S-1/A 1 h83468a4sv1za.htm FORM S-1/A sv1za
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As filed with the Securities and Exchange Commission on December 6, 2011
Registration No. 333-176265
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 4
to
 
Form S-1
 
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
Mid-Con Energy Partners, LP
(Exact name of registrant as specified in its charter)
 
         
Delaware
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  45-2842469
(I.R.S. Employer
Identification Number)
 
2501 North Harwood Street, Suite 2410
Dallas, Texas 75201
(918) 743-7575
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
Charles R. Olmstead
Mid-Con Energy GP, LLC
2431 E. 61st Street, Suite 850
Tulsa, Oklahoma 74136
(918) 743-7575
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
Copies to:
 
         
Richard M. Carson
GableGotwals
1100 ONEOK Plaza
100 W. Fifth Street
Tulsa, Oklahoma 74103
(918) 595-4800
  William J. Cooper
Andrews Kurth LLP
1350 I Street, NW
Suite 1100
Washington, DC 20005
(202) 662-2700
  J. Michael Chambers
Brett E. Braden
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400
 
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.
 
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
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.
 


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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 the offer or sale is not permitted.
 
Subject to Completion, dated December 6, 2011
 
PRELIMINARY PROSPECTUS          
 
(MID-CON ENERGY LOGO)
 
 
 
 
Mid-Con Energy Partners, LP
5,400,000 Common Units
Representing Limited Partner Interests
 
 
 
 
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. This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial public offering price to be between $19.00 and $21.00 per common unit.
 
We have been approved to list our common units on the NASDAQ Global Market under the symbol “MCEP.”
 
Investing in our common units involves risks. See “Risk Factors” beginning on page 22.
 
These risks include the following:
 
  •  We may not have sufficient cash to pay the initial quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.
 
  •  We would not have generated sufficient available cash on a pro forma basis to have paid the initial quarterly distribution on all of our units for the twelve months ended September 30, 2011.
 
  •  Unless we replace the oil reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders at the initial quarterly distribution rate.
 
  •  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.
 
  •  Our general partner, who controls us, will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.
 
  •  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 will manage us will also provide substantially similar services to affiliates of our general partner, and thus will not be 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, which could reduce the price at which our common units will trade.
 
  •  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(1)
  $       $    
Proceeds, before expenses(2)
  $       $  
(1) Excludes a structuring fee equal to 0.375% of the gross proceeds of this offering payable to RBC Capital Markets, LLC.
 
(2) After deducting the underwriting discount, the structuring fee and the estimated offering expenses and applying the offering proceeds as described in “Use of Proceeds” on page 46, we do not expect that any of the net proceeds of the offering will be available for investment in our business.
 
We have granted the underwriters a 30-day option to purchase up to an additional 810,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 5,400,000 common units in this offering.
 
The underwriters expect to deliver the common units on or about          , 2011.
 
 
 
 
RBC Capital Markets Raymond James Wells Fargo Securities
 
Baird Oppenheimer & Co.
 
 
 
 
, 2011


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(GRAPHICS)
 
As of and for the month ended September 30, 2011
 
  •  Total estimated proved reserves: 9.9 MMBoe, 98% oil and 69% proved developed, both on a Boe basis.
 
  •  272 gross producing oil and natural gas wells (174 net wells) and 139 gross injection wells (85 net wells), 21 gross wells (14 net wells) shut-in or waiting on completion, 99% of our properties are operated by us, and 92% of our reserves were being produced under waterflood, both on a Boe basis.
 


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You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.
 
Until          , 2011 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”
 
 
Industry and Market Data
 
The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.


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PROSPECTUS SUMMARY
 
This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk Factors” and the historical and unaudited pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes that the underwriters do not exercise their option to purchase up to an additional 810,000 common units, unless otherwise indicated. As used in this prospectus, unless we indicate otherwise:
 
  •  “Contributing Parties” collectively refers to the Founders, Yorktown, our executive officers, employees and other individuals and entities who hold membership interests in our predecessor;
 
  •  “Founders” collectively refers to Charles R. Olmstead, S. Craig George and Jeffrey R. Olmstead;
 
  •  “our general partner” refers to Mid-Con Energy GP, LLC;
 
  •  “Mid-Con Affiliates” collectively refers to Mid-Con Energy III, LLC and Mid-Con Energy IV, LLC, which are affiliates of our general partner;
 
  •  “Mid-Con Energy Partners,” the “partnership,” “we,” “our,” “us” or like terms when used in a historical context refer to our predecessor, which will be merged with and into Mid-Con Energy Properties, LLC, our wholly owned subsidiary, in connection with this offering. When used in the present tense or prospectively, those terms refer to Mid-Con Energy Partners, LP, a Delaware limited partnership, and its subsidiaries;
 
  •  “Mid-Con Energy Operating” refers to Mid-Con Energy Operating, Inc., an affiliate of our general partner;
 
  •  “Mid-Con Energy Properties” refers to Mid-Con Energy Properties, LLC, our wholly owned subsidiary;
 
  •  “our predecessor” collectively refers to Mid-Con Energy Corporation, prior to June 30, 2009, and to Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, on a combined basis, thereafter, our respective predecessors for accounting purposes; and
 
  •  “Yorktown” collectively refers to Yorktown Partners LLC, Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., 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 B. Our estimated proved reserve information as of December 31, 2010 and September 30, 2011 is based on a report prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. A summary of our estimated proved reserve information as of September 30, 2011 prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc. is included in this prospectus in Appendix C.
 
Mid-Con Energy Partners, LP
 
Overview
 
We are a Delaware limited partnership formed in July 2011 to own, operate, acquire, exploit and develop producing oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our management team has significant industry experience, especially with waterflood projects and, as a result, our operations focus primarily on enhancing the development of producing oil properties through waterflooding. Through the continued development of our existing properties and through future acquisitions, we will seek to


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increase our reserves and production in order to maintain and, over time, increase distributions to our unitholders. Also, in order to enhance the stability of our cash flow for the benefit of our unitholders, we will seek to hedge a significant portion of our production volumes through various commodity derivative contracts.
 
As of September 30, 2011, our total estimated proved reserves were 9.9 MMBoe, of which approximately 98% were oil and 69% were proved developed, both on a Boe basis. As of September 30, 2011, we operated 99% of our properties through our affiliate, Mid-Con Energy Operating, and 92% of our properties were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended September 30, 2011 was approximately 1,343 Boe per day and our total estimated proved reserves had a reserve-to-production ratio of approximately 20 years. Our management team developed approximately 60% 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 September 30, 2011, approximately 91% of the properties associated with our estimated reserves, on a Boe basis, have been producing continuously since 1982 or earlier. Through the application of waterflooding, we believe these mature properties have attractive upside potential. Waterflooding, a form of secondary oil recovery, works by repressuring a reservoir through water injection and pushing or “sweeping” oil to producing wellbores. Based on the production estimates from our September 30, 2011 reserve report, the average estimated decline rate for our proved developed producing reserves is approximately 8.5% 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 September 30, 2011 and our average net production for the month ended September 30, 2011.
 
                                                                                 
          Average
                   
                            Net
                   
    Estimated
    Production
                   
    Net Proved Reserves
    for the Month Ended
                         
    as of September 30, 2011     September 30, 2011     Average
    Gross Active Wells        
                                        Reserve-to-
    Oil and
          Shut-in/
 
                      % Proved
    Boe/d
    Boe/d
    Production
    Natural
    Injection
    Waiting on
 
    (MBoe)     % Operated     % Oil     Developed     Gross     Net     Ratio(1)     Gas Wells     Wells     Completion  
 
Southern Oklahoma
    5,385       100 %     100 %     66 %     2,139       784       19       74       48       4  
Northeastern Oklahoma
    3,129       100 %     99 %     68 %     572       329       26       143       69       17  
Hugoton Basin
    1,045       100 %     100 %     75 %     263       160       18       42       17       0  
Other
    349       61 %     60 %     100 %     222       70       14       13       5       0  
                                                                                 
Total
    9,908       99 %     98 %     69 %     3,196       1,343       20       272       139       21  
                                                                                 
(1)  The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of September 30, 2011 by average net production for the month ended September 30, 2011.


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The following chart summarizes our pro forma total average net Boe production volumes on a monthly basis, and illustrates the 100% increase in our production volumes over the twelve months ended September 30, 2011. We achieved approximately 75% of this production increase primarily through ongoing waterflood response from existing development activities and approximately 25% of this production increase from workovers and acquisitions.
 
GRAPH
 
Our Hedging Strategy
 
Our hedging strategy seeks to reduce the impact to our cash flow from commodity price volatility. We intend to enter into commodity derivative contracts at times and on terms designed to maintain, over the long-term, a portfolio covering approximately 50% to 80% of our estimated oil production from proved reserves over a three-to-five year period at any given point in time. For the years ending December 31, 2011, 2012 and 2013, we have commodity derivative contracts covering approximately 37%, 53% and 30%, respectively, of our estimated oil production from proved reserves as of September 30, 2011. All of our derivative contracts for 2012 and 2013 are either swaps with fixed settlements or collars. The weighted average minimum prices on all of our derivative contracts for 2012 and 2013 are $101.18 and $100.14, 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 2012, we have collars with a floor of $100.00 and swaps with fixed price settlements ranging from $100.97 to $104.28 covering approximately 11% and 42%, respectively, of our total proved estimated oil production. In 2013, we have collars with a floor of $100.00 and swaps with fixed price settlements ranging from $96.00 to $105.80 covering 9% and 21%, respectively, of our total proved estimated oil production.
 
We intend to enter into additional commodity derivative contracts in connection with material increases in our estimated production and at times when we believe market conditions or other circumstances suggest that it is prudent to do so as opposed to entering into commodity


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derivative contracts at predetermined times or on prescribed terms. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes or the duration of our hedge contracts when circumstances suggest that it is prudent to do so.
 
By removing a significant portion of price volatility associated with our estimated future oil production, we have mitigated, but not eliminated, the potential effects of changing oil prices on our cash flow from operations for those periods. For a further description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”
 
Our Business Strategies
 
Our primary business objective is to generate stable cash flow, which will allow us to make quarterly cash distributions to our unitholders at the initial quarterly distribution rate and, over time, to increase our quarterly cash distributions. To achieve our objective, we intend to execute the following business strategies:
 
  •  Continue exploitation of our existing properties to maximize production;
 
  •  Pursue acquisitions of long-lived, low-risk producing properties with upside potential;
 
  •  Capitalize on our relationship with the Mid-Con Affiliates for favorable acquisition opportunities;
 
  •  Maintain operational control and a focus on cost-effectiveness in all our operations;
 
  •  Reduce the impact of commodity price volatility on our cash flow through a disciplined commodity hedging strategy;
 
  •  Maintain a balanced capital structure to allow for financial flexibility to execute our business strategies; and
 
  •  Utilize compensation programs that align the interests of our management team with our unitholders.
 
For a more detailed description of our business strategies, please read “Business and Properties—Our Business Strategies.”
 
Our Competitive Strengths
 
We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:
 
  •  An asset portfolio largely consisting of properties with existing waterflood projects that have relatively predictable production profiles, that provide growth potential through ongoing response to waterflooding and that have modest capital requirements;
 
  •  The ability to further exploit existing mature properties by utilizing our waterflooding expertise;
 
  •  Acquisition opportunities that are consistent with our criteria of predictable production profiles with upside potential that may arise as a result of our relationship with the Mid-Con Affiliates;
 
  •  Access to the collective expertise of Yorktown’s employees and their extensive network of industry relationships through our relationship with Yorktown;
 
  •  The ability to better manage our operating costs, capital expenditures and development schedule because of our high level of operational control;


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  •  An enhanced ability to pursue acquisition opportunities arising from our competitive cost of capital and balanced capital structure; and
 
  •  The range and depth of our technical and operational expertise will allow us to expand both geographically and operationally to achieve our goals.
 
For a more detailed discussion of our competitive strengths, please read “Business and Properties—Our Competitive Strengths.”
 
Our Principal Business Relationships
 
Our Relationship with the Mid-Con Affiliates
 
In June 2011, management and Yorktown formed two limited liability companies, which we refer to collectively as the Mid-Con Affiliates, to acquire and develop oil and natural gas properties that are either undeveloped or that may require significant capital investment and development efforts before they meet our criteria for ownership. As these development projects mature, we expect to have the opportunity to acquire certain of these properties from the Mid-Con Affiliates. Through this relationship with the Mid-Con Affiliates, we plan to avoid much of the capital, engineering and geological risks associated with the early development of any of these properties we may acquire. However, the Mid-Con Affiliates may not be successful in indentifying or consummating acquisitions or in successfully developing the new properties they acquire. Further, the Mid-Con Affiliates are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Please read “Certain Relationships and Related Party Transactions—Review, Approval or Ratification of Transactions with Related Persons.”
 
Our Relationship with Yorktown
 
We have a valuable relationship with Yorktown, a private investment firm founded in 1991 and focused on investments in the energy sector. Since 2004, Yorktown has made several equity investments in our predecessor. Immediately following the consummation of this offering, Yorktown will own an approximate 49.9% limited partner interest in us, making it our largest unitholder, and will own a 50% interest in our affiliate Mid-Con Energy Operating. Also, Peter A. Leidel, a principal of Yorktown, will serve on our board of directors.
 
Yorktown currently has more than $3.0 billion in assets under management and Yorktown’s employees have extensive investment experience in the oil and natural gas industry. Yorktown’s employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Yorktown owns interests. With their extensive investment experience in the oil and natural gas industry and their extensive network of industry relationships, we believe that Yorktown’s employees are well positioned to assist us in identifying and evaluating acquisition opportunities and in making strategic decisions. Yorktown is not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Investment funds managed by Yorktown manage numerous other portfolio companies that are engaged in the oil and natural gas industry and, as a result, Yorktown may present acquisition opportunities to other Yorktown portfolio companies that compete with us.
 
Risk Factors
 
An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under “Risk Factors.”


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Risks Related to Our Business
 
  •  We may not have sufficient cash to pay the initial quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.
 
  •  We would not have generated sufficient available cash on a pro forma basis to have paid the initial quarterly distribution on all of our units for the twelve months ended September 30, 2011.
 
  •  Unless we replace the oil reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders at the initial quarterly distribution rate.
 
  •  A decline in oil prices, or an increase in the differential between the NYMEX or other benchmark prices of oil and the wellhead price we receive for our production, will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.
 
  •  We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders at the initial quarterly distribution rate.
 
Risks Inherent in an Investment in Us
 
  •  Our general partner controls us, and the Founders and Yorktown own a 57.4% interest in us. They will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.
 
  •  Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage and operate our business. The management team of Mid-Con Energy Operating, which includes the individuals who will manage us, will also provide substantially similar services to the Mid-Con Affiliates, and thus will not be solely focused on our business.
 
  •  Units held by persons who our general partner determines are not eligible holders will be subject to redemption.
 
  •  Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors, which could reduce the price at which our common units will trade.
 
  •  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 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.


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Formation Transactions and Partnership Structure
 
The following transactions, which we refer to as the formation transactions, will occur at, or immediately prior to, the closing of this offering:
 
  •  We will acquire working interests from J&A Oil Company and Charles R. Olmstead and interests in derivative contracts from J&A Oil Company for aggregate consideration of approximately $6.0 million immediately prior to the closing of this offering;
 
  •  We will enter into a contribution, conveyance, assumption and merger agreement pursuant to which Mid-Con Energy I, LLC and Mid-Con Energy II, LLC will merge with and into our wholly owned subsidiary, Mid-Con Energy Properties and our general partner will make a contribution to us;
 
  •  We will enter into a new $250.0 million credit facility under which we expect to borrow approximately $45.0 million at the closing of this offering;
 
  •  We will issue 5,400,000 common units to the public, representing a 30.0% limited partner interest in us;
 
  •  We will issue 12,240,000 common units to the Contributing Parties as additional consideration for the merger;
 
  •  We will issue 360,000 general partner units to our general partner, representing a 2.0% general partner interest in us, in consideration for its contribution to us;
 
  •  We will repay in full the outstanding borrowings under our existing credit facility and distribute approximately $121.2 million to the Contributing Parties as the cash portion of the consideration in respect of the merger discussed in the second bullet above; and
 
  •  We will enter into a services agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us.
 
The number of common units that we will issue to the public and the Contributing Parties, as reflected in the fourth and fifth bullet points above, assume that the underwriters do not exercise their option to purchase up to an additional 810,000 common units. To the extent the underwriters exercise this option, the number of common units issued to the public (as reflected in the fourth bullet above) will increase by the aggregate number of common units purchased by the underwriters pursuant to such exercise, and the number of common units issued to the Contributing Parties (as reflected in the fifth bullet above) will decrease by the aggregate number of common units purchased by the underwriters pursuant to such exercise.


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Ownership and Organizational Structure of Mid-Con Energy Partners, LP
 
The diagram below depicts our organization and ownership after giving effect to the offering and the related formation transactions and assumes that the underwriters do not exercise their option to purchase additional common units.
 
         
Common units held by the public
    30.0 %
Common units held by the Contributing Parties:
       
Common units held by the Founders
    7.5 %
Common units held by Yorktown
    49.9 %
Common units held by the other Contributing Parties
    10.6 %
General partner units
    2.0 %
         
Total
    100.0 %
         
 
 
(1) The additional Contributing Parties (other than the Founders and Yorktown) are not reflected in the chart above. Certain of such additional Contributing Parties also hold membership interests in the Mid-Con Affiliates.
 
(2) The Founders are S. Craig George, Charles R. Olmstead and Jeffrey R. Olmstead.
 
(3) 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. 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 will not be entitled to elect our general partner or its directors or otherwise participate in our management or operation. All of the executive officers of our general partner are also officers and/or directors of the Mid-Con Affiliates. For information about the executive officers and directors of our general partner, please read “Management.”
 
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


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partner, or collectively, the “Founders,” will 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 will control our general partner, will be entitled to appoint its entire board of directors and will receive all of the distributions our general partner receives in respect of its 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. In connection with the closing of this offering, we and our general partner will enter into a services agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will provide management, administrative and 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 will initially have one subsidiary, Mid-Con Energy Properties, that will hold title to our properties.
 
Principal Executive Offices and Internet Address
 
Our headquarters are located 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 (918) 743-7575. Our website address is www.midconenergypartners.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.
 
Summary of Conflicts of Interest and Fiduciary Duties
 
Under our partnership agreement, our general partner has a legal duty to manage us in a manner that is in, or not opposed to, the best interests of the holders of our common 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 will have economic interests in the Mid-Con Affiliates. In addition, Peter A. Leidel, a principal of Yorktown, will serve on our board of directors. Mr. Leidel has economic interests in Yorktown and its affiliates that manage, hold and own investments in other funds and companies that may compete with us. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its owners and affiliates, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flow necessary to make cash distributions to our unitholders, including determinations related to:
 
  •  purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that may also be suitable for the Mid-Con Affiliates, Yorktown or any Yorktown portfolio company;
 
  •  the manner in which our business is operated;
 
  •  the level of our borrowings;
 
  •  the amount, nature and timing of our capital expenditures; and


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  •  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.”
 
Our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including any common units held by affiliates of our general partner). Upon consummation of 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 58.6% of our outstanding common units. Assuming that we do not issue any additional common units and the Founders and Yorktown do not transfer their units, they will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholders. Please see “Risk Factors—Risks Inherent in an Investment in Us” and “The Partnership Agreement—Amendment of the Partnership Agreement.”
 
Partnership Agreement Modification of Fiduciary Duties
 
Our partnership agreement limits the liability of our general partner and reduces the fiduciary duties it owes to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of the fiduciary duties that our general partner owes to our unitholders. By purchasing a common unit, our unitholders agree to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, are treated as having consented to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.


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The Offering
 
Common units offered by us 5,400,000 common units, or 6,210,000 common units if the underwriters exercise in full their option to purchase additional common units.
 
Units outstanding after this offering 17,640,000 common units.
 
If the underwriters do not exercise their option to purchase additional common units, we will issue that number of units to the Contributing Parties at the expiration of the option period as additional consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into Mid-Con Energy Properties at closing. To the extent the underwriters exercise their option to purchase up to an additional 810,000 common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder of the common units that are subject to the option, if any, will be issued to the Contributing Parties. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the initial quarterly distribution on all outstanding units.
 
In addition, our general partner will own general partner units representing a 2.0% general partner interest in us.
 
Use of proceeds We intend to use the expected net proceeds of approximately $97.4 million from this offering, based upon the assumed initial public offering price of $20.00 per common unit, after deducting underwriting discounts, a structuring fee and estimated expenses, together with borrowings of approximately $45.0 million under our new revolving credit facility, to:
 
•   distribute approximately $121.2 million to the Contributing Parties as the cash portion of the consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing;
 
•   repay in full $15.2 million of indebtedness outstanding under our existing revolving credit facilities; and
 
•   acquire, for aggregate consideration of approximately $6.0 million, certain working interests in the Cushing Field from J&A Oil Company and Charles R. Olmstead and interests in certain derivative contracts from J&A Oil Company.
 
After the uses described above, we do not expect that any of the net proceeds of the offering will be available for investment in our business.
 
If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $15.1 million. The net proceeds from any exercise of such option will be used to distribute


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additional cash consideration in respect of the merger to the Contributing Parties. Please read “Use of Proceeds.”
 
Cash distributions We intend to pay an initial quarterly distribution of $0.475 per unit per quarter on all common and general partner units ($1.90 per unit on an annualized basis) to the extent we have sufficient cash from operations, after the establishment of cash reserves and the payment of fees and expenses.
 
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 initial quarterly distribution rate or at any other rate except as provided in our partnership agreement. Further, our ability to pay the initial quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will prorate the initial quarterly distribution payable for the period from the closing of this offering through December 31, 2011, based on the actual length of that period.
 
Assuming our general partner maintains its 2.0% general partner interest in us, our partnership agreement requires that we distribute 98.0% of our available cash each quarter to the holders of our common units, pro rata, and 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.
 
Pro forma cash available for distribution generated during the year ended December 31, 2010 and the twelve months ended September 30, 2011 was approximately $5.4 million and $15.8 million, respectively. The amount of available cash we will need to pay the initial quarterly distribution for four quarters on our common units outstanding immediately after this offering and the corresponding distributions on our general partner’s 2.0% interest will be approximately $34.2 million (or an average of approximately $8.6 million per quarter). As a result, for the year ended December 31, 2010, we would have generated available cash sufficient to pay a cash distribution of $0.075 per unit per quarter ($0.30 on an annualized basis), or approximately 15.8% of the initial quarterly distribution on our common units during that period. For the twelve months ended September 30, 2011, we would have generated available cash sufficient to pay a cash distribution of $0.219 per unit per quarter ($0.878 on an annualized basis), or approximately 46.3% of the initial quarterly distribution on our common units during that period. For a calculation of our ability to pay distributions to our unitholders based on our pro forma results for the year ended December 31, 2010 and the twelve months ended September 30, 2011, please read “Our Cash Distribution Policy and Restrictions


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on Distributions—Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended September 30, 2011.”
 
We believe, based on our financial forecast and the related assumptions included under “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA for the Year Ending December 31, 2012,” that we will have sufficient cash available for distribution to pay the initial quarterly distribution of $0.475 per unit on all common and general partner units for the four quarters ending December 31, 2012.
 
Issuance of additional units We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”
 
Limited voting rights Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates. Upon consummation of this offering, the Founders and Yorktown will own an aggregate of approximately 58.6% of our common units and, therefore, will be able to prevent the removal of our general partner. Please read “The Partnership Agreement—Limited Voting Rights.”
 
Limited call right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon consummation of this offering, the Founders will own an aggregate of approximately 7.7% of our common units. Please read “The Partnership Agreement—Limited Call Right.”


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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 40% of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for the basis of this estimate.
 
Material tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”
 
Listing and trading symbol We have been approved to list our common units on the NASDAQ Global Market under the symbol “MCEP.”


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Summary Historical and Pro Forma Financial Data
 
We were formed in July 2011 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor, which consist of the consolidated historical financial statements of Mid-Con Energy Corporation through June 30, 2009 and the combined historical financial statements of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, thereafter. The following table presents summary historical financial data of our predecessor and summary pro forma financial data of Mid-Con Energy Partners, LP as of the dates and for the periods indicated. The summary historical financial data as of December 31, 2009 and 2010 and for the years ended June 30, 2008 and 2009, the six months ended December 31, 2009 and the year ended December 31, 2010 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data as of September 30, 2011 and for the nine months ended September 30, 2010 and 2011 are derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus. These historical financial statements have been restated to correct errors discovered in the calculation of depreciation, depletion, and amortization and impairment of proved properties for all periods prior to September 30, 2011, as well as the expensing of certain geological and geophysical costs by Mid-Con Energy I, LLC for the six months ended December 31, 2009.
 
The summary unaudited pro forma financial data as of September 30, 2011 and for the nine months ended September 30, 2011 and the year ended December 31, 2010 are derived from the unaudited pro forma condensed financial statements of our predecessor included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:
  •  the sale by Mid-Con Energy I, LLC and Mid-Con Energy II, LLC of certain oil and natural gas properties representing 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;
  •  the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC with our wholly owned subsidiary in exchange for aggregate consideration of 12,240,000 common units and $121.2 million in cash;
  •  the issuance to our general partner of 360,000 general partner units, representing a 2.0% general partner interest in us in exchange for a contribution from our general partner;
  •  the issuance and sale by us to the public of 5,400,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds;”
  •  our borrowing of approximately $45.0 million under our new credit facility and the application of the proceeds as described in “Use of Proceeds;” and
  •  our acquisition of additional working interests in the Cushing Field from J&A Oil Company and Charles R. Olmstead immediately prior to the closing of this offering.
 
The unaudited pro forma balance sheet data assume the events listed above occurred as of September 30, 2011. The unaudited pro forma statement of operations data for the nine months ended September 30, 2011 and the year ended December 31, 2010 assume the items listed above occurred as of January 1, 2010. We have not given pro forma effect to incremental general and administrative expenses of approximately $3.0 million that we expect to incur annually as a result of being a publicly traded partnership.
 
You should read the following table in conjunction with “—Formation Transactions and Partnership Structure,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of our predecessor and the unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP and the notes thereto included elsewhere in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information.


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The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.
 
                                                                   
                                          Mid-Con Energy
 
                                          Partners, LP  
                  Mid-Con Energy I, LLC and Mid-Con Energy II, LLC (combined)     Pro Forma  
    Mid-Con Energy Corporation
      Six Months
                      Year
    Nine Months
 
    (consolidated)       Ended
    Year Ended
    Nine Months Ended
    Ended
    Ended
 
    Year Ended June 30,       December 31,
    December 31,
    September 30,     December 31,     September 30,  
Statement of Operations Data:
  2008     2009       2009     2010     2010     2011     2010     2011  
                              (unaudited)     (unaudited)     (unaudited)     (unaudited)  
    (in thousands)  
    (restated)     (restated)       (restated)     (restated)                 (restated)        
Revenues:
                                                                 
Oil sales
  $ 13,667     $ 10,246       $ 5,729     $ 16,853     $ 11,390     $ 25,068     $ 16,286     $ 25,040  
Natural gas sales
    618       2,172         743       1,418       1,104       974       1,397       978  
Realized loss on derivatives, net
    (804 )     (669 )       (350 )     (90 )     (87 )     (799 )     (100 )     (875 )
Unrealized gain (loss) on derivatives, net
    (2,035 )     1,679         (147 )     (707 )     182       9,400       (707 )     9,400  
                                                                   
Total revenues
    11,446       13,428         5,975       17,474       12,589       34,643       16,876       34,543  
                                                                   
Operating costs and expenses:
                                                                 
Lease operating expenses
    5,005       5,369         2,431       6,237       4,654       5,951       5,041       5,600  
Oil and gas production taxes
    946       631         269       822       522       1,116       797       1,119  
Dry holes and abandonments of unproved properties
                        1,418       1,053       772       514       772  
Geological and geophysical
    1,296       507               394       253       171              
Depreciation, depletion and amortization
    1,599       2,293         2,552       5,851       4,743       4,318       3,327       4,128  
Accretion of discount on asset retirement obligations
    56       78         58       127       95       55       63       55  
General and administrative
    1,871       1,767         704       982       708       552       982       552  
Impairment of proved oil and gas properties
                  9,208       1,886                   1,260        
                                                                   
Total operating costs and expenses
    10,773       10,645         15,222       17,717       12,028       12,935       11,984       12,226  
                                                                   
Income (loss) from operations
    673       2,783         (9,247 )     (243 )     561       21,708       4,892       22,317  
                                                                   
Other income (expenses):
                                                                 
Interest income and other
    115       119         35       218       208       160       126       102  
Interest expense
    (3 )     (93 )       (2 )     (98 )     (59 )     (378 )     (1,350 )     (1,013 )
Gain on sale of assets
                        354       354       1,559              
Stock-based compensation
                                    (1,671 )           (1,671 )
Other revenue and expenses, net
    108       298         118       847       501       576              
Income tax expense—current
          (625 )                                      
Income tax (expense) benefit—deferred
    (261 )     502                                        
                                                                   
Net income (loss)
  $ 632     $ 2,984       $ (9,096 )   $ 1,078     $ 1,565     $ 21,954     $ 3,668     $ 19,735  
                                                                   
Net income per limited partner unit (basic and diluted)
                                                    $ 0.20     $ 1.10  
                                                                   
Weighted average number of limited partner units outstanding (basic and diluted)
                                                      17,640       17,640  
                                                                   
Other Financial Data:
                                                                 
Adjusted EBITDA
  $ 4,471     $ 3,773       $ 2,836     $ 10,593     $ 6,771     $ 18,029     $ 10,763     $ 17,872  
Cash Flow Data:
                                                                 
Net cash provided by (used in):
                                                                 
Operating activities
  $ 4,221     $ 10,935       $ 965     $ 11,798     $ 10,269     $ 14,554                  
Investing activities
    (7,646 )     (12,448 )       (5,018 )     (22,726 )     (15,922 )     (24,881 )                
Financing activities
    147       4,841         (1,164 )     10,387       5,133       10,291                  
                                                                   
                                                                   
                  Mid-Con Energy I, LLC and
          Mid-Con
 
                  Mid-Con Energy II, LLC
          Energy Partners, LP
 
                  (combined)           Pro Forma  
                  As of December 31,           As of September 30,
          As of September 30,
 
Balance Sheet Data:
                2009     2010           2011           2011  
                                    (unaudited)           (unaudited)  
                  (in thousands)  
                  (restated)     (restated)                          
Working capital(1)
    $ 2,420     $ (1,256 )                    $ 6,819             $ 5,236  
Total assets
      40,496       56,867               88,682               92,377  
Total debt
      337       5,513               15,210               45,000  
Partners’ capital
      36,779       43,072               69,955               43,860  
 
 
(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.


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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;
 
  •  stock-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.


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Reconciliation of Adjusted EBITDA to Net Income
 
                                                                   
                  Mid-Con Energy I, LLC and
    Mid-Con Energy
 
                  Mid-Con Energy II, LLC
    Partners, LP
 
    Mid-Con Energy
      (combined)     Pro Forma  
    Corporation
      Six Months
    Year
    Nine Months
    Nine Months
    Year
    Nine Months
 
    (consolidated)       Ended
    Ended
    Ended
    Ended
    Ended
    Ended
 
    Year Ended June 30,       December 31,
    December 31,
    September 30,
    September 30,
    December 31,
    September 30,
 
    2008     2009       2009     2010     2010     2011     2010     2011  
                              (unaudited)     (unaudited)     (unaudited)     (unaudited)  
    (in thousands)  
    (restated)     (restated)       (restated)     (restated)                 (restated)        
                                                                   
Net income (loss)
  $ 632     $ 2,984       $ (9,096 )   $ 1,078     $ 1,565     $ 21,954     $ 3,668     $ 19,735  
                                                                   
Income tax expense (benefit)—deferred
    261       (502 )                                      
                                                                   
Income tax expense—current
          625                                        
                                                                   
Interest expense
    3       93         2       98       59       378       1,350       1,013  
                                                                   
Depreciation, depletion and amortization
    1,599       2,293         2,552       5,851       4,743       4,318       3,327       4,128  
                                                                   
Accretion of discount on asset retirement obligations
    56       78         58       127       95       55       63       55  
                                                                   
Unrealized (gain) loss on derivatives, net
    2,035       (1,679 )       147       707       (182 )     (9,400 )     707       (9,400 )
                                                                   
Impairment of proved oil and gas properties
                  9,208       1,886                   1,260        
                                                                   
Dry holes and abandonments of unproved properties
                        1,418       1,053       772       514       772  
                                                                   
Gain on sales of assets
                        (354 )     (354 )     (1,559 )            
                                                                   
Stock-based compensation
                                    1,671             1,671  
                                                                   
Interest income
    (115 )     (119 )       (35 )     (218 )     (208 )     (160 )     (126 )     (102 )
                                                                   
                                                                   
Adjusted EBITDA
  $ 4,471     $ 3,773       $ 2,836     $ 10,593     $ 6,771     $ 18,029     $ 10,763     $ 17,872  
                                                                   
                                                                   
                                                                   
 
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
                                                                   
                                                                   
                                                                   
                                                                   
                  Mid-Con Energy I, LLC and
             
    Mid-Con
      Mid-Con Energy II, LLC
             
    Energy
      (combined)              
    Corporation
      Six Months
    Year
    Nine Months
    Nine Months
             
    (consolidated)       Ended
    Ended
    Ended
    Ended
             
    Year Ended June 30,       December 31,
    December 31,
    September 30,
    September 30,
             
    2008     2009       2009     2010     2010     2011              
                              (unaudited)     (unaudited)              
    (in thousands)  
    (restated)     (restated)       (restated)     (restated)                          
                                                                   
Net cash provided by operating activities
  $ 4,221     $ 10,935       $ 965     $ 11,798     $ 10,269     $ 14,554                  
                                                                   
Change in working capital
    521       (7,761 )       1,904       (1,085 )     (3,349 )     3,257                  
                                                                   
Income tax expense—current
          625                                            
                                                                   
Bad debt expense
    (159 )                                                
                                                                   
Interest expense
    3       93         2       98       59       378                  
                                                                   
Interest income
    (115 )     (119 )       (35 )     (218 )     (208 )     (160 )                
                                                                   
                                                                   
Adjusted EBITDA
  $ 4,471     $ 3,773       $ 2,836     $ 10,593     $ 6,771     $ 18,029                  
                                                                   


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Summary Pro Forma and Historical Reserve and Operating Data
 
The following table presents summary data with respect to the estimated net proved oil and natural gas reserves that we will own at the closing of this offering and the standardized measure amounts associated with those estimated proved reserves as of December 31, 2010 and as of September 30, 2011, both based on reserve reports prepared by our internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc., our independent reserve engineers. Our estimated proved reserves as of December 31, 2010 are presented on a pro forma basis and exclude certain properties of our predecessor that were sold to the Mid-Con Affiliates on June 30, 2011. The properties we sold represented less than 1% of our proved reserves by value, as calculated using the standardized measure, as of September 30, 2011.
 
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 September 30, 2011 our proved reserves increased by approximately 2.8 MMBoe, or 39%. Total proved reserves increased by approximately 1.0 MMBoe from acquisitions in the Hugoton Basin and Northeastern Oklahoma core areas; 0.7 MMBoe from waterflood expansion in the Northeastern Oklahoma core area; 0.5 MMBoe from infill drilling in Northeastern and Southern Oklahoma core areas; 0.5 MMBoe from workovers in Northeastern Oklahoma and the Hugoton Basin core areas and 0.1 MMBoe in net performance revisions for all of our properties. We spent a total of $19.3 million and $31.2 million in capital expenditures for the year ended December 31, 2010 and the nine months ended September 30, 2011, respectively, which contributed to the increase in our September 30, 2011 proved reserves.
 
From December 31, 2010 to September 30, 2011 our proved developed reserves increased by approximately 3.1 MMBoe, or 83%. Proved developed reserves increased in our Southern Oklahoma core area by 1.0 MMBoe from development drilling and 0.4 MMBoe from better than expected production responses to waterflooding, which exceeded our December 31, 2010 estimates; in the Hugoton Basin by 0.5 MMBoe from the acquisition of the War Party I and II Units and by 0.2 MMBoe from workovers performed on those properties after acquisition; and in our Northeastern Oklahoma core area by 0.3 MMBoe from acquisitions, 0.1 MMBoe from infill drilling, 0.1 MMBoe from expansion of waterflood operations, 0.3 MMBoe from workovers and 0.1 MMBoe in net performance revisions on our other properties.
 
During the nine months ended September 30, 2011, we spent approximately $16.4 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 1.0 MMBoe increase in proved developed reserves in our Southern Oklahoma core area discussed in the prior paragraph. Additionally, we spent approximately $9.4 million during the nine months ended September 30, 2011 to acquire new leases in the Hugoton Basin and Northeastern Oklahoma. We spent another $0.7 million on workover activities and $0.6 million on drilling during the nine months ended September 30, 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


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pro forma reserve reports dated December 31, 2010 and September 30, 2011 included in this prospectus in evaluating the material presented below.
 
                 
    Pro Forma as of
    Pro Forma as of
 
    December 31,
    September 30,
 
    2010(1)     2011(2)  
 
Reserve Data:
               
Estimated proved reserves:
               
Oil (MBbl)
    6,938       9,730  
Natural Gas (MMcf)
    1,070       1,069  
                 
Total (Mboe)
    7,116       9,908  
                 
Proved developed (MBoe)
    3,710       6,801  
Oil (MBbl)
    3,531       6,619  
Natural Gas (MMcf)
    1,082       1,093  
Proved undeveloped (MBoe)
    3,406       3,107  
Oil (MBbl)
    3,407       3,111  
Natural Gas (MMcf)
    (12 )     (24 )
Proved developed reserves as a percentage of total proved reserves
    52.1 %     68.6 %
Standardized Measure (in millions)(3)
  $ 182.1     $ 312.0  
Oil and Natural Gas Prices(4):
               
Oil — NYMEX — WTI per Bbl
  $ 79.43     $ 94.50  
Natural gas — NYMEX — Henry Hub per MMBtu
  $ 4.37     $ 4.17  
 
(1) Excludes certain properties, which represented less than 1% of our proved reserves by value, as calculated using the standardized measure, as of September 30, 2011, that were sold to the Mid-Con Affiliates on June 30, 2011.
 
(2) Includes the working interests to be acquired from J&A Oil Company and Charles R. Olmstead immediately prior to the closing of this offering.
 
(3) Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas. Because we were not subject to federal or state income taxes for the periods presented, we make no provision for federal or state income taxes in the calculation of our standardized measure. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Contracts.”
 
(4) 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 $94.50 per Bbl for oil and $4.17 per MMBtu for natural gas at September 30, 2011. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For the year ended December 31, 2010, the relevant average realized prices for oil and natural gas were $74.15 per Bbl and $7.58 per Mcf, respectively, on a pro forma basis. For the nine months ended September 30, 2011, the relevant average realized prices for oil and natural gas were $90.22 per Bbl and $7.83 per Mcf, respectively, on a pro forma basis. Realized natural gas sales price per Mcf includes the sale of natural gas liquids for both the year ended December 31, 2010 and the nine months ended September 30, 2011.
 


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    Pro Forma(1)
        Nine Months
    Year Ended
  Ended
    December 31,
  September 30,
    2010   2011
    (restated)    
 
Production and operating data:
               
Net production volumes:
               
Oil (MBbls)
    220       278  
Natural gas (MMcf)
    184       125  
Total (MBoe)
    250       298  
Average net production (Boe/d)
    686       1,093  
Average sales price:(2)
               
Oil (per Bbl)
  $ 74.15     $ 90.22  
Natural gas (per Mcf)(3)
  $ 7.58     $ 7.83  
Average price per Boe
  $ 70.64     $ 87.20  
Average unit costs per Boe:
               
Oil and natural gas production expenses
  $ 20.14     $ 18.77  
Production taxes
  $ 3.18     $ 3.75  
General and administrative and other(4)
  $ 3.92     $ 1.85  
Depreciation, depletion and amortization
  $ 13.29     $ 13.84  
 
(1) Excludes production from certain properties, which represent less than 1% of our proved reserves by value, as calculated using the standardized measure, as of September 30, 2011, that were sold to the Mid-Con Affiliates on June 30, 2011.
 
(2) Prices do not include the effects of derivative cash settlements.
 
(3) Realized natural gas sales price per Mcf includes the sale of natural gas liquids.
 
(4) Pro forma general and administrative expenses do not include the additional expenses we would have incurred as a publicly traded partnership. We estimate these additional expenses would have been $3.0 million, or $11.99 per Boe, for the year ended December 31, 2010 and $2.3 million, or $7.72 per Boe, for the nine months ended September 30, 2011 on a pro forma basis.

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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 the initial quarterly distribution on our units following the establishment of cash reserves and payment of expenses, including payments to our general partner.
 
We may not have sufficient available cash each quarter to pay the initial quarterly distribution of $0.475 per unit (or $8.6 million in the aggregate), or any distribution at all, on our units. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development of our oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of cash that we distribute to our unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:
 
  •  the amount of oil and natural gas we produce;
 
  •  the prices at which we sell our oil and natural gas production;
 
  •  the amount and timing of settlements on our commodity derivative contracts;
 
  •  the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;
 
  •  the level of our operating costs, including payments to our general partner; and
 
  •  the level of our interest 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.
 
We would not have generated sufficient available cash on a pro forma basis to have paid the initial quarterly distribution on all of our units for the twelve months ended September 30, 2011.
 
On a pro forma historical basis, assuming we had completed our formation transactions on October 1, 2010, our unaudited pro forma available cash generated during the twelve months ended September 30, 2011 would have been approximately $15.8 million, which would have been sufficient to pay only 46.3% of the aggregate initial quarterly distribution on our common units. For a calculation of our ability to have made distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2010 and the twelve months ended September 30, 2011, please read “Our Cash Distribution Policy and Restrictions on


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Distributions—Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended September 30, 2011.”
 
The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results.
 
Our management’s forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2012. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted. If our actual results are significantly below forecasted results, we may not generate enough cash available for distribution to pay the initial quarterly distribution, or any distribution at all, on our common units, which may cause the market price of our common units to decline materially. For prospective financial information regarding our ability to pay the initial quarterly distribution on our common units and general partner units for the twelve months ending December 31, 2012, please read “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA for the Year Ending December 31, 2012.”
 
Unless we replace the oil reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders at the initial quarterly distribution rate.
 
We may be unable to sustain the initial quarterly distribution rate without substantial capital expenditures that maintain our asset base. Producing oil reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil reserves and production and, therefore, our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.
 
Our operations may require substantial capital expenditures, which could reduce our cash available for distribution and could materially affect our ability to make distributions to our unitholders.
 
We may be required to make substantial capital expenditures from time to time in connection with the production of our oil reserves. Further, if the borrowing base under our new credit facility or our revenues decrease as a result of lower oil prices, declines in estimated reserves or production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at the expected levels so as to generate an amount of cash necessary to make distributions to our unitholders.
 
Developing and producing oil is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
 
The cost of developing and operating oil properties, particularly under a waterflood, is often uncertain, and cost and timing factors can adversely affect the economics of a well. Our efforts may be uneconomical if our properties are productive but do not produce as much oil as we had


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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.


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A decline in oil prices, or an increase in the differential between the NYMEX or other benchmark prices of oil and the wellhead price we receive for our production, will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.
 
Lower oil prices may decrease our revenues and, therefore, our cash available for distribution to our unitholders. Historically, oil prices have been extremely volatile. For example, for the five years ended December 31, 2010, the NYMEX—WTI oil price ranged from a high of $145.29 per Bbl to a low of $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 expect to enter into commodity derivative contracts at times and on terms designed to maintain, over the long-term, a portfolio covering approximately 50% to 80% of our estimated oil production from proved reserves over a three-to-five year period at any given point of time, although we may from time to time hedge more or less than this approximate range. The prices at which we are able to enter into commodity derivative contracts covering our production in the future will be dependent upon oil prices at the time we enter into these transactions, which may be substantially higher or lower than current oil prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil prices received for our future production.
 
In addition, our new credit facility may hinder our ability to effectively execute our hedging strategy. To the extent our new credit facility limits the maximum percentage of our production that we can hedge or the duration of those hedges, we may be unable to enter into additional commodity derivative contracts during favorable market conditions and, thus, unable to lock in attractive future prices for our product sales. Conversely, while our new credit facility will not require us to hedge a minimum percentage of our production, it may cause us to enter into


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commodity derivative contracts at inopportune times. For example, during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our borrowing base upon a redetermination.
 
Our hedging activities could result in cash losses, could reduce our cash available for distribution and may limit the prices we would otherwise realize for our production.
 
Many of the derivative contracts that we will be a party to will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays), we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity and our cash available for distribution to our unitholders.
 
Our hedging transactions expose us to counterparty credit risk.
 
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
 
Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.
 
It is not possible to measure underground accumulations of oil in an exact way. Oil reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and assumptions concerning future oil prices, future production levels and operating and development costs.
 
As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove inaccurate. For example, if the prices used in our December 31, 2010 reserve reports had been $10.00 less per barrel for oil, the standardized measure of our estimated proved reserves, without asset retirement obligations, as of that date on a pro forma basis would have decreased by $33.3 million, from $183.2 million to $149.9 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


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significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
 
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
 
Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:
 
  •  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;
 
  •  unable to obtain financing for these acquisitions on economically acceptable terms; or
 
  •  outbid by competitors.
 
If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.
 
Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.
 
One of our growth strategies is to capitalize on opportunistic acquisitions of oil reserves. Even if we make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
 
  •  the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, operating expenses and costs;
 
  •  an inability to successfully integrate the assets we acquire;
 
  •  a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
 
  •  a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
 
  •  the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
 
  •  the diversion of management’s attention from other business concerns;
 
  •  an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and
 
  •  facts and circumstances that could give rise to significant cash and certain non-cash charges, such as the impairment of oil properties, goodwill or other intangible assets, asset devaluations or restructuring charges.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations.
 
Also, our reviews of properties acquired from third parties (as opposed to from the Mid-Con Affiliates) may be incomplete because it generally is not feasible to perform an in-depth review of


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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 76% of our total sales revenues for the year ended December 31, 2010 and approximately 87% of our total sales revenues for the nine months ended September 30, 2011. Our production is and will continue to be marketed by our affiliate, Mid-Con Energy Operating, under these crude oil purchase contracts. By selling a substantial majority of our current production to Sunoco Logistics under these contracts, we believe that we have obtained and will continue to receive more favorable pricing than would otherwise be available to us if smaller amounts had been sold to several purchasers based on posted prices. To the extent Sunoco Logistics or any other significant customer reduces the volume of oil they purchase from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our oil production, and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders at the then-current distribution rate or at all.
 
In addition, a failure by Sunoco Logistics or any of our other significant customers, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.
 
Unitization difficulties may prevent us from developing certain properties or greatly increase the cost of their development.
 
Regulation of waterflood unit formation is typically governed by state law. In Oklahoma, where most of our properties are located, 63% of the leasehold and mineral owners in a proposed unit area must consent to a unitization plan before the Oklahoma Corporation Commission (the regulatory body which oversees issues related to unitization and well spacing) will issue a unitization order. We may be required to dedicate significant amounts of time and financial resources to obtaining consents from other owners and the necessary approvals from the Oklahoma Corporation Commission and similar regulatory agencies in other states. Obtaining these consents and approvals may also delay our ability to begin developing our new waterflood projects and may prevent us from developing our properties in the way we desire.


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Other owners of mineral rights may object to our waterfloods.
 
It is difficult to predict the movement of the injection fluids that we use in connection with waterflooding. It is possible that certain of these fluids may migrate out of our areas of operations and into neighboring properties, including properties whose mineral rights owners have not consented to participate in our operations. This may result in litigation in which the owners of these neighboring properties may allege, among other things, a trespass and may seek monetary damages and possibly injunctive relief, which could delay or even permanently halt our development of certain of our oil properties.
 
We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders at the initial quarterly distribution rate.
 
The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ financial, technical and personnel resources substantially greater than ours. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.
 
Many of our leases are in areas that have been partially depleted or drained by offset wells.
 
Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining our interests could take actions, such as drilling additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.
 
We may incur additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to pay future distributions or execute our business plan.
 
We may be unable to pay distributions at our initial quarterly distribution rate or the then-current distribution rate without borrowing under our new credit facility. If we use borrowings under our new credit facility to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.


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Our new credit facility will have restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.
 
Our new credit facility will restrict, among other things, our ability to incur debt and pay distributions under certain circumstances, and will require us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our new credit facility that are not cured or waived within specific time periods, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our new credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our new credit facility, the lenders could seek to foreclose on our assets.
 
The total amount we will be able to borrow under our new credit facility will be limited by a borrowing base, which will be primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts, as determined by our lenders in their sole discretion. The borrowing base will be subject to redetermination on a semi-annual basis and more frequent redetermination in certain circumstances. Any substantial or sustained decline in commodity prices would likely lead to a decrease in our borrowing base upon redetermination. In the future, we may be unable to access sufficient capital under our new credit facility as a result of a decrease in our borrowing base due to a subsequent borrowing base redetermination.
 
In addition, our new credit facility may hinder our ability to effectively execute our hedging strategy. To the extent our new credit facility limits the maximum percentage of our production that we can hedge or the duration of those hedges, we may be unable to enter into additional commodity derivative contracts during favorable market conditions and, thus, unable to lock in attractive future prices for our product sales. Conversely, our new credit facility 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 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. 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 can also be affected by federal and state regulation of oil production and transportation, 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.


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Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
 
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA adopted two sets of regulations under the existing Clean Air Act requiring a reduction in emissions of GHGs from motor vehicles that became effective on January 2, 2011. The EPA also determined that a permit review for GHG emissions from certain stationary sources was triggered under the federal air permit programs. EPA adopted a tiered approach to implementing the permitting of GHG emissions from stationary sources in May 2010. The so-called “tailoring rule” only requires the stationary sources with the largest emissions to undergo an assessment of GHG emissions under the best available control technology under the federal permitting programs. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHGs emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published mandatory reporting rules for certain oil and gas facilities requiring reporting starting in 2012 for emissions in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
 
In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane, which are understood to contribute to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to emissions of GHGs. In addition, almost half of the states in the United States have begun to address GHG emissions, primarily through the planned development of GHG emission inventories or regional GHG cap and trade programs.
 
Any future laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs or reduce emissions of and could adversely affect demand for the oil that we produce. Please read “Business and Properties—Environmental Matters and Regulation.”
 
Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.
 
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil development and production activities. These costs and liabilities could arise under a wide range of federal, state, tribal and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. Claims for damages to persons or property from private parties and governmental authorities may result from environmental and other impacts of our operations.
 
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws,


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regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs.
 
We may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues. For example, on July 28, 2011, the EPA proposed four sets of new rules which, if adopted, will impose stringent new standards for air emissions from oil and natural gas development and production operations, including crude oil storage tanks with a throughput of at least 20 barrels per day, condensate storage tanks with a throughput of at least one barrel per day, completions of new hydraulically fractured natural gas wells, and recompletions of existing natural gas wells that are fractured or refractured. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by April 3, 2012. If adopted, these rules may require us to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. If we were not able to recover the resulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected.
 
In addition, we may be required to establish reserves against these liabilities. Although we believe we have established appropriate reserves for known liabilities, we could be required to set aside additional reserves in the future if additional liabilities arise, which could have an adverse effect on our operating results.
 
Please read “Business and Properties—Environmental Matters and Regulation” for more information.
 
The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.
 
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) establishes a new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted (commonly referred to as “margin”). The Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. Since the Act mandates the Commodities Futures Trading Commission (the “CFTC”) to promulgate rules to define these terms, we do not know the definitions the CFTC will actually adopt or how these definitions will apply to us. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalent. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict if and when the CFTC will finalize these regulations.
 
Although we currently do not, and do not anticipate that we will in the future, voluntarily enter into derivative transactions that require an initial deposit of cash collateral, depending on the rules and definitions ultimately adopted by the CFTC, we might in the future be required to post cash collateral for our commodities derivative transactions. Posting of cash collateral could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other partnership purposes. Also, if commodity prices move in a manner adverse to us, we may be required to meet margin calls. A requirement to post cash collateral could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flow. Although the CFTC has issued proposed rules under the Act, we are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as us are not required to post cash collateral for our derivative hedging contracts. In addition, even if we are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Act’s new


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requirements, and the costs of their compliance will likely be passed on to customers, including us, thus decreasing the benefits to us of hedging transactions and reducing the profitability of our cash flow.
 
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
 
The U.S. Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is a commonly used process in the completion of unconventional wells in shale formations, as well as tight conventional formations including many of those that we complete and produce. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level, and could make it easier for third parties to initiate legal proceedings based on allegations that chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil and surface water. In addition, the EPA has recently asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act’s Underground Injection Program and has begun the process of drafting guidance documents on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel fuel. Moreover, the EPA 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, a number of other federal agencies are also analyzing a variety of environmental issues associated with hydraulic fracturing and could potentially take regulatory actions that impair our ability to conduct hydraulic fracturing operations. Some states, including Texas, and various local governments have adopted, and others are considering, regulations to restrict and regulate hydraulic fracturing. Any additional level of regulation could lead to operational delays or increased operating costs which could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and would increase our costs of compliance and doing business, resulting in a decrease of cash available for distribution to our unitholders.
 
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 the Founders and Yorktown own a 57.4% interest in us. They will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.
 
Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, our general partner will be owned by the Founders. The Founders and Yorktown will own a 57.4% interest in us. 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


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interests and the interests of its affiliates over the interests of our common unitholders. These potential conflicts include, among others:
 
  •  Our partnership agreement limits our general partner’s liability, reduces its fiduciary duties and also restricts the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
 
  •  Neither our partnership agreement nor any other agreement requires the Mid-Con Affiliates and Yorktown or their respective affiliates (other than our general partner) to pursue a business strategy that favors us. The officers and directors of the Mid-Con Affiliates and Yorktown and their respective affiliates (other than our general partner) have a fiduciary duty to make these decisions in the best interests of their respective equity holders, which may be contrary to our interests;
 
  •  The Mid-Con Affiliates and Yorktown and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;
 
  •  All of the executive officers of our general partner who will provide services to us will also devote a significant amount of time to the Mid-Con Affiliates and will be compensated for those services rendered;
 
  •  Our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
 
  •  We will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us, and Mid-Con Energy Operating will also provide these services to the Mid-Con Affiliates;
 
  •  Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
 
  •  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •  Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
 
  •  Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;
 
  •  Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; 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.”


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Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage and operate our business. The management team of Mid-Con Energy Operating, which includes the individuals who will manage us, will also provide substantially similar services to the Mid-Con Affiliates, and thus will not be solely focused on our business.
 
Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage us and operate our assets. Upon the closing of this offering, we will enter into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will provide management, administrative and operational services to us.
 
Mid-Con Energy Operating will also continue to provide substantially similar services and personnel to the Mid-Con Affiliates and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Mid-Con Energy Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Mid-Con Affiliates or other affiliates of our general partner. There is no requirement that Mid-Con Energy Operating favor us over these other entities in providing its services. If the employees of Mid-Con Energy Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
 
We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
 
Prior to the completion of this offering, we were a private entity with limited accounting personnel and other supervisory resources to adequately execute our accounting processes and address our internal control over financial reporting. Subsequent to the review of the interim combined financial information as of June 30, 2011 and for the six month period then ended, our independent registered accounting firm identified and communicated material weaknesses related to ineffective internal controls to ensure that misstatements of more than a significant magnitude were detected during the routine financial statement closing process, which resulted in errors in the calculation of depreciation, depletion and amortization and impairment of proved oil and gas properties and in the recording of certain geological and geophysical costs. These errors caused us to make several adjustments to our financial statements, resulting in a restatement of many of our financial statements for the periods presented in this registration statement. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls over financial reporting such that there is a reasonable possibility that a material misstatement of our financial statements will not be prevented, or detected on a timely basis. A control deficiency exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis. In particular, our independent registered accounting firm informed us that our system of internal controls relied too heavily on one key individual in our accounting and financial reporting group to perform period-end calculations and to ensure the financial statements and disclosures were materially correct. Further, our independent registered accounting firm suggested that we develop a more formalized system of procedures performed by lower level accounting and reporting staff and implement controls to ensure that those procedures are operating as designed and that the data generated is accurate.
 
Our management recently hired additional accounting personnel and purchased new accounting software in an effort to enhance its internal controls over financial reporting.
 
While we have begun the process of evaluating the design and operation of our internal control over financial reporting, we are in the early phases of our review and will not complete


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our review until after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim combined financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.
 
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.
 
Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. If it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
 
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, initially we will not have any incentive distribution rights or subordinated units. Because we will have no subordinated units after this offering, our public unitholders will not be senior in payment of distributions at the initial quarterly distribution rate, or at any rate, over the Contributing Parties. In addition, if the amount of any


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future distribution is less than the initial 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 will trade.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by the Founders, as a result of their ownership of our general partner, and not by our unitholders. Please read “Management—Management of Mid-Con Energy Partners, LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.
 
The public unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner and Yorktown will own sufficient units upon


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completion of this offering to be able 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. Following consummation of this offering, the Founders and Yorktown will own approximately 58.6% of our outstanding 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 our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.
 
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.


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Once our common units are publicly traded, the Founders, Yorktown and the other Contributing Parties may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
 
After the sale of the common units offered hereby, the Founders, Yorktown and the other Contributing Parties will own 12,240,000 common units or approximately 69.4% of our limited partner interests. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
 
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
 
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
Please read “The Partnership Agreement—Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.
 
Our unitholders may have liability to repay distributions.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
 
Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may not be able to resell their common units at the initial public offering price.
 
Prior to this offering, there has been no public market for the common units. After this offering, there will be publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.


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If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.
 
The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
 
  •  changes in commodity prices;
 
  •  changes in securities analysts’ recommendations and their estimates of our financial performance;
 
  •  public reaction to our press releases, announcements and filings with the SEC;
 
  •  fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;
 
  •  changes in market valuations of similar companies;
 
  •  departures of key personnel;
 
  •  commencement of or involvement in litigation;
 
  •  variations in our quarterly results of operations or those of other oil and natural gas companies;
 
  •  variations in the amount of our quarterly cash distributions to our unitholders;
 
  •  future issuances and sales of our common units; and
 
  •  changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.
 
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
 
Our unitholders will experience immediate and substantial dilution of $17.56 per unit.
 
The assumed initial offering price of $20.00 per common unit exceeds our pro forma net tangible book value after this offering of $2.44 per common unit. Based on the assumed initial offering price of $20.00 per common unit, our unitholders will incur immediate and substantial dilution of $17.56 per common unit. This dilution will occur primarily because the assets contributed by affiliates of our general partner are recorded, in accordance with GAAP, at their historical cost, and not their fair value.
 
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and make acquisitions.
 
Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:
 
  •  general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;


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  •  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 new credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
 
Tax Risks to Unitholders
 
In addition to reading the following risk factors, prospective unitholders should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
 
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units.


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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.
 
Both the Obama Administration’s budget proposal for fiscal year 2012 and the proposed American Jobs Act of 2011 include potential legislation that would, if enacted, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.
 
If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.
 
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.


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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 IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
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


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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.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or


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own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in Oklahoma and Colorado, each of which currently imposes a personal income tax on individuals. These states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all 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.
 
Compliance with and changes in tax laws could adversely affect our performance.
 
We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.


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USE OF PROCEEDS
 
We intend to use the estimated net proceeds of approximately $97.4 million from this offering, based upon the assumed initial public offering price of $20.00 per common unit, after deducting underwriting discounts, a structuring fee and estimated offering expenses, together with borrowings of approximately $45.0 million under our new revolving credit facility, to:
 
  •  distribute approximately $121.2 million to the Contributing Parties as the cash portion of the consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing;
 
  •  repay in full $15.2 million of indebtedness outstanding under our existing credit facilities; and
 
  •  acquire, for aggregate consideration of approximately $6.0 million, certain working interests in the Cushing Field from J&A Oil Company and Charles R. Olmstead and interests in certain derivative contracts from J&A Oil Company.
 
After the uses described above, we do not expect that any of the net proceeds of the offering will be available for investment in our business.
 
As of September 30, 2011, the interest rate on our two existing credit facilities was 4% for each facility, and the credit facilities mature on December 31, 2013. Borrowings made under these facilities within the last twelve months were used for acquisitions and development activities.
 
The following table illustrates our use of proceeds from this offering and our borrowings under our new credit facility:
 
                     
Sources of Cash (in millions)     Uses of Cash (in millions)  
 
Gross proceeds from this offering(1)
  $ 108.0     Distribution to Contributing Parties(1)   $ 121.2  
Borrowings under our new credit facility
  $ 45.0     Repayment of indebtedness under our
  existing credit facilities
  $ 15.2  
            Acquisition of certain working interests in Cushing Field and derivative contracts   $ 6.0  
            Underwriting discounts, a structuring fee
  and estimated offering expenses
  payable by us
  $ 10.6  
Total
  $ 153.0     Total   $ 153.0  
                     
 
 
(1) If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $15.1 million, and the total distribution to the Contributing Parties would be approximately $136.3 million.
 
If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public. If the underwriters exercise their option to purchase 810,000 additional common units in full, the additional net proceeds would be approximately $15.1 million. The net proceeds from any exercise of such option will be used to distribute additional cash consideration to the Contributing Parties in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing. If the underwriters do not exercise their option to purchase 810,000 additional common units in full, we will issue the number of remaining common units to the Contributing Parties upon the expiration of the option (810,000 common units if the option is not exercised at all) as additional consideration in respect of the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at closing. We will not receive any additional consideration from the Contributing Parties in connection with such


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issuance. The exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the initial quarterly distribution on all units. Please read “Underwriting.”
 
A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, a structuring fee and estimated offering expenses payable by us, to increase or decrease, respectively, by approximately $5.0 million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $20.00 per common unit, would increase net proceeds to us from this offering by approximately $24.5 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $20.00 per common unit, would decrease the net proceeds to us from this offering by approximately $22.7 million.


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CAPITALIZATION
 
The following table shows:
 
  •  historical capitalization as of September 30, 2011; and
 
  •  our as adjusted capitalization as of September 30, 2011, which gives effect to the formation transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure” on and the application of the net proceeds from this offering as described under “Use of Proceeds.”
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please read our Unaudited Pro Forma Condensed Financial Statements.
 
                 
    As of September 30, 2011  
          Mid-Con
 
    Our
    Energy
 
    Predecessor
    Partners, LP
 
    Historical     As Adjusted  
    (in thousands)  
 
Cash and cash equivalents
  $ 186     $  
                 
Long-term debt
  $ 15,210     $ 45,000  
Members’/partners’ capital/net equity:
               
Predecessor members’ capital
  $ 69,955     $ 43,860  
Common units held by purchasers in this offering
          13,158  
Common units held by the Contributing Parties
          29,825  
General partner interest
          877  
                 
Total members’/partners’ capital/net equity
    69,955       43,860  
                 
Total capitalization
  $ 85,165     $ 88,860  
                 


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DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus), on a pro forma basis as of September 30, 2011, after giving effect to the transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure,” including this offering of common units and the application of the related net proceeds, our net tangible book value would have been $43.9 million, or $2.44 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:
 
                 
Assumed initial public offering price per common unit
              $ 20.00  
Pro forma net tangible book value per unit before this offering(1)
  $ 5.55          
Decrease in net tangible book value per unit attributable to purchasers in the offering
    (3.11 )        
                 
Less: Pro forma net tangible book value per unit after this offering(2)
               
              2.44  
                 
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)
          $ 17.56  
                 
 
(1) Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of units (12,240,000 common units to be issued to the Contributing Parties and the issuance of 360,000 general partner units) to be issued to the Contributing Parties and our general partner.
 
(2) Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of this offering, by the total number of units to be outstanding after this offering (17,640,000 common units and 360,000 general partner units).
 
(3) Because the total number of units outstanding following the consummation of this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the underwriters’ option to purchase additional common units.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and the Contributing Parties, including the Founders and Yorktown, and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired     Total Consideration  
    Number     Percent     Amount     Percent  
                (in thousands)  
 
General partner and Contributing Parties(1)(2)
    12,600,000       70.0 %   $ (53,540 )     %
Purchasers in the offering(3)
    5,400,000       30.0 %     97,400       %
                                 
Total
    18,000,000       100.0 %   $ 43,860       100.0 %
                                 
 
(1) Upon the consummation of the transactions contemplated by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner, its owners and their affiliates will own 12,240,000 common units and 360,000 general partner units.
 
(2) The assets we will own as a result of the merger of our affiliates into our wholly owned subsidiary were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of our general partner is equal to the net tangible book value of such assets as of September 30, 2011.
 
(3) Total consideration is after deducting underwriting discounts, a structuring fee and estimated offering expenses.


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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
 
You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
 
For additional information regarding our historical and pro forma operating results, you should refer to our audited historical financial statements for the years ended June 30, 2008 and 2009, the six months ended December 31, 2009 and the year ended December 31, 2010, our unaudited historical financial statements for the nine months ended September 30, 2011 and our unaudited pro forma financial statements for the year ended December 31, 2010 and nine months ended September 30, 2011 included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy
 
Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects a basic judgment that our unitholders generally will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Our available cash is the sum of our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our partnership agreement will not restrict our ability to borrow to pay distributions. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to such federal income tax.
 
Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
 
There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay distributions at our initial quarterly distribution rate or at any other rate. As a result, there are no consequences to the Partnership (such as an obligation to pay arrearages in future periods) if it was to pay distributions in an amount less the initial quarterly distribution rate. If the Partnership has available cash in respect of any quarter in excess of an amount that would enable it to pay a distribution at the initial quarterly distribution rate to all unitholders, such excess will be distributed to the general partner and all unitholders on a pro rata basis in accordance with their respective interests in the Partnership. Our cash distribution policy may be changed at any time and is or may become subject to certain restrictions, including the following:
 
  •  Our cash distribution policy will be subject to restrictions on distributions under our new credit facility or other debt agreements that we may enter into in the future. Specifically, our new credit facility will contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility.” Should we be unable to satisfy these restrictions, or if a default occurs under our new credit facility, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.


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  •  Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish, other than with respect to reserves for future cash distributions. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must believe that the determination is in, or not opposed to, our best interests. We intend to reserve a sufficient portion of our cash generated from operations to fund our exploitation and development capital expenditures. If our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain the current production levels over the long-term of our oil and natural gas properties, we will be unable to pay distributions at our initial quarterly distribution rate or the then-current distribution rate from cash generated from operations and would therefore expect to reduce our distributions. We are unlikely to be able to sustain the initial quarterly distribution rate without making accretive acquisitions or capital expenditures that maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may have the effect of, and may effectively represent, a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment.
 
  •  Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation, employment benefits, and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.
 
  •  Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner). At the closing of this offering, the Founders will own and control our general partner, and the Founders and Yorktown will own approximately 58.6% of our outstanding common units or 58.6% of our limited partner interests. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”
 
  •  Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, our new credit facility and any other debt agreements we may enter into in the future.
 
  •  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.
 
  •  We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including decreases in commodity prices, decreases in our oil and natural gas


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  production or increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs. For a discussion of additional factors that may affect our ability to pay distributions, please read “Risk Factors.”
 
  •  If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund growth capital expenditures.
 
  •  Capital expenditures reduce cash available to pay distributions to the extent such amounts are funded from cash generated by operating activities.
 
  •  Our ability to make distributions to our unitholders depends on the performance of our operating subsidiary and its ability to distribute cash to us. The ability of our operating subsidiary to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.
 
Our Ability to Grow Depends on Our Ability to Access External Capital
 
Because we will distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including borrowings under our new credit facility and the issuance of debt and equity securities, rather than operating cash flow, to fund our acquisitions and growth capital expenditures. As a result, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand their ongoing operations. To the extent we issue additional units in connection with any capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our quarterly per unit distribution level. There are no limitations in our partnership agreement or in our new credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings (under our credit facility or otherwise) or other debt to finance our growth strategy will increase our interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
Our Initial Quarterly Distribution Rate
 
Upon completion of this offering, the board of directors of our general partner will adopt a cash distribution policy pursuant to which we will establish an initial quarterly distribution of $0.475 per unit per quarter, or $1.90 per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter, beginning with the quarter ending December 31, 2011. This equates to an aggregate cash distribution of approximately $8.6 million per quarter, or $34.2 million on an annualized basis, based on the number of common units and general partner units expected to be outstanding immediately after the closing of this offering. We will prorate our first distribution for the period from the closing of this offering through December 31, 2011 based on the length of that period. The number of outstanding common units and general partner units on which we have based such belief does not include any common units that may be issued under the long-term incentive program that our general partner is expected to adopt prior to the closing of this offering.
 
To the extent the underwriters exercise their option to purchase additional common units in connection with this offering, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remaining common units subject to the option, if any, will be issued to the Contributing Parties, at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the initial quarterly distribution on all units. Please read “Use of Proceeds.”


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Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner’s initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to the Contributing Parties, upon expiration of the underwriters’ option to purchase additional common units or the issuance of common units upon conversion of any outstanding partnership interests that may be converted into common units) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its initial 2.0% general partner interest. Our general partner has the right, but is not obligated, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its then current general partner interest.
 
The table below sets forth the number of common units and general partner units expected to be outstanding immediately following the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial quarterly distribution of $0.475 per unit per quarter, or $1.90 per unit on an annualized basis.
 
                         
    Number of
    Initial Quarterly Distribution  
    Units     One Quarter     Four Quarters  
 
Common units held by the public(1)(2)
    5,400,000     $ 2,565,000     $ 10,260,000  
Common units held by the Contributing Parties(1)(2)(3)
    12,240,000       5,814,000       23,256,000  
General partner units
    360,000       171,000       684,000  
                         
Total
    18,000,000     $ 8,550,000     $ 34,200,000  
                         
 
(1) Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters do not exercise their option to purchase an additional 810,000 common units, we will issue the additional 810,000 common units to the Contributing Parties, upon the expiration of the option. To the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder, if any, will be issued to the Contributing Parties. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the initial quarterly distribution on all units.
 
(2) Does not include any common units that may be issued under the long-term incentive program that our general partner is expected to adopt prior to the closing of this offering.
 
(3) Includes 1,356,027 common units held by the Founders and 8,986,988 common units held by Yorktown.
 
Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above. However, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in the best interests of the Partnership. Please read “Conflicts of Interest and Fiduciary Duties.”
 
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended by a vote of the holders of a majority of our common units. At the closing of this offering, the Founders will own and control our general partner, and the Founders and Yorktown will own approximately 58.6% of our outstanding common


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units, or 58.6% of our limited partner interests. Assuming we do not issue any additional common units and the Founders and Yorktown do not transfer their common units, they will have the ability to amend our partnership agreement without the approval of any other unitholder. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”
 
We will pay our quarterly distributions on or about the 15th of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our first quarterly distribution, we will prorate the initial quarterly distribution payable for the period from the closing of this offering through December 31, 2011 based on the actual length of the period. We expect to pay this cash distribution on or before February 15, 2012.
 
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial quarterly distribution of $0.475 per unit for the year ending December 31, 2012. In those sections, we present two tables, consisting of:
 
  •  “Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2010 and the twelve months ended September 30, 2011, based on our unaudited pro forma financial statements. Our calculation of unaudited pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had the formation transactions contemplated in this prospectus occurred in an earlier period; and
 
  •  “Estimated Cash Available for Distribution,” in which we demonstrate our ability to generate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full initial quarterly distribution on all the outstanding units, including our general partner units, for the year ending December 31, 2012.
 
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended September 30, 2011
 
If we had completed the formation transactions contemplated in this prospectus on January 1, 2010, our unaudited pro forma available cash for the year ended December 31, 2010 would have been approximately $5.4 million. This amount would have been sufficient to pay a cash distribution of $0.075 per unit per quarter ($0.30 on an annualized basis), or approximately 15.8% of the initial quarterly distribution on our common units during that period.
 
If we had completed the transactions contemplated in this prospectus on October 1, 2010, our unaudited pro forma available cash generated for the twelve months ended September 30, 2011 would have been approximately $15.8 million. This amount would have been sufficient to pay a cash distribution of $0.219 per unit per quarter ($0.878 on an annualized basis), or approximately 46.3% of the initial quarterly distribution on our common units during that period.
 
Our unaudited pro forma cash available for distribution includes incremental general and administrative expenses that we expect we will incur as a result of being a publicly traded partnership, consisting of costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, NASDAQ Global Market listing, registrar and transfer agent fees, incremental director and officer liability insurance costs and officer and director compensation. We estimate that these incremental general and administrative expenses initially will be approximately $3.0 million per year. These incremental general and administrative expenses are not reflected in our pro forma Adjusted EBITDA or in our historical and pro forma financial statements.


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The pro forma financial statements, from which pro forma cash available for distribution is derived, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.
 
The following table illustrates, on an unaudited pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011, the amount of available cash that would have been available for distribution to our unitholders, assuming that the formation transactions had been consummated on January 1, 2010 and October 1, 2010, respectively. Each of the pro forma adjustments reflected or presented below is explained in the footnotes to such adjustments.


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Mid-Con Energy Partners, LP
Unaudited Pro Forma Available Cash
                 
    Pro Forma  
    Year
    Twelve Months
 
    Ended
    Ended
 
    December 31,
    September 30,
 
    2010     2011  
    (in thousands, except per unit data)  
    (restated)        
 
Net income
  $ 3,668     $ 18,980  
Plus:
               
Income tax expense (benefit), if any
           
Interest expense
    1,350       1,350  
Depreciation, depletion and amortization
    3,327       4,771  
Accretion of discount on asset retirement obligations
    63       71  
Unrealized (gain) loss on derivatives, net
    707       (7,280 )
Impairment of proved oil and gas properties
    1,260       1,234  
Dry hole costs and abandonments of unproved properties
    514       1,149  
Interest income
    (126 )     (179 )
Stock-based compensation
          1,671  
                 
Adjusted EBITDA(1)
  $ 10,763     $ 21,767  
Less:
               
Incremental general and administrative expense(2)
    3,000       3,000  
Cash interest expense(3)
    1,350       1,350  
Maintenance capital expenditures(4)
    1,014       1,596  
                 
Pro Forma Available cash
  $ 5,399     $ 15,821  
Pro Forma Annualized distributions per unit
    1.90       1.90  
Pro Forma Estimated annual cash distributions:
               
Distributions on common units held by purchasers in this offering
  $ 10,260     $ 10,260  
Distributions on common units held by the Contributing Parties
    23,256       23,256  
Distributions on general partner units
    684       684  
                 
Total estimated annual cash distributions
  $ 34,200     $ 34,200  
                 
Shortfall
  $ (28,801 )   $ (18,379 )
                 
Percent of initial quarterly distributions payable to common unitholders
    15.8 %     46.3 %
 
(1) Adjusted EBITDA is defined in “Prospectus Summary—Non-GAAP Financial Measures.”
 
(2) Reflects the $3.0 million of estimated incremental annual general and administrative expenses associated with being a publicly traded partnership that we expect to incur.
 
(3) In connection with this offering, we intend to enter into a new $250.0 million credit facility under which we expect to incur approximately $45.0 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $45.0 million of borrowings at an assumed weighted-average rate of 3.0%.
 
(4) We define maintenance capital expenditures as capital expenditures that we expect to make on an ongoing basis to maintain waterflood operations over the long-term. We define growth capital expenditures as those that we expect to make to either develop new waterfloods or add primary production through newly initiated development programs. Following this offering, we generally expect to fund maintenance capital expenditures with cash flow from operations, while we plan primarily to use external financing sources, including borrowings under our new credit facility and the issuance of debt and equity securities, to fund growth capital expenditures. Historically, we did not distinguish between maintenance capital expenditures and growth capital expenditures. As a result, the amounts included in the table above represent the approximate amounts of our total capital expenditures for the periods presented that we believe would have been maintenance capital expenditures in those periods. Excluded are approximately $18.7 million and $40.0 million of capital expenditures for the year ended December 31, 2010 and the twelve months ended September 30, 2011, respectively, which are the amounts of capital expenditures that we believe would have been growth capital expenditures in those periods.


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Estimated Adjusted EBITDA for the Year Ending December 31, 2012
 
Set forth below is a Statement of Estimated Adjusted EBITDA that supports our belief that we will be able to generate sufficient cash available for distribution to pay the aggregate annualized initial quarterly distribution on all of our outstanding units for the twelve months ending December 31, 2012. The financial forecast presents, to the best of our knowledge and belief, our expected results of operations, Adjusted EBITDA and cash available for distribution for the forecast period. Based upon the assumptions and considerations set forth in the table below, to fund cash distributions to our unitholders at our annualized initial quarterly distribution of $1.90 per common unit and general partner unit, or $34.2 million in the aggregate, for the year ending December 31, 2012, our Adjusted EBITDA for the year ending December 31, 2012 must be at least $40.6 million. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under the long-term incentive program that our general partner is expected to adopt prior to the closing of this offering.
 
Our Statement of Estimated Adjusted EBITDA reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take in order to be able to pay the annualized initial quarterly distribution on all of our outstanding common and general partner units for the year ending December 31, 2012. The assumptions discussed below under “—Assumptions and Considerations” are those that we believe are significant to our ability to generate the minimum Adjusted EBITDA. We believe our actual results of operations and cash flow will be sufficient to generate the minimum Adjusted EBITDA necessary to pay the aggregate annualized initial quarterly distribution. We can, however, give you no assurance that we will generate this amount. There will likely be differences between our estimated Adjusted EBITDA and our actual results, and those differences could be material. If we fail to generate the estimated Adjusted EBITDA contained in our forecast, we may not be able to pay the aggregate annualized initial quarterly distribution to all of our unitholders.
 
While we do not as a matter of course make public projections as to future sales, earnings or other results, our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the initial quarterly distribution on all our common units and general partner units for the year ending December 31, 2012. This forecast is a forward-looking statement and should be read together with our historical financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the minimum Adjusted EBITDA necessary for us to pay the initial quarterly distribution on all of our outstanding common and general partner units for the year ending December 31, 2012. Readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “—Assumptions and Considerations.”
 
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Grant Thornton LLP has not compiled, examined or performed any procedures with respect to the accompanying prospective financial information and, accordingly, Grant Thornton LLP does not express an opinion or any other form of assurance with respect thereto. The Grant Thornton LLP reports included in the registration statement relate to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.


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When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the minimum Adjusted EBITDA necessary to pay the aggregate annualized initial quarterly distribution on all of our outstanding common and general partner units for the year ending December 31, 2012.
 
We are providing the Statement of Estimated Adjusted EBITDA to supplement our historical financial statements and in support of our belief that we will have sufficient available cash to pay the aggregate annualized initial quarterly distribution on all of our outstanding common and general partner units for the year ending December 31, 2012. Please read below under “—Assumptions and Considerations” for further information about the assumptions we have made for the financial forecast.
 
We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.
 
Our Estimated Adjusted EBITDA
 
To pay the annualized initial quarterly distribution to our unitholders of $0.475 per unit for the year ending December 31, 2012, our aggregate cash available to pay distributions must be at least approximately $8.6 million over that period. We have calculated that the amount of estimated Adjusted EBITDA for the year ending December 31, 2012 that will be necessary to generate cash available to pay an aggregate annualized distribution of approximately $34.2 million over that period is approximately $40.6 million. Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flow from operating activities or any other measure calculated in accordance with GAAP.
 
Adjusted EBITDA is a significant financial metric that will be used by our management to indicate (prior to the establishment of any reserves by the board of directors of our general partner) the cash distributions we expect to pay to our unitholders. Specifically, we intend to use this financial measure to assist us in determining whether we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. For a definition of Adjusted EBITDA, please read “Prospectus Summary—Non-GAAP Financial Measures.”


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Mid-Con Energy Partners, LP
Statement of Estimated Adjusted EBITDA
 
         
    Year Ending
 
    December 31, 2012
 
    (in thousands, except
 
    per unit amounts)  
 
Revenue and realized commodity derivative gains(losses)(1)
  $ 63,832  
Less:
       
Lease operating expenses
    9,396  
Oil and gas production taxes
    3,043  
General and administrative(2)
    4,000  
Depreciation, depletion and amortization
    15,000  
Interest expense
    1,350  
         
Net income excluding unrealized gains (losses) on derivatives
  $ 31,043  
Adjustments to reconcile net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA:
       
Add:
       
Depreciation, depletion and amortization
  $ 15,000  
Interest expense
    1,350  
         
Estimated Adjusted EBITDA(3)
  $ 47,393  
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
       
Less:
       
Cash interest expense
  $ 1,350  
Maintenance capital expenditures(4)
    5,000  
         
Estimated cash available for distribution
  $ 41,043  
Annualized initial quarterly distribution per unit
  $ 1.90  
Estimated annual cash distributions(5):
       
Distributions on common units held by purchasers in this offering
  $ 10,260  
Distributions on common units held by the Contributing Parties
    23,256  
Distributions on general partner units
    684  
Total estimated annual cash distributions
  $ 34,200  
Excess cash available for distribution
  $ 6,843  
 
(1) Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.
 
(2) Includes $3.0 million of estimated incremental annual general and administrative expenses associated with being a publicly traded partnership that we expect to incur.
 
(3) Adjusted EBITDA is defined in “Prospectus Summary—Non-GAAP Financial Measures.”
 
(4) Reflects estimated maintenance capital expenditures for the year ending December 31, 2012. We define maintenance capital expenditures as those we expect to make on an ongoing basis to maintain our waterflood operations over the long-term. Following this offering, we generally expect to fund maintenance capital expenditures with cash flow from operations.
 
(5) The number of outstanding common units assumed herein does not include any common units that may be issued under the long-term incentive program that our general partner is expected to adopt prior to the closing of this offering. We estimate that the maximum number of awards that we would grant during the year ending December 31, 2012 under the long-term incentive program would be an aggregate of 350,000 restricted units, phantom units or other unit-based awards. If all of the 350,000 units underlying such awards were entitled to receive four quarterly distributions at the initial distribution rate during the year ending December 31, 2012, the aggregate amount distributable on such units would be $665,000. In that case, the amount of our excess cash available for distribution for the year would be reduced to $6,178,000.


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Assumptions and Considerations
 
Based upon the specific assumptions outlined below with respect to the year ending December 31, 2012, we expect to generate estimated Adjusted EBITDA sufficient to establish reserves for capital expenditures and to pay the aggregate annualized initial quarterly distribution on all common and general partner units for the year ending December 31, 2012.
 
While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay quarterly cash distributions equal to our initial quarterly distribution (absent additional borrowings under our new revolving credit facility), or any amount, on all common and general partner units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our initial quarterly distribution over the long-term without making accretive acquisitions or substantial capital expenditures that maintain the current production levels of our oil and natural gas properties. We expect to rely primarily on external financing sources, including bank borrowings and the issuance of equity and debt securities, rather than operating cash flow to fund our growth capital expenditures. If we do not make sufficient cash expenditures from operating cash flow to maintain the current production levels of our oil and natural gas properties, we may be unable to pay distributions at our initial quarterly distribution rate or the then-current distribution rate from cash generated from operations and would therefore expect to reduce our distributions over time. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.
 
Operations and Revenue
 
Production.  The following table sets forth information regarding net production of oil and natural gas on a pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011 and on a forecasted basis for the year ending December 31, 2012:
 
                         
    Pro Forma
    Pro Forma
    Forecasted
 
    Year Ended
    Twelve Months
    Year Ending
 
    December 31,
    Ended September 30,
    December 31,
 
    2010     2011     2012  
 
Annual production:
                       
Oil (MBbl)
    220       347       659  
Natural gas (MMcf)
    184       158       115  
                         
Total (MBoe)
    250       373       678  
                         
Average net daily production:
                       
Oil (Bbl/d)
    602       951       1,800  
Natural Gas (Mcf/d)
    505       434       314  
                         
Total (Boe/d)
    686       1,023       1,852  
                         


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We estimate that our total oil and natural gas production for the year ending December 31, 2012 will be 1,852 Boe per day as compared to 686 Boe per day on a pro forma basis for the year ended December 31, 2010 and 1,023 Boe per day on a pro forma basis for the twelve months ended September 30, 2011. For the months ended June 30, 2011, July 31, 2011, August 31, 2011 and September 30, 2011, our average net production was 1,248 Boe per day, 1,272 Boe per day, 1,327 Boe per day and 1,343 Boe per day, respectively. The 2012 forecast reflects a 509 Boe per day production increase from our September 30, 2011 production. A portion of this increase relates to our Highlands Unit. Under the unitization order governing the Highlands Unit, the working and net revenue interests of each owner in the unit depend on the classification of reserves currently produced from the unit. The unitization order divides reserves into two classifications based on agreed upon volumes—those capable of production under primary recovery techniques and those capable of production under secondary recovery techniques (e.g., waterflooding). Our working and net revenue interests in the Highlands Unit for the first reserve category were 44.5% and 36.3%, respectively, but increased to 57.5% and 46.8%, respectively, when the unit began producing from the second reserve category on November 1, 2011. During September 2011, our average net production from the Highlands Unit was 238 Boe day. Had the unit been producing from the second reserve category during that same time, our average net production would have been 307 Boe per day. We have similar arrangements in place in several of our other units, and many of these units have already begun producing from the second reserve category, resulting in an increase in our working and net revenue interests.
 
Since January 2010 we have drilled approximately 78 gross (47 net) infill development wells, mostly in our Southern Oklahoma core area. Approximately half of these wells are injection wells, which have allowed us to increase injection in our waterflood units, leading to higher reservoir pressures and ultimately increases in our production over time. We spent approximately $12.9 million on this drilling program in 2010 and have spent approximately $22.3 million in the first nine months of 2011. We expect to spend approximately $5.2 million on these activities during the last three months of 2011. The typical response time for waterflood projects after injection is initiated ranges from six to eighteen months, and consequently, our capital expenditures do not ordinarily result in corresponding immediate increases in our production levels or consistent increases over a period of time. However, we believe that our capital expenditures in 2010 and 2011 will enable us to achieve our forecasted production level of 1,852 Boe per day for the year ending December 31, 2012. In addition, we estimate that we will spend an average of $5.0 million per year on maintenance capital expenditures in order to maintain our forecasted production level, which we intend to fund with cash generated from operations.
 
Prices.  The table below illustrates the relationship between average oil and natural gas realized sales prices and average NYMEX prices on a pro forma basis for the year ended


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December 31, 2010 and the twelve months ended September 30, 2011 and our forecast for the year ending December 31, 2012:
 
                         
    Pro Forma
  Pro Forma
  Forecasted
    Year Ended
  Twelve Months
  Year Ending
    December 31,
  Ended September 30,
  December 31,
    2010   2011   2012
 
Average oil sales prices:
                       
Average daily NYMEX-WTI oil price per Bbl
  $ 79.61     $ 94.50     $ 96.00  
Differential to NYMEX-WTI oil per Bbl
  $ (5.46 )   $ (6.22 )   $ (3.08 )
Realized oil sales price per Bbl (excluding cash settlements of derivatives)
  $ 74.15     $ 88.28     $ 92.92  
Realized oil sales price per Bbl (including cash settlements of derivatives)
  $ 73.69     $ 85.74     $ 95.75  
Average natural gas sales prices:
                       
Average daily NYMEX-Henry Hub natural gas price per MMBtu
  $ 4.38     $ 4.17     $ 3.86  
Differential to NYMEX-Henry Hub natural gas per MMBtu
  $ 3.18     $ 3.71     $ 2.70  
Realized natural gas sales price per Mcf(1)
  $ 7.58     $ 7.88     $ 6.56  
 
(1) We had no natural gas derivative contracts for the pro forma periods and assume that we will not enter into any such contracts for the year ending December 31, 2012. Realized natural gas sales price per Mcf includes the sale of natural gas liquids.
 
Price Differentials.  Our oil production, which is predominantly “light sweet” oil, typically sells at a discount to the NYMEX-WTI price due to quality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Our natural gas production has historically sold at a positive basis differential from the NYMEX-Henry Hub price primarily due to the rich Btu and liquids content of the production attributable to our operating areas. The adjustments we have made to reflect the basis differentials for our forecasted production during the year ending December 31, 2012 are presented in the following table and shown per Bbl for oil and per Mcf for natural gas, as adjusted to reflect our oil purchase contracts effective as of January 1, 2012.
 
                 
    Oil
  Natural Gas
Operating Area
  Per Bbl   Per Mcf(1)
 
Southern Oklahoma
  $ (3.64 )   $ 0.92  
Northeastern Oklahoma
  $ (1.37 )   $ (1.61 )
Hugoton Basin
  $ (4.21 )   $ (1.20 )
Other
  $ (1.35 )   $ 4.39  
Weighted Average
  $ (3.08 )   $ 2.70  
 
(1) Realized natural gas sales price per Mcf includes the sale of natural gas liquids.


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Use of Commodity Derivative Contracts.  For purposes of our forecast, we have assumed that our commodity derivative contracts will cover 360 MBbl, or approximately 55%, of our forecasted total oil production of 659 MBbl for the year ending December 31, 2012. Our commodity derivative contracts consist of swap and collar agreements based upon NYMEX-WTI prices. The table below shows the volumes and prices covered by the commodity derivative contracts for the year ending December 31, 2012. For purposes of our forecast, we have assumed that we will not enter into natural gas derivative contracts or additional oil derivative contracts during the forecast period, although we may do so on an opportunistic basis if market conditions are favorable.
 
                                         
    Swaps   Collars
        Weighted
      Weighted
  Weighted
        Average
      Average
  Average
    Bbl   Price   Bbl   Floor Price   Ceiling Price
 
Oil:
                                       
January—December 2012
    288,000     $ 101.47       72,000     $ 100.00     $ 117.00  
% of forecasted oil production
    43.72 %             10.93 %                
 
Operating Revenues and Realized Commodity Derivative Gains.  The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2010 and the twelve months ended September 30, 2011 and on a forecasted basis for the year ending December 31, 2012:
 
                         
    Pro Forma
    Pro Forma
    Forecasted
 
    Year Ended
    Twelve Months
    Year Ending
 
    December 31,
    Ended September 30,
    December 31,
 
    2010     2011     2012  
    (in thousands)  
 
Oil:
                       
Oil revenues
  $ 16,286     $ 30,640     $ 61,216  
Realized oil derivative instruments gain (loss)
    (100 )     (879 )     1,862  
                         
Total
  $ 16,186     $ 29,761     $ 63,078  
                         
Natural gas:
                       
Natural gas revenues(1)
  $ 1,397     $ 1,248     $ 754  
                         
 
(1) We had no natural gas derivative contracts for the pro forma periods and assume that we will not enter into any such contracts for the year ending December 31, 2012. Realized natural gas sales price per Mcf includes the sale of natural gas liquids.
 


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    Pro Forma
    Pro Forma
    Forecasted
 
    Year Ended
    Twelve Months
    Year Ending
 
    December 31,
    Ended September 30,
    December 31,
 
    2010     2011     2012  
    (in thousands)  
 
Total:
                       
Operating revenues
  $ 17,683     $ 31,888     $ 61,970  
Commodity derivative instruments gain (loss)
    (100 )     (879 )     1,862  
                         
Operating revenue and realized commodity derivative instruments gains
  $ 17,583     $ 31,009     $ 63,832  
                         
 
Capital Expenditures and Expenses
 
Capital Expenditures.  Historically, we did not distinguish between maintenance capital expenditures and growth capital expenditures, but we believe that approximately $1.0 million and $1.6 million of our total capital expenditures for the year ended December 31, 2010 and the twelve months ended September 30, 2011, respectively, would have been maintenance capital expenditures. We believe that the balance of our capital expenditures for those periods, $18.7 million and $40.0 million, respectively, would have been growth capital expenditures. Through these growth capital expenditures, we have significantly increased our production levels. As a result, we anticipate that our maintenance capital expenditures will increase significantly during the year ending December 31, 2012 as compared to the year ended December 31, 2010 and the twelve months ended September 30, 2011 in order to maintain our forecasted production level of 1,852 Boe per day. For the forecast period, we estimate that we will drill 9 gross (5 net) wells and spend additional maintenance capital on workovers at an average annual aggregate net cost of approximately $5.0 million.
 
Although we may make acquisitions during the year ending December 31, 2012, our forecast period does not reflect any acquisitions or other growth capital expenditures because we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase terms.
 
Lease Operating Expenses.  The following table summarizes lease operating expenses on an aggregate basis and on a per Boe basis for the year ended December 31, 2010, pro forma, the twelve months ended September 30, 2011, pro forma, and on a forecasted basis for the year ending December 31, 2012:
 
                         
    Pro Forma
  Pro Forma
  Forecasted
    Year Ended
  Twelve Months
  Year Ending
    December 31,
  Ended September 30,
  December 31,
    2010   2011   2012
 
Lease operating expenses (in thousands)
  $ 5,041     $ 7,074     $ 9,396  
Lease operating expenses (per Boe)
  $ 20.14     $ 18.94     $ 13.86  
 
We estimate that our lease operating expenses for the year ending December 31, 2012 will be approximately $9.4 million. On a pro forma basis, for the year ended December 31, 2010 and the twelve months ended September 30, 2011, lease operating expenses were $5.0 million and $7.1 million, respectively. The increase in forecasted lease operating expenses is primarily a

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result of increased drilling activity and production. The decrease in lease operating expenses per Boe is a result of the projected increase in production. Lease operating expenses also include ad valorem taxes, which are generally tied to the valuation of the oil and natural gas properties. These valuations are generally correlated to revenues, excluding the effects of our commodity derivative contracts. As a result, we forecast our ad valorem taxes as a percent of revenues, excluding the effects of commodity derivative contracts.
 
Production Taxes.  The following table summarizes production taxes before the effects of our commodity derivative contracts on a pro forma basis for the year ended December 31, 2010, the twelve months ended September 30, 2011 and on a forecasted basis for the year ending December 31, 2012:
 
                         
    Pro Forma
  Pro Forma
  Forecasted
    Year Ended
  Twelve Months
  Year Ending
    December 31,
  Ended September 30,
  December 31,
    2010   2011   2012
    (in thousands)
 
Oil and natural gas revenues, excluding the effect of our commodity derivative contracts
  $ 17,683     $ 31,888     $ 61,970  
Production taxes
  $ 797     $ 1,415     $ 3,043  
Production taxes as a percentage of revenue
    4.51 %     4.43 %     4.91 %
 
Our production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Additionally, production tax rates vary by state, and as revenues by state vary, our production taxes will increase or decrease. The State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas properties, and an excise tax of 0.095%. A portion of our wells in the State of Oklahoma currently receive a reduced production tax rate due to the Enhanced Recovery Project Gross Production Tax Exemption. The State of Colorado currently imposes a 1.0% production tax for oil properties.
 
General and Administrative Expenses.  In connection with the closing of this offering, we will enter into a services agreement with Mid-Con Energy Operating with respect to all general and administrative expenses and costs it incurs on our general partner’s and our behalf, including $3.0 million of incremental annual expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NASDAQ Global Market; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and director and officer compensation. Under the services agreement, Mid-Con Energy Operating will be reimbursed for all general and administrative expenses allocated to us under the services agreement.
 
Depreciation, Depletion and Amortization Expense.  We estimate that our depreciation, depletion and amortization expense for the year ending December 31, 2012 will be approximately $15.0 million, as compared to $3.3 million and $4.8 million on a pro forma basis for the year ending December 31, 2010 and the twelve months ended September 30, 2011, respectively. The forecasted increase in the depletion of our oil and natural gas properties is primarily based on the forecasted increase in our production. Our capitalized costs are calculated using the successful efforts method of accounting. For a detailed description of the successful efforts method of


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accounting, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates.”
 
Cash Interest Expense.  We estimate that at the closing of this offering we will borrow approximately $45.0 million in revolving debt under our new $250.0 million credit facility. We estimate that the borrowings will bear interest at a weighted average rate of approximately 3.0%. Based on these assumptions, we estimate that our cash interest expense for the year ending December 31, 2012 will be $1.4 million and on a pro forma basis for both the year ended December 31, 2010 and the twelve months ended September 30, 2011.
 
Our new credit facility will contain financial covenants that require us to maintain a leverage ratio of not more than 4.0 to 1.0x and a current ratio of not less than 1.0 to 1.0x. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility” for additional detail regarding the covenants and restrictive provisions to be included in our new credit facility. Our new credit facility will not require any cash expenditures on our part that would affect our cash available for distribution other than cash interest expense and unused facility fees.
 
Regulatory, Industry and Economic Factors
 
Our forecast for the year ending December 31, 2012 is based on the following significant assumptions related to regulatory, industry and economic factors:
 
  •  There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or any interpretation of existing regulations, that will be materially adverse to our business;
 
  •  There will not be any material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;
 
  •  All supplies and commodities necessary for production and sufficient transportation will be readily available;
 
  •  There will not be any major adverse change in commodity prices or the energy industry in general;
 
  •  There will not be any material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events, including any events that could lead to force majeure under any of our marketing agreements;
 
  •  There will not be any adverse change in the markets in which we operate resulting from supply or production disruptions, reduced demand for our product or significant changes in the market prices for our product; and
 
  •  Market, insurance, regulatory and overall economic conditions will not change substantially.
 
Sensitivity Analysis
 
Our ability to generate sufficient cash from operations to pay cash distributions to our unitholders is a function of two primary variables: (i) production volumes; and (ii) commodity prices. In the tables below, we illustrate the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the initial quarterly distribution on our outstanding common units for the year ending December 31, 2012.


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Production Volume Changes
 
The following table shows estimated Adjusted EBITDA under production levels of 90%, 100% and 110% of the production level we have forecasted for the year ending December 31, 2012. The estimated Adjusted EBITDA amounts shown below are based on the assumptions used in our forecast.
 
                         
    Percentage of Forecasted
 
    Net Production  
    90%     100%     110%  
    (in thousands, except per unit amounts)  
 
Forecasted net production:
                       
Oil (MBbl)
    593       659       725  
Natural gas (MMcf)
    103       115       126  
                         
Total (MBoe)
    610       678       746  
Oil (Bbl/d)
    1,620       1,800       1,980  
Natural gas (Mcf/d))
    283       314       345  
                         
Total (Boe/d)
    1,667       1,852       2,038  
Forecasted prices:
                       
NYMEX-WTI oil price (per Bbl)
  $ 96.00     $ 96.00     $ 96.00  
Realized oil price (per Bbl) (excluding derivatives)
  $ 92.92     $ 92.92     $ 92.92  
Realized oil price (per Bbl) (including derivatives)
  $ 96.06     $ 95.75     $ 95.49  
NYMEX-Henry Hub natural gas price (per MMBtu)
  $ 3.86     $ 3.86     $ 3.86  
Realized natural gas price (per Mcf)(1)(2)
  $ 6.56     $ 6.56     $ 6.56  


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    Percentage of Forecasted
 
    Net Production  
    90%     100%     110%  
    (in thousands, except per unit amounts)  
 
Forecasted Adjusted EBITDA projection:
                       
Operating revenue
  $ 55,773     $ 61,970     $ 68,166  
Realized derivative gains (losses)
    1,862       1,862       1,862  
                         
Total revenue including realized derivative gains (losses)
  $ 57,635     $ 63,832     $ 70,028  
Lease operating expenses(3)
    8,457       9,396       10,336  
Production taxes
    2,738       3,043       3,347  
General and administrative expenses
    4,000       4,000       4,000  
                         
Estimated Adjusted EBITDA
  $ 42,440     $ 47,393     $ 52,345  
Minimum estimated Adjusted EBITDA(4)
    40,550       40,550       40,550  
Excess (shortfall) estimated cash available for distribution(4)
    1,890       6,843       11,795  
 
 
(1) Realized natural gas sales price per Mcf includes the sale of natural gas liquids.
 
(2) We assume that we will not enter into any natural gas derivative contracts for the year ending December 31, 2012.
 
(3) The calculation of lease operating expenses includes ad valorem taxes.
 
(4) We have calculated that the minimum amount of estimated Adjusted EBITDA for the year ending December 31, 2012 that will be necessary to generate cash available to pay an aggregate annualized distribution on all of our outstanding units over that period is approximately $40.6 million. In the case where our production level is 90% of the production level we have forecasted for the year ending December 31, 2012, we should have had an excess of $1.9 million over the amount of cash available for distribution necessary to pay such aggregate annualized distribution.
 
Commodity Price Changes
 
The following table shows estimated Adjusted EBITDA under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the year ending December 31, 2012. For the year ending December 31, 2012, we have assumed that commodity derivative contracts will cover 360 MBoe, or approximately 55% of our estimated total oil production from proved reserves for the year ending December 31, 2012, at a weighted average floor price of $101.18 per Bbl of oil. In addition, the estimated Adjusted EBITDA amounts shown below are based on forecasted realized


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commodity prices that take into account assumptions concerning updated differentials based on new crude oil purchase contracts that will be effective as of January 1, 2012.
 
                                         
    (in thousands, except per unit amounts)  
 
NYMEX-WTI oil price (per Bbl):
  $ 76.00     $ 86.00     $ 96.00     $ 106.00     $ 116.00  
NYMEX-Henry Hub natural gas price (per MMBtu):
  $ 2.86     $ 3.36     $ 3.86     $ 4.36     $ 4.86  
Forecasted net production:
                                       
Oil (MBbl)
    659       659       659       659       659  
Natural gas (MMcf)
    115       115       115       115       115  
                                         
Total (MBoe)
    678       678       678       678       678  
Oil (Bbl/d)
    1,800       1,800       1,800       1,800       1,800  
Natural gas (Mcf/d)
    314       314       314       314       314  
                                         
Total (Boe/d)
    1,852       1,852       1,852       1,852       1,852  
Forecasted prices:
                                       
NYMEX-WTI oil price (per Bbl)
  $ 76.00     $ 86.00     $ 96.00     $ 106.00     $ 116.00  
Realized oil price (per Bbl) (excluding derivatives)
  $ 72.92     $ 82.92     $ 92.92     $ 102.92     $ 112.92  
Realized oil price (per Bbl) (including derivatives)
  $ 86.68     $ 91.21     $ 95.75     $ 100.94     $ 106.57  
NYMEX-Henry Hub natural gas price (per MMBtu)
  $ 2.86     $ 3.36     $ 3.86     $ 4.36     $ 4.86  
Realized natural gas price (per Mcf)(1)(2)
  $ 5.56     $ 6.06     $ 6.56     $ 7.06     $ 7.56  
Forecasted Adjusted EBITDA projection:
                                       
Operating revenue
  $ 48,679     $ 55,324     $ 61,970     $ 68,615     $ 75,261  
Realized derivative gains (losses)
    9,062       5,462       1,862       (1,306 )     (4,186 )
                                         
Total revenue including realized derivative gains (losses)
    57,741       60,786       63,832       67,309       71,075  
Lease operating expenses(3)
    9,396       9,396       9,396       9,396       9,396  
Production taxes
    2,390       2,716       3,043       3,369       3,695  
General and administrative expenses
    4,000       4,000       4,000       4,000       4,000  
                                         
Estimated Adjusted EBITDA
  $ 41,955     $ 44,674     $ 47,393     $ 50,544     $ 53,984  
Minimum estimated Adjusted EBITDA
    40,550       40,550       40,550       40,550       40,550  
Excess (shortfall) estimated cash available for distribution(4)
    1,405       4,124       6,843       9,994       13,434  
 
 
(1) Realized natural gas sales price per Mcf includes the sale of natural gas liquids.
 
(2) We assume that we will not enter into any natural gas derivative contracts for the year ending December 31, 2012.
 
(3) The calculation of lease operating expenses includes ad valorem taxes.
 
(4) We have calculated that the minimum amount of estimated Adjusted EBITDA for the year ending December 31, 2012 that will be necessary to generate cash available to pay an aggregate annualized distribution on all of our outstanding units over that period is approximately $40.6 million. In the case where the average daily NYMEX-WTI price for oil for the year ending December 31, 2012 is $76.00 and the average daily NYMEX-Henry Hub price for natural gas is $2.86 per MMBtu for the same period, we would have had an excess of $1.4 million over the amount of cash available for distribution necessary to pay such aggregate annualized distribution. In the case where the average daily NYMEX-WTI price for oil for the year ending December 31, 2012 is $86.00 and the average daily NYMEX-Henry Hub price for natural gas is $3.36 per MMBtu for the same period, we would have had an excess of $4.1 million over the amount of cash available for distribution necessary to pay such aggregate annualized distribution.


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


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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO
CASH DISTRIBUTIONS
 
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions. The information presented in this section assumes that our general partner will continue to make capital contributions to us in order to maintain its 2.0% general partner interest.
 
Distributions of Available Cash
 
General
 
Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we will distribute all of our available cash to unitholders of record on the applicable record date. We will prorate the initial quarterly distribution payable for the period from the closing of this offering through December 31, 2011, based on the actual length of that period. We will distribute 98.0% of our available cash to our common unitholders, pro rata, and 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.
 
Definition of Available Cash
 
Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
 
  •  less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:
 
  •  provide for the proper conduct of our business (including reserves for future capital expenditures, working capital and operating expenses) subsequent to that quarter;
 
  •  comply with applicable law, any of our loan agreements, security agreements, mortgages debt instruments or other agreements; or
 
  •  provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters;
 
  •  plus, if our general partner so determines, all or a portion of cash or cash equivalents on hand on the date of determination of available cash for the quarter.
 
Distributions of Cash Upon Liquidation
 
General
 
If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors and the liquidator in the order of priority provided in our partnership agreement and by law. Thereafter, we will distribute any remaining proceeds to our unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.


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Manner of Adjustments for Gain
 
The manner of the adjustment for gain is set forth in the partnership agreement. Upon our liquidation, we will allocate any net gain (or unrealized gain attributable to assets distributed in kind to our partners) in the following manner:
 
  •  first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances; and
 
  •  second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner.
 
Manner of Adjustments for Losses
 
Upon our liquidation, we will generally allocate any loss to our general partner and the unitholders in the following manner:
 
  •  first, 98.0% to the holders of common units, in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of our unitholders have been reduced to zero; and
 
  •  thereafter, 100% to our general partner.
 
Adjustments to Capital Accounts
 
Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation.


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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA
 
We were formed in July 2011 and do not have historical financial operating results. Therefore, in this prospectus, we present the historical financial statements of our predecessor, which consist of the consolidated historical financial statements of Mid-Con Energy Corporation through June 30, 2009 and the combined historical financial statements of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, thereafter. The following table presents selected historical financial data of our predecessor and selected pro forma financial data of Mid-Con Energy Partners, LP as of the dates and for the periods indicated. The selected historical financial data as of December 31, 2009 and 2010 and for the years ended June 30, 2008 and 2009, the six months ended December 31, 2009 and the year ended December 31, 2010 are derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The selected historical financial data for the years ended June 30, 2006 and 2007 are derived from audited historical financial statements of our predecessor not included herein. The selected historical financial data as of September 30, 2011 and for the nine months ended September 30, 2010 and 2011 are derived from the unaudited historical combined financial statements of our predecessor included elsewhere in this prospectus.
 
The selected unaudited pro forma financial data as of September 30, 2011 and for the nine months ended September 30, 2011 and the year ended December 31, 2010 are derived from the unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:
 
  •  the sale by Mid-Con Energy I, LLC and Mid-Con Energy II, LLC of certain oil and natural gas properties representing 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;
 
  •  the merger of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC with our wholly owned subsidiary in exchange for aggregate consideration of 12,240,000 common units and $121.2 million in cash;
 
  •  the issuance to our general partner of 360,000 general partner units, representing a 2.0% general partner interest in us in exchange for a contribution from our general partner;
 
  •  the issuance and sale by us to the public of 5,400,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds;”
 
  •  our borrowing of approximately $45.0 million under our new credit facility and the application of the proceeds as described in “Use of Proceeds;” and
 
  •  our acquisition of additional working interests in the Cushing Field from J&A Oil Company and Charles R. Olmstead immediately prior to the closing of this offering.
 
The unaudited pro forma balance sheet data assume the events listed above occurred as of September 30, 2011. The unaudited pro forma statement of operations data for the nine months ended September 30, 2011 and the year ended December 31, 2010 assume the items listed above occurred as of January 1, 2010. We have not given pro forma effect to incremental general and administrative expenses of approximately $3.0 million that we expect to incur annually as a result of being a publicly traded partnership.
 
You should read the following table in conjunction with “Prospectus Summary—Formation Transactions and Partnership Structure,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of our predecessor and the unaudited pro forma condensed financial statements of Mid-Con Energy Partners, LP and the notes thereto included elsewhere in this prospectus.


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Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information.
 
The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the financial performance and liquidity of our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.
 
                                                                                   
            Mid-Con Energy I, LLC and
    Mid-Con Energy
 
            Mid-Con Energy II, LLC
    Partners, LP  
            (combined)     Pro Forma  
    Mid-Con Energy Corporation
      Six Months
    Year
    Nine Months
    Year
    Nine Months
 
    (consolidated)       Ended
    Ended
    Ended
    Ended
    Ended
 
    Year Ended June 30,       December 31,     December 31,     September 30,     December 31,     September 30,  
Statement of Operations Data:   2006     2007     2008     2009       2009     2010     2010     2011     2010     2011  
                                          (unaudited)     (unaudited)     (unaudited)     (unaudited)  
    (in thousands)  
    (restated)     (restated)     (restated)     (restated)       (restated)                       (restated)        
                                    (restated)                          
Revenues:
                                                                                 
Oil sales
  $ 5,569     $ 6,944     $ 13,667     $ 10,246       $ 5,729     $ 16,853     $ 11,390     $ 25,068     $ 16,286     $ 25,040  
Natural gas sales
    51       64       618       2,172         743       1,418       1,104       974       1,397       978  
Realized loss on derivatives, net
    (165 )     558       (804 )     (669 )       (350 )     (90 )     (87 )     (799 )     (100 )     (875 )
Unrealized gain (loss) on derivatives, net
    (294 )     45       (2,035 )     1,679         (147 )     (707 )     182       9,400       (707 )     9,400  
                                                                                   
Total revenues
    5,161       7,611       11,446       13,428         5,975       17,474       12,589       34,643       16,876       34,543  
                                                                                   
Operating costs and expenses:
                                                                                 
Lease operating expenses
    2,252       3,429       5,005       5,369         2,431       6,237       4,654       5,951       5,041       5,600  
Oil and gas production taxes
    407       478       946       631         269       822       522       1,116       797       1,119  
Dry holes and abandonments of unproved properties
    539       220                           1,418       1,053       772       514       772  
Geological and geophysical
    146       342       1,296       507               394       253       171              
Depreciation, depletion and amortization
    931       924       1,599       2,293         2,552       5,851       4,743       4,318       3,327       4,128  
Accretion of discount on asset retirement obligations
    2       35       56       78         58       127       95       55       63       55  
General and administrative
    1,391       1,805       1,871       1,767         704       982       708       552       982       552  
Impairment of proved oil and gas properties
    178                           9,208       1,886                   1,260        
                                                                                   
Total operating costs and expenses
    5,846       7,233       10,773       10,645         15,222       17,717       12,028       12,935       11,984       12,226  
                                                                                   
Income (loss) from operations
    (685 )     378       673       2,783         (9,247 )     (243 )     561       21,708       4,892       22,317  
                                                                                   


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            Mid-Con Energy I, LLC and
    Mid-Con Energy
 
            Mid-Con Energy II, LLC
    Partners, LP  
            (combined)     Pro Forma  
    Mid-Con Energy Corporation
      Six Months
    Year
    Nine Months
    Year
    Nine Months
 
    (consolidated)       Ended
    Ended
    Ended
    Ended
    Ended
 
    Year Ended June 30,       December 31,     December 31,     September 30,     December 31,     September 30,  
Statement of Operations Data:   2006     2007     2008     2009       2009     2010     2010     2011     2010     2011  
                                          (unaudited)     (unaudited)     (unaudited)     (unaudited)  
    (in thousands)  
    (restated)     (restated)     (restated)     (restated)       (restated)                       (restated)        
                                    (restated)                          
Other income (expenses):
                                                                                 
Interest income and other
    63       126       115       119         35       218       208       160       126       102  
Interest expense
    (24 )     (11 )     (3 )     (93 )