1)
Oil (per Bbl)	$	90.45	$	95.39
Natural gas (per Mcf)(2)	$	7.43	$	5.88
Average price per Boe	$	87.63	$	93.47
Average unit costs per Boe:
Oil and natural gas production expenses	$	19.56	$	15.05
Production taxes	$	4.31	$	2.27
General and administrative and other(3)	$	4.43	$	15.51
Depreciation, depletion and amortization	$	15.66	$	15.00

(1)

Prices do not include the effects of derivative cash settlements.

(2)

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

(3)

General and administrative expenses include non-cash, equity-based compensation for the six months ended June 30, 2012. We had no non-cash, equity-based compensation expense for the year ended December 31, 2011.

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation. 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 any 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 any distributions to our unitholders. 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 expense, 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 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.

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, 2011, the NYMEX — WTI oil price ranged from a high of $145.29 per Bbl to a low of $33.87 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 generally intend to hedge a significant portion of our near-term estimated oil production. 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.

Our credit facility may hinder our ability to effectively execute our hedging strategy. To the extent our 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 our credit facility does not currently 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 our derivative contracts 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.

We may be unable to sustain our current quarterly distribution rate of $0.475 per unit 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 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 not be able 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;

costs or delays imposed by or resulting from compliance with regulatory requirements;

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.

Hydraulic fracturing has been a part of the completion process for the majority of the wells on our producing properties, and most of our properties are dependent on our ability to hydraulically fracture the producing formations. We engage third-party contractors to provide hydraulic fracturing services and generally enter into service orders on a job-by-job basis. Some such service orders limit the liability of these contractors. Hydraulic fracturing operations can result in surface spillage or, in rare cases, the underground migration of fracturing fluids. Any such spillage or migration could result in litigation, government fines and penalties or remediation or restoration obligations. Our current insurance policies provide some coverage for losses arising out of our hydraulic fracturing operations. However, these policies may not cover fines, penalties or costs and expenses related to government-mandated clean-up activities, and total losses related to a spill or migration could exceed our per occurrence or aggregate policy limits. Any losses due to hydraulic fracturing that are not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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, 2011 reserve report had been $10.00 less per barrel for oil, the standardized measure of our estimated proved reserves, without asset retirement obligations, as of that date would have decreased by $48.0 million, from $328.2 million to $280.9 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 the Financial Accounting Standards Board 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.

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

the occurrence of other significant 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 a small number of customers for our production sales, and we may experience a temporary decline in revenues and production if we lose any of those customers.

Sales to a subsidiary of Sunoco Logistics Partners, L.P., or Sunoco Logistics, accounted for approximately 86% of our total sales revenues for the year ended December 31, 2011. In 2012, we entered into crude oil purchase agreements with Enterprise Crude Oil, Inc., or Enterprise, Vitol, Inc., or Vitol, and Coffeyville Resources Refining and Marketing, LLC, or Coffeyville Resources. For the six months ended June 30, 2012, sales to Enterprise, Sunoco Logistics and Vitol accounted for approximately 54%, 37% and 2%, respectively, of our total sales. We do not currently sell any production to Sunoco Logistics. After June 30, 2012, we expect that Vitol and Coffeyville Resources will each account for significantly higher percentages of our total sales. Our production is and will continue to be marketed by our affiliate, Mid-Con Energy Operating, under these crude oil purchase contracts. To the extent that any of our current purchasers reduce the volumes 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 Enterprise, Vitol, Coffeyville Resources 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. Mid-Con Energy Operating 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.

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 distributions at our current quarterly distribution rate without borrowing under our credit facility. If we use borrowings under our 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.

Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

Our credit facility restricts, among other things, our ability to incur debt and pay distributions under certain circumstances, and requires us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within specific time periods, a significant portion of our indebtedness may become immediately due and payable, we will be prohibited from making distributions to our unitholders, 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 credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

The total amount we are able to borrow under our credit facility is limited by a 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. The borrowing base is subject to redetermination on a semi-annual basis and more frequent redetermination in certain circumstances. Our lenders reaffirmed the borrowing base at $100.0 million on September 20, 2012. Any substantial or sustained decline in commodity prices would likely lead to a decrease in our borrowing base upon redetermination and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. In the future, we may be unable to access sufficient capital under our 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. Also, the shipment of our oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. 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. Our access to transportation options and the prices we receive for our production can also be affected by federal and state regulation, including regulation of oil production and transportation, and pipeline safety, as well as by general economic conditions and changes in supply and demand. In addition, 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.

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.

In December 2009, the Environmental Protection Agency, or “EPA,” published its findings that emissions of carbon dioxide, methane and other greenhouse gases, or “GHGs”, present a danger to public health and the environment. Based on these findings, the EPA began adopting and implementing regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another which requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. On May 12, 2010, the EPA also issued a new “tailoring” rule, which makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. On September 22, 2009, the EPA issued 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. In addition, on November 30, 2010, the EPA published a final rule that expands its existing GHG emissions reporting rule to include certain owners and operators of onshore oil and natural gas production to monitor GHG emissions beginning in 2011 and to report those emissions beginning in 2012. We are currently monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Data collected from our initial GHG monitoring activities indicated that we do not exceed the threshold level of GHG emissions triggering a reporting obligation. To the extent we exceed the applicable regulatory threshold level in the future, we will report the emissions beginning in the applicable period. Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. 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 significant costs to reduce emissions of GHGs associated with operations or could adversely affect demand for our production.

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. If we are 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.

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 Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, enacted in July 2010, establishes a new regulatory framework for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on a derivative clearing organization and traded on an exchange or a swap execution facility, and cash collateral will have to be posted. The Dodd-Frank Act requires the Commodities Futures Trading Commission, or the CFTC, federal regulators of banks and other financial institutions (the “Prudential Regulators”) and the SEC to promulgate the rules implementing the Dodd-Frank Act, within 360 days from the date of enactment. The CFTC issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s position limits rules will become effective on October 12, 2012, although there is a pending legal proceeding seeking to enjoin those rules. The rules will impose certain position limits for spot month positions; at this time the CFTC has not established limits for non-spot month or combined month positions. Certain CFTC reporting and recordkeeping rules will become effective beginning October 12, 2012, for swap dealer entities. End user compliance with reporting rules and permanent recordkeeping rules is expected to begin 180 days after October 12, 2012.

Depending on the rules and definitions ultimately adopted by the CFTC, the SEC and the Prudential Regulators, 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. A requirement to post cash collateral could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows. We are at risk until the regulators adopt rules and definitions that confirm that companies like us are not required to post cash collateral for our derivative hedging contracts. 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 Dodd-Frank 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 flows. In addition, the Dodd-Frank Act may also require our contractual counterparties to our derivative contracts to spin-off their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. These changes might not only increase costs, but could also reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or reduce our ability to monetize or restructure our existing derivative contracts and potentially increase our exposure to less creditworthy counterparties.

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

Hydraulic fracturing is an important and common practice that is used in the completion of unconventional wells in shale formations as well as tight conventional formations, including many of those that we complete and produce. The hydraulic fracturing process involves the injection of water, sand and

chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. On July 1, 2012, the Oklahoma Corporation Commission adopted new rules requiring well operators to publicly disclose certain information regarding hydraulic fracturing operations, including the chemical composition of any liquids used in the hydraulic fracturing process. Certain proprietary information may be excluded from an operator’s disclosure. The new disclosures apply to horizontal wells that are hydraulically fractured on or after January 1, 2013 and to other wells that are hydraulically fractured on or after January 1, 2014. Additionally, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in our development or production activities.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

Risks Inherent in an Investment in Us

In addition to the risk factors presented below, there are other risk factors related to conflicts of interests and our general partner’s fiduciary duties inherent in an investment in us. See “Conflicts of Interest and Fiduciary Duties” for a discussion of those risks.

Our general partner controls us, and immediately following this offering, the Founders and Yorktown will own an approximate 36.0% limited partner interest in us, or an approximate 32.8% in us if the underwriters exercise in full their option to purchase additional common units. They 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 has control over all decisions related to our operations. Our general partner is owned by the Founders. Immediately following this offering, the Founders and Yorktown will own an approximate 36.0% limited partner interest in us, or an approximate 32.8% limited partner interest in us if the underwriters exercise in full their option to purchase additional common 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 provide services to us also devote a significant amount of time to the Mid-Con Affiliates and are 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 businesses 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 entered into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides management, administrative and operational services to us, and Mid-Con Energy Operating also provides 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 has limited 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; and

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

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

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 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 is bound by the provisions in the partnership agreement, including the provisions discussed above.

Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to provide management, administrative and operational services to us. Mid-Con Energy Operating also provides 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.

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.

Public unitholders do not have a priority right to receive distributions and are not entitled to receive any payments of arrearages.

Unlike many publicly traded partnerships, we do not have any incentive distribution rights or subordinated units. Because there are no subordinated units, our public unitholders are not senior in payment of distributions over any other parties, including the Founders or Yorktown. In addition, if the amount of any future distribution is less than the current quarterly distribution rate, public unitholders will not have any right to receive any payments of arrearages in future periods.

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;

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; or

a limited partner whose nationality, citizenship or other related status would not, in the determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we or our subsidiary has an interest.

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 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 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 do not conduct annual meetings of our unitholders to elect directors or address other matters routinely handled at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

The public unitholders are currently unable to remove our general partner without its consent because affiliates of our general partner and Yorktown own sufficient units to prevent the removal of our general partner. The vote of the holders of at least 66²/₃% of all outstanding units is required to remove our general partner. Immediately following this offering, the Founders and Yorktown will own approximately 36.0% of our outstanding common units, or approximately 32.8% of our outstanding common units if the underwriters exercise in full their option to purchase additional common units, which will enable those holders, collectively, to prevent the removal of our general partner.

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

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the Founders 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 and 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;

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 Yorktown, 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 Yorktown, 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.

Sales of our common units by significant unitholders may have an adverse impact on the trading price of our common units.

Following this offering, the Founders and Yorktown will own 6,816,660 common units or approximately 36.0% of our outstanding common units, or 6,216,660 common units or approximately 32.8% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full. Sales of these units or of other substantial amounts of our common units in the public market could cause the market price of our common units to decline. Sales of such units could also impair our ability to raise capital through the sale of additional common units.

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 continue for the common units and our unitholders may not be able to resell their common units at their initial purchase price.

Our common units are thinly traded on the public market. We do not know how liquid the trading market for our common units will be after this offering. Our unitholders may not be able to resell their common units at or above their initial purchase 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, our unitholders could lose a significant part of their investment.

The market price of our common units is subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

changes in commodity prices;

changes in interest rates;

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 partnership agreement requires that we distribute all of our available cash (as defined in our partnership agreement), 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 growth 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 or in our 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.

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.

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, the Obama Administration and 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.

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.

Legislation has been proposed 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 are 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 are treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders are 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.

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 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 U.S. federal, state and local tax returns. Andrews Kurth LLP has not rendered an opinion on the state or local tax consequences of an investment in our units.

USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $ million from our sale of common units in this offering, based upon the assumed public offering price of $ per common unit, after deducting underwriting discounts and estimated offering expenses, to repay $ million of indebtedness outstanding under our credit facility. Borrowings under our credit facility were used for short-term working capital needs and acquisitions. The borrowings bear interest at approximately 2.5%, and are due upon the expiration of our credit facility in December 2016.

Affiliates of RBC Capital Markets, LLC and Wells Fargo Securities, LLC are lenders under our credit facility, and, accordingly, will receive a substantial portion of the net proceeds from this offering. Please read “Underwriting.”

We will not receive any of the proceeds from the sale of common units by the Selling Unitholders, including any common units sold by the Selling Unitholders if the underwriters exercise their option to purchase additional common units, in whole or in part.

CAPITALIZATION

The following table shows our:

historical capitalization as of June 30, 2012; and

as adjusted capitalization as of June 30, 2012, which gives effect to this offering 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 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.”


	As of June 30, 2012
	Actual		As Adjusted
	(in thousands)
Cash and cash equivalents	$	3,964	$

Long-term debt	$	58,000	$
Equity:
General partner interest		1,638

Total partners’ equity		60,473

Total capitalization	$	118,473	$

PRICE RANGE OF COMMON UNITS AND DISTRIBUTION

Our common units are listed and traded on the NASDAQ Global Market under the symbol “MCEP.” Our common units began trading on December 15, 2011 at an initial public offering price of $18.00 per common unit. As reported by the NASDAQ Global Market, the following table shows the low and high sales prices per common unit for the periods indicated. Distributions are shown in the quarter for which they were paid:


	Low		High		Cash distribution per unit
2012:
Third quarter (through September 25, 2012)	$	20.31	$	24.12	$	—(2)
Second quarter	$	17.87	$	24.66	$	0.475
First quarter	$	18.25	$	25.18	$	0.475
2011:
Fourth quarter(1)	$	17.25	$	18.87	$	0.057	(3)

(1)

From December 15, 2011, the day our common units began trading on the NASDAQ Global Market, through December 31, 2011.

(2)

The distribution payable for the third quarter of 2012 has not been declared or paid.

(3)

Reflects the pro rata portion of the $0.475 quarterly distribution per unit paid, representing the period from the day after the December 20, 2011 closing of our initial public offering through December 31, 2011. An identical cash distribution was paid on all outstanding common and general partner units.

The last reported sale price of our common units on the NASDAQ Global Market on September 25, 2012 was $22.84. As of September 13, 2012, there were approximately 30 holders of record of our common units. This number does not include owners for whom common units may be held in “street” name.

SELECTED HISTORICAL FINANCIAL DATA

The following table shows selected financial data of us and our predecessor for the periods and as of the dates indicated. The selected financial data as of and for the years ended June 30, 2007 and 2008 are derived from the audited consolidated financial statements of our predecessor not included in this prospectus. The selected financial data as of and for the year ended June 30, 2009 are derived from the audited consolidated financial statements of our predecessor included elsewhere in this prospectus. The selected financial data as of and for the years ended December 31, 2010 and 2011 and as of and for the six months ended December 31, 2009 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected financial data for the six months ended June 30, 2011 and 2012 are derived from our unaudited consolidated financial statements. The selected financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical consolidated financial statements of Mid-Con Energy Partners, LP and our predecessor and the unaudited condensed financial statements of Mid-Con Energy Partners, LP and the notes thereto included elsewhere in this prospectus.

The following table represents 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 Corporation (consolidated)								Mid-Con Energy Partners, LP
	Year Ended June 30,								Six Months Ended December 31,			Year Ended December 31,						Six Months Ended June 30,
Statement of Operations Data:	2007		2008			2009			2009			2010			2011			2011			2012
																		(unaudited)			(unaudited)
						(in thousands)
Revenues:
Oil sales	$	6,944	$	13,667		$	10,246		$	5,729		$	16,853		$	36,813		$	15,609		$	28,998
Natural gas sales		64		618			2,172			743			1,418			1,218			658			353
Realized gain (loss) on derivatives, net		558		(804	)		(669	)		(350	)		(90	)		(2,157	)		(715	)		769
Unrealized gain (loss) on derivatives, net		45		(2,035	)		1,679			(147	)		(707	)		3,437			1,046			9,741

Total revenues		7,611		11,446			13,428			5,975			17,474			39,311			16,598			39,861

Operating costs and expenses:
Lease operating expenses		3,429		5,005			5,369			2,431			6,237			8,491			3,550			4,725
Oil and gas production taxes		478		946			631			269			822			1,869			656			713
Dry holes and abandonments of unproved properties		220		—			—			—			1,418			813			772			—
Geological and geophysical		342		1,296			507			—			394			172			—			—
Depreciation, depletion and amortization		924		1,599			2,293			2,552			5,851			7,160			2,418			4,709
Accretion of discount on asset retirement obligations		35		56			78			58			127			78			32			57
General and administrative		1,805		1,871			1,767			704			982			1,924			534			4,869
Impairment of proved oil and gas properties		—		—			—			9,208			1,886			—			—			—

Total operating costs and expenses		7,233		10,773			10,645			15,222			17,717			20,507			7,962			15,073

Income (loss) from operations		378		673			2,783			(9,247	)		(243	)		18,804			8,636			24,788


	Mid-Con Energy Corporation (consolidated)									Mid-Con Energy Partners, LP
	Year Ended June 30,									Six Months Ended December 31,			Year Ended December 31,						Six Months Ended June 30,
Statement of Operations Data:	2007			2008			2009			2009			2010			2011			2011			2012
																			(unaudited)			(unaudited)
							(in thousands)
Other income (expenses):
Interest income and other		126			115			118			35			218			216			62			5
Interest expense		(11	)		(3	)		(93	)		(2	)		(98	)		(578	)		(237	)		(703	)
Gain on sale of assets		—			—			1			—			354			1,621			1,209			—
Equity-based compensation		—			—			—			—			—			(1,671	)		—			—
Other revenue and expenses, net		439			108			298			118			847			576			576			—
Tax expense — current		—			—			(625	)		—			—			—			—			—
Tax (expense) benefit — deferred		(197	)		(261	)		502			—			—			—			—			—

Net income (loss)	$	735		$	632		$	2,984		$	(9,096	)	$	1,078		$	18,968		$	10,246		$	24,090

Net income per limited partner unit (basic and diluted)										$	(0.51	)	$	0.06		$	1.05		$	0.57		$	1.33

Weighted average number of limited partner units outstanding (basic and diluted)											17,640			17,640			17,640			17,640			17,790

Other Financial Data:
Adjusted EBITDA				$	4,471		$	3,773		$	2,836		$	10,593		$	23,994		$	11,388		$	22,503
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	2,052		$	4,221		$	10,935		$	965		$	11,798		$	24,113		$	5,192		$	24,384
Investing activities		(11,143	)		(7,646	)		(12,448	)		(5,018	)		(22,726	)		(42,045	)		(13,351	)		(23,992	)
Financing activities		9,980			147			4,841			(1,164	)		10,387			17,938			8,377			3,344


	Mid-Con Energy Partners, LP
	As of December 31,							As of June 30,
Balance Sheet Data:	2009		2010			2011		2011		2012
Working capital(1)	$	2,420	$	(1,256	)	$	2,361	$	4,383	$	11,879
Total assets		40,496		56,867			96,611		72,390		125,148
Total debt		337		5,513			45,000		13,310		58,000
Equity		36,779		43,072			43,349		56,098		60,473

(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 Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus.

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 generally intend to hedge a significant portion of our production volumes through various commodity derivative contracts.

As of December 31, 2011, our total estimated proved reserves were approximately 10.0 MMBoe, of which approximately 99% were oil and 69% were proved developed, both on a Boe basis. As of December 31, 2011, Mid-Con Energy Operating operated 99% of our properties and 96% were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended June 30, 2012 was approximately 1,844 Boe per day and based on our December 31, 2011 audited reserves, as adjusted for average net production for the six months ended June 30, 2012, our total estimated proved reserves had a reserve-to-production ratio of approximately 15 years. As of December 31, 2011, our management team developed approximately 59% 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 December 31, 2010 and 2011 and for the six months ended June 30, 2011 and 2012.


	Year Ended December 31,				Six Months Ended June 30,
	2010		2011		2011		2012
Oil (MBbls)		228		407		167		304
Natural Gas (MMcf)		191		164		79		60

Total (MBoe)		260		434		180		314

Average Net Production (Boe/d)		710		1,191		994		1,725

Realized Prices on the Sale of Oil

Factors Affecting the Sales Price of Oil. 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. 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.

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).

Sales Contracts. For the six months ended June 30, 2012, sales to Enterprise, Sunoco Logistics and Vitol accounted for approximately 54%, 37% and 2%, respectively, of our total sales. We enter into six month crude oil purchase agreements with each of our purchasers with month-to-month extensions until either party terminates the contract with a thirty day notice. We believe this allows us to obtain favorable and more predictable pricing for our production than would otherwise be available to us if smaller amounts of our production had been sold to several purchasers based on posted prices.

Our purchase agreements with our purchasers all provide a fixed NYMEX-WTI differential for all production from an individual producing lease. Settlement under all of these purchase agreements occurs monthly, with payment being made on or about the 20th of each month for oil delivered during the previous month. The ultimate price per barrel paid to us by our purchasers is based on a daily average settling price of the near month NYMEX-WTI light sweet crude oil contract during the month in which the oil is actually delivered, minus the applicable differential.

We will continue to compare the pricing under our crude oil purchase contracts to offers from other purchasers to determine the best price in the relevant market.

Commodity Derivative Contracts. To better manage oil price fluctuations and achieve more predictable cash flow, we maintain a portfolio of hedge contracts to help protect our ability to make distributions. These instruments limit our exposure to declines in prices, but also limit our upside if prices increase. Because the prices at which we sell a substantial majority of our oil production are determined by the NYMEX-WTI futures price, our derivatives contract pricing strategy is intended to manage and reduce our exposure to NYMEX-WTI price fluctuations, and is not dependent upon or influenced by the portion of our production we sell to any of our customers.

As of September 25, 2012, for the three months ending December 31, 2012 and the years ending December 31, 2013 and 2014, we have commodity derivative contracts covering approximately 69.9%,

69.6% and 57.0%, respectively, of our fourth quarter 2012 and calendar years 2013 and 2014 average daily oil production (as estimated from the projection of our oil production in our audited proved reserves as of December 31, 2011). All of our derivative contracts for 2012, 2013 and 2014 are either swaps with fixed settlements or collars. The weighted average minimum prices on all of our derivative contracts for 2012, 2013 and 2014 are $101.59, $99.66 and $94.30, respectively.

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:


	Six Months Ended December 31,		Year Ended December 31,
	2012		2013		2014
Oil Derivative Contracts:
Swap Contracts:
Volume (Bbls/d)		1,207		1,216		1,315
Weighted Average NYMEX-WTI price per Bbl	$	101.85	$	100.14	$	94.30
Put/Call Option Contracts (Collars):
Volume (Bbls/d)		196		296		—
Weighted Average Floor-Ceiling NYMEX-WTI price per Bbl	$	100.00–$117.00	$	97.67–108.08	$	—

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 by 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, 2012. During the same twelve month period, per unit lease operating expenses for our Highlands Unit decreased from approximately $16.41 per Boe, for the twelve months ending June 30, 2011, to $9.47 per Boe for the twelve months ended

June 30, 2012 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;

equity-based compensation; 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 generally increased since the second quarter of 2009, the demand for oil remains mixed in foreign markets, especially in China, and the outlook and timing for a worldwide economic recovery remains uncertain for the foreseeable future and the timing of a recovery in worldwide demand for energy to pre-2008 levels is difficult to predict. As a result, it is likely that commodity prices will continue to be volatile in 2012. 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. Significant factors that may impact future commodity prices include the political and economic developments currently impacting North Africa and the Middle East in general, the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas, and the overall North American oil and natural gas supply fundamentals.

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 for us and our predecessor for the periods presented. The following table should be read in conjunction with “Selected Historical Financial Data.”


	Mid-Con Energy Corporation (consolidated)			Mid-Con Energy Partners, LP
	Year Ended June 30,			Six Months Ended December 31,			Year Ended December 31,						Six Months Ended June 30,
	2009			2009			2010			2011			2011			2012
													(unaudited)			(unaudited)
	(in thousands)
Revenues (in thousands):
Oil sales	$	10,246		$	5,729		$	16,853		$	36,813		$	15,609		$	28,998
Natural gas sales		2,172			743			1,418			1,218			658			353
Realized gain (loss) on derivatives, net		(669	)		(350	)		(90	)		(2,157	)		(715	)		769
Unrealized gain (loss) on derivatives, net		1,679			(147	)		(707	)		3,437			1,046			9,741

Total Revenues	$	13,428		$	5,975		$	17,474		$	39,311		$	16,598		$	39,861

Expenses (in thousands):
Lease operating expense	$	5,369		$	2,431		$	6,237		$	8,491			3,550		$	4,725
Oil and gas production taxes		631			269			822			1,869			656			713
Dry holes and abandonments of unproved properties		—			—			1,418			813			772			—
Depreciation, depletion and amortization(1)		2,103			2,357			5,204			6,795			2,080			4,709
General and administrative(3)		1,767			704			982			1,924			534			4,869
Impairment of proved oil and gas properties		—			9,208			1,886			—			—			—
Interest expense		93			2			98			578			237			703
Production:
Oil (MBbls)		153			87			228			407			167			304
Natural gas (MMcf)		341			140			191			164			79			60
Total (MBoe)		210			110			260			434			180			314
Average net production (Boe/d)		575			602			710			1,191			994			1,725
Average sales price:
Oil (per Bbl):
Sales price	$	66.87		$	65.85		$	73.92		$	90.45		$	93.47		$	95.39
Effect of realized commodity derivative instruments	$	(4.37	)	$	(4.02	)	$	(0.39	)	$	(5.30	)	$	(4.28	)	$	2.53
Realized price	$	62.50		$	61.83		$	73.53		$	85.15		$	89.19		$	97.92
Natural gas (per Mcf):
Sales price(2)	$	6.37		$	5.31		$	7.42		$	7.43		$	8.33		$	5.88
Average unit costs per Boe:
Lease operating expenses	$	25.56		$	22.10		$	23.99		$	19.56		$	19.72		$	15.05
Oil and gas production taxes	$	3.00		$	2.45		$	3.16		$	4.31		$	3.64		$	2.27
General and administrative expenses	$	8.41		$	6.40		$	3.78		$	4.43		$	2.97		$	15.51
Depreciation, depletion and amortization	$	10.01		$	21.43		$	20.02		$	15.66		$	11.56		$	15.00

(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.

(3)

General and administrative expenses include non-cash, equity-based compensation for the six months ended June 30, 2012. We had no non-cash, equity based compensation expense for the year ended December 31, 2011.

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:

Our initial public offering of 5,400,000 common units and subsequent over-allotment offering of 810,000 common units in December 2011 and January 2012, respectively;

The drilling of 35 wells in 2010, 48 wells in 2011 and 14 wells during the six months ended June 30, 2012 on our properties in Oklahoma;

Our sale to the Mid-Con Affiliates on June 30, 2011 of certain properties representing less than 1% of our proved reserves by value, as calculated using the standardized measure, as of September 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;

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;

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;

Our acquisition in December 2011 of additional working interests in the Cushing Field for $6.0 million; and

The acquisition in June 2012 of certain oil properties located in our Northeastern Oklahoma core area and additional working interests in our existing units in our Southern Oklahoma core area.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Sales Revenues. Revenues from oil and natural gas sales for the six months ended June 30, 2012 were approximately $29.4 million as compared to approximately $16.3 million for the six months ended June 30, 2011. The increase in revenues was primarily due to an increase in daily oil production in 2012.

Our production volumes for the six months ended June 30, 2012 were 314 MBoe, or 1,725 Boe per day. In comparison, our production volumes for the six months ended June 30, 2011 were 180 MBoe, or 994 Boe per day. The increase in production volumes was primarily due to ongoing waterflood response to injection as well as the drilling programs in our Southern Oklahoma core area, and the acquisitions of

interests in various properties located in the Hugoton Basin area, which both occurred during the second half of 2011. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the six months ended June 30, 2012 was $95.39, compared with $93.47 for the six months ended June 30, 2011.

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, 2012 of approximately $10.5 million, which was composed of a realized gain of approximately $0.8 million and an unrealized gain of approximately $9.7 million. For the six months ended June 30, 2011, we recorded a net gain from our commodity hedging program of approximately $0.3 million, which was composed of a realized loss of approximately $0.7 million and an unrealized gain of approximately $1.0 million.

Lease Operating Expenses. Our lease operating expenses were $4.7 million for the six months ended June 30, 2012, or $15.05 per Boe, compared to $3.6 million for the six months ended June 30, 2011, or approximately $19.72 per Boe. The increase in total lease operating expenses during the six months ended June 30, 2012 was primarily attributable to an increase in production resulting from our drilling programs and the increase in the number of producing wells. The decrease in lease operating expenses per Boe was due to the increased production for the six months ended June 30, 2012. Ad valorem taxes are also reflected in lease operating expenses. Ad valorem taxes are levied on our properties in 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, 2012, or $2.27 per Boe for an effective tax rate of 2.4%, compared to $0.7 million for the six months ended June 30, 2011, or $3.64 per Boe for an effective tax rate of approximately 4.0%. The decrease in the production taxes per Boe during the six months ended June 30, 2012 was primarily due to receiving an adjustment of $0.5 million of production taxes for one of our Southern Oklahoma units for periods prior to the year 2012. The adjustment was due to the Enhanced Recovery Project Gross Production Tax Exemption. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. 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 continue to receive a reduced production rate due to Oklahoma’s Enhanced Recovery Project Gross Production Tax Exemption which has been extended to July 2014.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing properties for the six months ended June 30, 2012 were $4.7 million, or $15.00 per Boe produced, compared to $2.1 million, or $11.56 per Boe produced, for the six months ended June 30, 2011. The increase in depreciation, depletion and amortization expenses and average price per Boe produced was primarily due to the increase in total proved and proved developed reserves estimated at June 30, 2012 and also the increase in total asset value of $40.0 million from our drilling program that occurred in the second half of 2011, and acquisitions of properties in our Hugoton Basin and Southern Oklahoma core areas, which both occurred during the second half of 2011.

General and Administrative Expenses. Our general and administrative expenses were approximately $4.9 million for the six months ended June 30, 2012, or $15.51 per Boe produced compared to approximately $0.5 million for the six months ended June 30, 2011 or $2.97 per Boe produced. The increase in general and administrative expenses for the six months ended June 30, 2012 is primarily due to higher compensation costs related to our non-cash equity-based compensation expense of $2.7 million, higher professional fees necessary to comply with public reporting requirements and incremental costs related to the hiring of additional staff.

Interest Expense. Our interest expense for the six months ended June 30, 2012 was $0.7 million, compared to $0.2 million for the six months ended June 30, 2011. The increase was primarily due to increased borrowings under our credit facility.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Sales Revenues. Revenues from oil and natural gas sales for the twelve months ended December 31, 2011 were approximately $38.0 million as compared to $18.3 million for the twelve months ended December 31, 2010. The increase in revenues was primarily due to an increase in daily oil production and higher sales prices during the twelve months ended December 31, 2011.

Our production volumes for the twelve months ended December 31, 2011 were 434 MBoe, or 1,191 Boe per day. In comparison, our production volumes for the twelve months ended December 31, 2010 were 260 MBoe, or 710 Boe per day. The increase in production volumes was primarily due to ongoing waterflood response to injection, and the drilling programs in our Oklahoma waterflood units in addition to the acquisition of interests in various properties located in the Hugoton Basin area. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the twelve months ended December 31, 2011 was $90.45, compared with $73.92 for the twelve months ended December 31, 2010.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, we recorded a net gain from our commodity hedging program for the twelve months ended December 31, 2011 of approximately $1.3 million, which was composed of a realized loss of $2.2 million and an unrealized gain of $3.4 million. For the twelve months ended December 31, 2010, we recorded a net loss from our commodity hedging program of approximately $0.8 million, which was composed of a realized loss of $0.1 million and an unrealized loss of $0.7 million.

Lease Operating Expenses. Our lease operating expenses were $8.5 million for the twelve months ended December 31, 2011, or $19.56 per Boe, compared to $6.2 million for the twelve months ended December 31, 2010, or $23.99 per Boe. The increase in total lease operating expenses during the twelve months ended December 31, 2011 was primarily attributable to an increase in production resulting from drilling programs, to injection and an increase in the number of wells producing. The decrease in lease operating expenses per Boe was due to the increased production for the twelve months ended December 31, 2011. Ad valorem taxes were also reflected in lease operating expenses. Ad valorem taxes are levied on our properties in 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 $1.9 million for the twelve months ended December 31, 2011, or $4.31 per Boe for an effective tax rate of 4.9%, compared to $0.8 million for the twelve months ended December 31, 2010, or $3.16 per Boe for an effective tax rate of 4.5%. The increase in production taxes during the twelve months ended December 31, 2011 was primarily due to the increase in the realized average oil sales price. 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 received a reduced rate due to the Enhanced Recovery Project Gross Production Tax Exemption.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing properties for the twelve months ended December 31, 2011 were $6.8 million, or $15.66 per Boe produced, compared to $5.2 million, or $20.02 per Boe produced, for the twelve months ended December 31, 2010. The increase in depreciation, depletion and amortization expenses on an overall and a decrease on a per Boe produced basis was primarily due to the substantial increase in proved

developed reserves estimated at December 31, 2011, in addition to the acquisition of waterflood units in our Hugoton Basin and Southern Oklahoma core areas.

Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2010, we recorded a non-cash impairment charge of $1.9 million due to a decline in reserve estimates for certain producing properties. There was no impairment charge for the year ended December 31, 2011.

General and Administrative Expenses. Our general and administrative expenses were approximately $1.9 million for the twelve months ended December 31, 2011, or $4.43 per Boe produced compared to $1.0 million for the twelve months ended December 31, 2010 or $3.78 per Boe produced. The increase in general and administrative expenses for the twelve months ended December 31, 2011 resulted primarily from higher professional fees of approximately $0.5 million and higher personnel costs of approximately $0.4 million. Professional fees included costs related to the preparation of our registration statement on Form S-1 for our initial public offering and compliance with public reporting requirements, some of which are believed to be non-recurring. Personnel costs were higher due to an increase in employees throughout the organization.

Interest Expense. Our interest expense for the twelve months ended December 31, 2011 was $0.6 million, compared to $0.1 million for the twelve months ended December 31, 2010. The increase was primarily due to increased borrowings on our credit facilities for capital expenditures and acquisitions. In addition, in December 2011, we entered into our current credit facility which resulted in higher average borrowings outstanding.

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 260 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 addition, 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 $73.92, compared with $65.85 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 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 $23.99 per Boe, compared to $2.4 million for the six months ended December 31, 2009, or $22.10 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 $3.16 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 $5.2 million, or $20.02 per Boe produced, compared to $2.4 million, or $21.43 per Boe produced, for the six months ended December 31, 2009. The decrease per Boe produced was primarily due to an increase in proved developed reserves during the year ended December 31, 2010.

Impairment of Oil and Natural Gas Properties. An impairment of $1.9 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 $9.2 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 $3.78 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 2011, we entered into our current credit facility which resulted in higher average 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. In comparison, our production volumes for the year ended June 30, 2009 were 210 MBoe, or 575 Boe per day. 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. Our average sales price per barrel for oil, excluding commodity derivative contracts, for the six months ended December 31, 2009 was $65.85 compared with $66.87 for the year ended June 30, 2009.

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 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 $22.10 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 $2.4 million, or $21.43 per Boe produced, as compared to $2.1 million, or $10.01 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 $9.2 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 $93,000 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.

Liquidity and Capital Resources

Prior to our initial public offering, our primary sources of liquidity and capital resources were proceeds from capital contributions from Yorktown, bank borrowings, and cash flow from operations. Our primary uses of capital were for the acquisition, development and drilling of waterflood units.

As a publicly traded partnership, our primary sources of liquidity and capital resources are from cash flow generated by operating activities and borrowings under our credit facility. We also expect to be able to issue additional equity and debt securities from time to time as market conditions allow. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and our 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 permits 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

generally intend 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 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 borrow to fund our distributions.

Cash Flow

Net cash provided by operating activities was approximately $24.1 million, $11.8 million, $10.9 million, $24.4 million, $5.2 million and $1.0 million for the twelve months ended December 31, 2011, December 31, 2010 and June 30, 2009 and for the six months ended June 30, 2012, June 30, 2011, and December 31, 2009, respectively. Our revenues increased significantly for the year ended December 31, 2011 and for the six months ended June 30, 2012 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 $42.0 million, $22.7 million, $12.4 million, $24.0 million, $13.4 million and $5.0 million for the twelve months ended December 31, 2011, December 31, 2010 and June 30, 2009 and for the six months ended June 30, 2012, June 30, 2011 and December 31, 2009, respectively. The increased amount of cash used in investing activities was primarily due to the increased waterflood development activities in Southern Oklahoma, including the in-field drilling in these units, development activity in our Northeastern Oklahoma core area and acquisitions.

Net cash (used in) provided by financing activities was approximately $17.9 million, $10.4 million, $4.8 million, $3.3 million, $8.4 million and ($1.2) million for the twelve months ended December 31, 2011, December 31, 2010 and June 30, 2009 and for the six months ended June 30, 2012, June 30, 2011 and December 31, 2009, respectively. During the six months ended June 30, 2012, we used net borrowings of $13.0 million from our credit facility to finance the purchase of certain oil properties located in our Northeastern Oklahoma core area and certain working interests in our existing units in our Southern Oklahoma core area and paid cash distributions of approximately $9.7 million. For the six months ended June 30, 2011, net cash provided by financing activities was used to acquire the War Party I and II Units in our Hugoton Basin core area. 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 year ended December 31, 2011, we received net proceeds of $87.4 million from our initial public offering, and net proceeds from our financing arrangements of $39.2 million which were used to fund our drilling activity in Southern Oklahoma and the distribution of $110.9 million to redeem the limited liability company membership units held by certain employees, directors, and non-affiliates for the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at the closing of our initial public offering. 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 $4.8 million distribution to certain 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 $11.9 million, $2.4 million, $4.4 million, ($1.2) million and $2.4 million at June 30, 2012, December 31, 2011, June 30, 2011, December 31, 2010 and December 31, 2009, respectively. Our cash balances at June 30, 2012, December 31, 2011, June 30, 2011, December 31, 2010 and December 31, 2009 were $4.0 million, $0.2 million, $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 excluded $5.3 million of maturities under our prior credit facilities. These facilities were repaid in full with proceeds from our initial public offering.

Capital Expenditures

We have budgeted a total of $15.6 million capital expenditures for 2012 based on our December 31, 2011 audited reserves and have spent $7.6 million during the six months ending June 30, 2012, which includes $2.4 million for maintenance capital expenditures. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our waterflood operations and production over the long-term. Our maintenance capital expenditures are intended to maintain the appropriate injection, reservoir pressure and resulting production response. While our maintenance capital expenditures are focused on maintaining our existing production, they could also create production increases as well. We estimate that maintenance capital expenditures will average approximately $5.0 million per year through the next five years.

Growth capital expenditures are capital expenditures that we expect to make to either develop new waterfloods or add primary production through newly initiated development programs. 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 which are at an early stage of development. Growth capital expenditures may also include acquisitions of additional oil and gas properties, including new producing wells that are either in the primary stage of production or in the secondary stage of production but which we believe have upside potential. 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 generally plan to use cash flow from operations to fund our maintenance capital expenditures. We plan primarily to use external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, to make growth capital expenditures. 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 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 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.

Credit Facility

Our wholly owned subsidiary, Mid-Con Energy Properties, as borrower, and we, as guarantor, have a $250.0 million senior secured revolving credit facility that expires in December 2016. Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiary. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to partners. The facility requires the maintenance of a leverage ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (each as defined in the credit agreement) of not more than 4.0 to 1.0, and a current ratio of not less than 1.0 to 1.0. As of June 30, 2012, we were in compliance with all of the facility’s financial covenants.

Borrowings under the facility may not exceed our current borrowing base of $100.0 million. The borrowing base is determined by the lenders based on our oil and natural gas reserves. The borrowing base is subject to scheduled redeterminations on or about April 30 and October 31 of each year with an optional redetermination during the period between each scheduled borrowing base determination, either at our request or at the request of the lenders. An optional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. The borrowing base is determined by our lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that may vary.

Additionally, borrowings under the facility will bear interest, at Mid-Con Energy Properties’ option, at either (i) the greater of the prime rate of the Royal Bank of Canada, the federal funds effective rate plus 0.50%, and the one month adjusted London Inter-Bank Offered Rate (LIBOR) plus 1.0% , all of which is subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. At June 30, 2012, we had $58.0 million of borrowings outstanding under our credit facility.

We continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility. As of June 30, 2012, our $250.0 million senior secured credit facility had borrowing capacity of $42.0 million ($100.0 million borrowing base less $58.0 million of outstanding borrowings under our credit facility). On April 23, 2012, the borrowing base of our credit facility increased from $75.0 million to $100.0 million, and on September 20, 2012 the borrowing base was reaffirmed by our lenders at $100.0 million.

Derivative Contracts

For the three months ending December 31, 2012 and years ending December 31, 2013 and 2014, we have commodity derivative contracts covering approximately 69.9%, 69.6% and 57.0%, respectively, of our fourth quarter 2012 and calendar years 2013 and 2014 average daily oil production (as estimated from the projection of our oil production in our audit of proved reserves as of December 31, 2011).

The following table summarizes, for the periods indicated, our oil swaps and put/call options, or “collars,” through December 31, 2014. These transactions are settled based upon the NYMEX-WTI price of oil.


Term	Type of Derivative	Weighted Average ($/Bbl)		Bbls/d
2012	Swaps	$	101.85		1,207
2012	Put/Call (Collars)	$	100 – $117		196
2013	Swaps	$	100.14		1,216
2013	Put/Call (Collars)	$	97.67 –108.08		296
2014	Swaps	$	94.30		1,315

Our hedging strategy is to enter into various commodity derivative contracts intended to achieve more predictable cash flows and to reduce exposure to fluctuations in the price of oil. Our hedging program’s objective is to protect our ability to make current distributions, and to allow us to be better positioned to increase our quarterly distributions over time, while retaining some ability to participate in upward movements in oil prices. We use a phased approach, looking approximately 36 months forward while targeting a higher hedged percentage in the near 12 months of the period. As of September 25, 2012, for the three months ending December 31, 2012 and the years ending December 31, 2013 and 2014, we have commodity derivative contracts covering approximately 69.9%, 69.6% and 57.0%, respectively, of our fourth quarter 2012 and calendar years 2013 and 2014 average daily oil production (as estimated from the projection of our oil production in our reserve audit of proved reserves as of December 31, 2011). All of our derivative contracts for 2012, 2013 and 2014 are either swaps with fixed settlements or collars. The weighted average minimum prices on all of our derivative contracts for 2012, 2013 and 2014 are $101.59, $99.66 and $94.30, respectively.

The following table details, for the periods indicated, our oil swaps and collars, through December 31, 2014. These transactions are settled based upon the NYMEX-WTI price of oil.


Months Outstanding	Settlement Price		Floor		Ceiling		Instrument Type	Total Bbls. Per Month		NYMEX Index
Oct-Dec 2012			$	100.00	$	117.00	Collar		6,000		WTI
Oct-Dec 2012	$	104.28					Swap		6,000		WTI
Oct-Dec 2012	$	100.00					Swap		8,000		WTI
Oct-Dec 2012	$	100.97					Swap		10,000		WTI
Oct-Dec 2012	$	99.95					Swap		5,000		WTI
Oct-Dec 2012	$	101.40					Swap		5,000		WTI
Oct-Dec 2012	$	108.80					Swap		3,000		WTI


Months Outstanding	Settlement Price		Floor		Ceiling		Instrument Type	Total Bbls. Per Month		NYMEX Index
Jan-Dec 2013			$	100.00	$	111.00	Collar		6,000		WTI
Jan-Dec 2013	$	105.80					Swap		6,000		WTI
Jan-Dec 2013	$	96.00					Swap		8,000		WTI
Jan-Dec 2013	$	97.70					Swap		5,000		WTI
Jan-Dec 2013	$	99.05					Swap		5,000		WTI
Jan-Dec 2013	$	100.05					Swap		5,000		WTI
Jan-Dec 2013	$	104.70					Swap		5,000		WTI
Jan-Dec 2013	$	98.30					Swap		3,000		WTI
Jan-Dec 2013			$	93.00	$	102.25	Collar		3,000		WTI
Jan-Dec 2014	$	96.10					Swap		5,000		WTI
Jan-Dec 2014	$	100.00					Swap		5,000		WTI
Jan-Dec 2014	$	97.40					Swap		5,000		WTI
Jan-Dec 2014	$	97.96					Swap		5,000		WTI
Jan-Dec 2014	$	89.50					Swap		5,000		WTI
Jan-Dec 2014	$	89.35					Swap		5,000		WTI
Jan-Dec 2014	$	89.87					Swap		5,000		WTI
Jan-Dec 2014	$	94.25					Swap		5,000		WTI

Contractual Obligations

A summary of our contractual obligations as of June 30, 2012 is provided in the following table.


	Obligations Due in Period
Contractual Obligation	2012		2013		2014		2015		Thereafter		Total
	(in thousands)
Long-term debt	$	—	$	—	$	—	$	—	$	58,000	$	58,000