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EX-10.8 - FORM OF STOCKHOLDERS AGREEMENT - Midstates Petroleum Company, Inc.d248475dex108.htm
EX-23.1 - CONSENT OF DELOITTE & TOUCHE LLP - Midstates Petroleum Company, Inc.d248475dex231.htm
EX-23.3 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Midstates Petroleum Company, Inc.d248475dex233.htm
EX-23.2 - CONSENT OF DELOITTE & TOUCHE LLP - Midstates Petroleum Company, Inc.d248475dex232.htm
EX-99.1 - REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Midstates Petroleum Company, Inc.d248475dex991.htm
Table of Contents

As filed with the Securities and Exchange Commission on February 1, 2012

Registration No. 333-177966

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

AMENDMENT NO. 3

TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Midstates Petroleum Company, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1311   45-3691816

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification No.)

4400 Post Oak Parkway, Suite 1900

Houston, Texas 77027

(713) 595-9400

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

 

 

John Foley

Corporate Counsel

4400 Post Oak Parkway, Suite 1900

Houston, Texas 77027

(713) 595-9400

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

 

 

Copies to:

 

David P. Oelman

Matthew R. Pacey

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002-6760

(713) 758-2222

 

Joshua Davidson

Kelly B. Rose

Baker Botts L.L.P.

One Shell Plaza

Houston, Texas 77002-4995

(713) 229-1234

 

 

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

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

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

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

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

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

 

Large accelerated filer    ¨      Accelerated filer    ¨
Non-accelerated filer    x    (Do not check if a smaller reporting company)   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 this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion. Dated February 1, 2012

PROSPECTUS

            Shares

LOGO

Midstates Petroleum Company, Inc.

COMMON STOCK

 

 

Midstates Petroleum Company, Inc. is offering              shares of its common stock and the selling stockholders named in this prospectus are offering              shares of common stock. We will not receive any proceeds from the sale of shares by the selling stockholders.

This is our initial public offering, and no public market currently exists for our shares. We anticipate that the initial public offering price of our common stock will be between $         and $         per share.

We have applied to list our common stock on the New York Stock Exchange under the symbol “MPO.”

Investing in our common stock involves risks. See “Risk Factors” beginning on page 17.

 

 

The Securities and Exchange Commission and state securities regulators have not 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 SHARE

 

     Price to Public    Underwriting
Discounts and
Commissions
   Proceeds to
Company
   Proceeds to Selling
Stockholder

Per Share

           

Total

           

 

 

Midstates Petroleum Company, Inc. and the selling stockholders have granted the underwriters the right to purchase up to an additional              shares of common stock.

The underwriters expect to deliver the shares of common stock to purchasers on or about                      , 2012.

 

 

Joint Book-Running Managers

 

Goldman, Sachs & Co.    
  Morgan Stanley  
      Wells Fargo Securities   
   

 

 

Prospectus dated                     , 2012


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or to which we have referred you. Neither we nor the selling stockholders have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the selling stockholders are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

Through and including                     , 2012 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” beginning on page 17 and “Cautionary Note Regarding Forward-Looking Statements” beginning on page 39.

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 as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

 

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus and is qualified in its entirety by the more detailed information and financial statements included elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and the related notes to those financial statements included elsewhere in this prospectus. Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of common stock is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and the “Company” refer to Midstates Petroleum Holdings LLC and its subsidiaries before the completion of our corporate reorganization and Midstates Petroleum Company, Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter. See “Corporate Reorganization” on page 123.

MIDSTATES PETROLEUM COMPANY, INC.

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources in previously discovered yet underdeveloped hydrocarbon trends. We were founded in 1993 to focus on oilfields in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. The Upper Gulf Coast Tertiary trend extends from south Texas to Mississippi across our current operating areas in central Louisiana and is characterized by well-defined geology, including tight sands featuring multiple productive zones typically located within large geologic traps. Many of the oilfields in this trend were discovered by major oil companies in the 1940’s and 1950’s, but were not fully developed due to then-prevailing oil prices, the adoption of a state-level severance tax in Louisiana, restrictive production allowables and other regulatory limitations. We have applied modern formation evaluation and drilling and completion techniques to the trend, and, as a result, we have identified a large inventory of development drilling opportunities that we believe will provide strong economic returns. Our early entry and relatively long history in the trend have positioned us as a first-mover. We have accumulated approximately 77,100 net acres in the trend and have options to acquire an aggregate of approximately 31,700 additional targeted net acres.

Our development operations are currently focused in the Wilcox interval of the trend, drilling vertical wells and commingling production from multi-stage hydraulically fractured completions across stacked oil-producing intervals. Our strategy has been validated by the 57 gross wells we have drilled in the trend, approximately 93% of which produced commercially, since the third quarter of 2008. Since that time, we have increased our average daily production at a compound annual growth rate of 101%, from 1,024 Boe/d in the month ended September 30, 2008 to 9,897 Boe/d in the month ended December 31, 2011. We believe that, based on the results of our drilling program and our understanding of the geology underlying our acreage, we have a total of 600 specifically identified gross vertical drilling locations in the trend. In addition, we believe this trend may further benefit from the application of horizontal drilling and completion techniques. We drilled our first horizontal well in the trend in the fourth quarter of 2011, and it is currently undergoing completion.

 

 

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Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 26.2 MMBoe as of December 31, 2011, 75% of which were comprised of oil and natural gas liquids (“NGLs”). As of December 31, 2011, our properties included approximately 92 gross active producing wells, 95% of which we operate, and in which we held an average working interest of approximately 99% across our 77,100 net acre leasehold. The following table presents summary data regarding our reserves and production for each of our four primary operating areas as well as other acreage we hold that we have identified as having significant hydrocarbon structures, as measured by either production tests or well log analysis, which we refer to as our expansion areas. The information in the table is as of December 31, 2011, unless otherwise indicated:

 

    Average Daily
Production (1)
    Estimated
Net
Proved
Reserves
    Acreage     Identified
Vertical
Drilling
Locations (3)
    2011
Wells (4)
    Budget  
              2012
Wells (5)
    2012
D&C (6)
 
    (Boe/d)     (% Oil) (2)     (MMBoe)     (Gross)     (Net)     (Gross)     (Gross)     (Gross)     (In millions)  

Pine Prairie

    3,793        71     12.1        3,101        3,076        150        13        26      $ 90   

South Bearhead Creek/Oretta

    4,367        60     5.3        3,645        3,559        39        6        8        47   

West Gordon

    1,002        68     5.5        10,617        10,488        73        8        15        98   

North Cowards Gully

    149        77     3.0        7,109        7,109        75        1        2        6   

Expansion Areas (7):

                 

Acreage under lease

    122        78     0.3        54,392        52,840        263        4        16        65   

Acreage under option

                         32,067        31,669                               
 

 

 

     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    9,433        66     26.2        110,931        108,741        600        32        67      $ 306   
 

 

 

     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Average daily production for the three months ended December 31, 2011.
(2) Includes volumes attributable to oil and NGLs.
(3) Our drilling locations are specifically identified based on our interpretation of 2D and 3D seismic data, study of previously drilled wells and analogous well performance. We have selected our drilling locations to optimize the initial testing and subsequent delineation of all potential reservoirs in a given field or geologic structure. Drilling locations in our Pine Prairie area are primarily based on 10-acre spacing, while other drilling locations are primarily based on 40-acre spacing or greater. Of our 600 specifically identified gross vertical drilling locations, approximately 100 are classified as proved undeveloped according to NSAI’s December 31, 2011 reserve report.
(4) Includes wells spud between January 1, 2011 and December 31, 2011; 31 wells were drilled to total depth and one well was in the process of drilling at December 31, 2011.
(5) Includes wells spud or expected to be spud between January 1, 2012 and December 31, 2012.
(6) Represents drilling and completion expenditures.
(7) For a description of our expansion areas, see “Business — Our Areas of Operation — Expansion Areas Within the Trend” beginning on page 71.

Our total 2011 capital expenditures were $264 million, and we drilled or spud 32 wells in 2011. Our total 2012 capital expenditure budget is $380 million, approximately 17% of which will be spent developing acreage currently under lease in our expansion areas. Our 2012 budget consists of:

 

   

$306 million for drilling and completion capital;

 

   

$58 million for acquisition of acreage and seismic data; and

 

   

$16 million in unallocated funds which are available for facilities.

While we have budgeted $380 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” beginning on page 55.

 

 

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Our Business Strategy

Our goal is to increase stockholder value by growing reserves, production and cash flows at an attractive return on invested capital. We seek to achieve this goal through the following strategies:

 

   

Accelerate development of our multi-year drilling inventory. We intend to drill and develop our current acreage position to maximize the value of our resource potential. Our assets are characterized by thick geologic sections of tight sands featuring multiple productive zones located within large geologic structural traps that are identifiable with 2D seismic data. Our primary operating areas have well-established production histories and relatively low terminal production decline rates. We have identified an inventory of 600 gross vertical drilling locations targeting large, well-defined geologic structures that we believe will increase our reserves, production and cash flow. Since the third quarter of 2008, we have drilled 57 gross wells in the trend, approximately 93% of which produced commercially, making us the most active driller in the trend during that period. As of December 31, 2011, we had four drilling rigs in operation. We expect to operate up to six drilling rigs by the end of 2012, which would enable us to drill as many as 67 gross operated wells during that year, 16 of which we anticipate drilling in our expansion areas.

 

   

Utilize our technical and operating expertise to enhance returns. Our management team is focused on the application of modern reservoir evaluation and drilling and completion techniques to reduce risk and enhance returns. We utilize 2D seismic data and existing sub-surface well control data to identify large, undeveloped or under-developed geologic traps that we believe have significant development potential as targets for our leasing activity. Once we have identified a potential target, we attempt to efficiently verify the economic viability of the target reservoir utilizing existing wellbores and techniques such as sidetracking and slim-hole drilling. Once the development potential of the target reservoir has been established, we seek to economically develop the opportunity by incorporating 3D seismic data and reservoir evaluation methods such as conventional and rotary sidewall coring, pressure sampling and other reservoir description techniques. We have accumulated 3D seismic data covering 80% of the acreage in our primary operating areas and 60% of our total acreage. We believe our primary operating areas represent the successful execution of this exploration to development approach. We are applying this same approach to our expansion areas, where we have recently leased approximately 52,800 net acres and have also entered into lease option agreements covering approximately 31,700 additional targeted net acres. We believe future development across our entire acreage position may be further optimized through specialized completion techniques, infill drilling, horizontal drilling and other enhanced recovery methods.

 

   

Strategically increase our acreage position. While we believe our existing inventory of specifically identified drilling locations provides significant growth opportunities, we continue to use the in-depth knowledge that we have gained as a first mover in the region to increase our leasehold position in the oil-prone portion of the Upper Gulf Coast Tertiary trend. We believe that this portion of the trend extends from east Texas through central Louisiana and into southern Mississippi and offers us significant opportunities to acquire additional acreage. We have screened more than 300 geologic structures in the oil-prone portion of the trend. Our current acreage position, including acreage under option, has captured 18 of these structures, of which we have drilled eight, all of which have established commercial production in multiple horizons. We have specifically identified approximately 40 additional geologic structures throughout the trend that we believe have characteristics similar to our existing operating areas. In addition to increasing our acreage position through leasing, we may selectively pursue potential acquisitions of strategic assets or operating companies in the trend. Over

 

 

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time, we also expect to selectively target additional onshore basins in North America that would allow us to extend our competencies to large undeveloped acreage positions in hydrocarbon trends similar to our existing core area.

 

   

Apply rigorous investment analysis to capital allocation decisions. We employ rigorous investment analysis to determine the allocation of capital across our many drilling opportunities. We are focused on maximizing the internal rate of return on our investment capital and screen drilling opportunities by measuring risk and financial return, among other factors. We continually evaluate and rank our inventory of potential investments by these measures, incorporating past drilling results and new information we have gathered. This approach has allowed us to maintain attractive operational and efficiency metrics, measured by finding and development costs, even as our capital expenditures and drilling activities have significantly increased over the last three years.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

 

   

Extensive technical knowledge, history and first-mover advantage in the Upper Gulf Coast Tertiary trend. We have had operations in the Upper Gulf Coast Tertiary trend since 1993. We believe our extensive operating experience in the trend provides us with an expansive technical understanding of the geology underlying our acreage and of the application of completion technologies and infrastructure design and optimization to our properties. We believe our relatively long history in this area and experience interpreting well control data, core data and 2D and 3D seismic data provides us with an information advantage over our competitors in the trend and has allowed us to identify and acquire quality acreage at a relatively low cost. In addition, we have developed amicable and mutually beneficial relationships with acreage owners in our operating areas, which we believe provides us with a competitive advantage with respect to our leasing and development activity. We also benefit from long-term relationships with local service companies and infrastructure providers that we believe contribute to our efficient low-cost operations.

 

   

Louisiana Light Sweet oil-weighted reserves, production and drilling locations with attractive economics. Our reserves, production and drilling locations are primarily oil with associated liquids rich natural gas. For the three months ended December 31, 2011, our production was comprised of approximately 55% oil and 12% NGLs. We benefit from selling our oil production to the Louisiana Light Sweet (“LLS”) market, which has historically commanded a premium to West Texas Intermediate (“NYMEX WTI”) oil prices due to its proximity to U.S. Gulf Coast refiners and the higher quality of the oil production sold in the LLS market. This premium has averaged approximately $7.82 per Bbl in the three years ended December 31, 2011. For the three months ended December 31, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $115.46 per Bbl, compared to an average NYMEX WTI price of $94.06 per Bbl for the same period, representing a premium of $21.40 per barrel. Our ability to capture a premium for our oil production in the LLS market provides us with a significant competitive advantage over companies with assets in other well known plays, such as the Bakken and Eagle Ford, where oil price realizations are typically at a discount to NYMEX WTI. In addition, our assets are located in an area with developed legacy infrastructure that reduces our development and transportation costs relative to other onshore basins in North America.

 

 

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Multi-year drilling inventory with significant upside potential. We have an inventory of approximately 600 specifically identified gross vertical drilling locations. This inventory includes drilling locations in our expansion areas that have been meaningfully risked given the early stage of development. We believe our expansion areas possess substantially similar characteristics as our primary operating areas, and expect that the execution of our 2012 drilling plan will allow us to reduce our risk profile on this acreage and could add materially to our drilling opportunities. We also believe the potential drilling inventory on our existing acreage may increase significantly by targeting additional productive zones and through infill drilling. Based on the results of our development activities in our primary operating areas, we believe that infill drilling within thick geologic sections of tight sands increases the ultimate resource recovery. We have successfully downspaced to 10-acre spacing in portions of our Pine Prairie area. We are currently testing downspacing in our South Bearhead Creek/Oretta and North Cowards Gully areas and intend to apply this concept in our other primary operating areas and our expansion areas. In addition, we may be able to enhance the total recovery in the trend through specialized completion techniques, horizontal drilling and secondary recovery techniques.

 

   

Operating control over 96% of our portfolio. In order to maintain better control over our assets, we have established a leasehold position comprised primarily of properties that we expect to operate. Controlling operations allows us to dictate the pace of development and better manage the cost, type and timing of exploration and development activities. We expect to operate 96% of our 600 specifically identified gross drilling locations. For the three months ended December 31, 2011, approximately 99% of our production was attributable to properties that we operate.

 

   

Experienced management team with extensive operating expertise. Our management team has extensive operating expertise in the oil and gas industry and significant public company executive experience at Apache Corporation, Burlington Resources, ConocoPhillips, Noble Corporation, and SM Energy. Our management team has an average of 30 years of industry experience, including prior experience in the Upper Gulf Coast Tertiary trend and similar trends. We believe our management team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record of efficiently operating exploration and development programs.

 

   

Conservative financial position. We believe that our capital structure and hedge positions following this offering will allow us to continue our development program and acquire additional acreage even in challenging commodity price environments and periods of capital markets dislocation. Giving effect to the completion of this offering, our liquidity as of December 31, 2011 would have been $         million, consisting of $         million available under our revolving credit facility and $         million in cash and cash equivalents. After the completion of this offering, we believe we will have the liquidity and financial flexibility to more than fund our 2012 drilling program and production growth. In addition, we have an active hedging program in place, with swaps, collars and puts covering approximately 1.6 million barrels of our oil production in 2012.

 

   

Alignment among management, founders and public stockholders. Upon the completion of this offering, our management team will have a significant direct ownership interest in us. In addition, our management team will also own an indirect economic interest in us through their ownership of incentive units in FR Midstates Interholding, LLC (“FRMI”). FRMI is controlled by funds affiliated with First Reserve Management, L.P. (“First Reserve”). The incentive units entitle our management to a portion of the proceeds to be received by First Reserve upon sales of our common stock by FRMI in excess of certain multiples of First Reserve’s

 

 

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aggregate capital contributions and investment expenses. Our management may significantly increase the value allocated to their incentive units by increasing the return on investment for First Reserve. We believe our management team’s direct ownership interest and incentive units provide significant incentives to grow the value of our business for the benefit of all stockholders.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. In particular, the following considerations may offset our competitive strengths or have a negative effect on our business strategy as well as on activities on our properties, which could cause a decrease in the price of our common stock and result in a loss of all or a portion of your investment:

 

   

A substantial or extended decline in oil and, to a lesser extent, natural gas, prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

   

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

 

   

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these assumptions will materially affect the quantities and present value of our reserves.

 

   

In connection with audits and reviews of our financial statements, our independent registered public accounting firm identified and reported adjustments to management. Certain of such adjustments were deemed to be the result of internal control deficiencies that constitute 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.

 

   

The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.

For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see “Risk Factors” beginning on page 17 and “Cautionary Note Regarding Forward-Looking Statements” beginning on page 39.

Conflicts of Interest

Affiliates of Goldman, Sachs & Co., Morgan Stanley & Co. LLC and Wells Fargo Securities, LLC are lenders, and in one case, an agent for the lenders, under our reserve-based revolving credit facility. Because a portion of the proceeds of this offering will be used to repay indebtedness under our revolving credit facility, a “conflict of interest” under Rule 5121 of the Financial Industry Regulatory Authority, or FINRA, is therefore deemed to exist. Accordingly, this offering is being made in compliance with FINRA Rule 5121. Pursuant to FINRA Rule 5121, a “qualified independent underwriter” meeting certain standards must participate in the preparation of the registration statement of which this prospectus forms a part and must exercise the usual standards of due diligence with respect thereto.             has assumed the responsibilities of acting as the qualified independent underwriter in this offering. Please read “Underwriting — Conflicts of Interest” beginning on page 138.

 

 

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Corporate Sponsorship and Structure

We were recently incorporated pursuant to the laws of the State of Delaware as Midstates Petroleum Company, Inc. to become a holding company for Midstates Petroleum Company LLC, a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Midstates Petroleum Holdings LLC was formed as a Delaware limited liability company on August 13, 2008, by certain members of our senior management and First Reserve. In connection with First Reserve’s initial investment in us, members of our management team contributed their interests in our predecessor, Midstates Petroleum Corporation, a Louisiana corporation, to Midstates Petroleum Holdings LLC. Midstates Petroleum Corporation was founded by Ray E. Royer, Robert McDaniel and Stephen J. McDaniel in 1993 with the acquisition of assets in our North Cowards Gully project area. Additional leasehold acreage was accumulated over the next 15 years preceding First Reserve’s initial investment and our corporate reorganization in August 2008. Including First Reserve’s initial investment in August 2008, First Reserve has acquired an approximate 77% aggregate equity interest in us. With over $23 billion of raised capital dedicated exclusively to the energy and natural resources industries, First Reserve is the largest energy focused private investment firm, making both private equity and infrastructure investments throughout the energy value chain. For 28 years, it has invested solely in the global energy industry, utilizing its broad base of specialized energy industry knowledge as a competitive advantage. The firm is currently investing its most recent private equity fund, which closed in 2009 at approximately US $9 billion and its most recent infrastructure fund, which closed in 2011 at approximately US $1.2 billion.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, Midstates Petroleum Company, Inc., will directly own all of the outstanding membership interests in Midstates Petroleum Company LLC. See “Corporate Reorganization” on page 123. Following the completion of this offering, First Reserve will initially own an approximate     % indirect economic interest in us through FRMI, which will initially own approximately     % of our outstanding shares of common stock (or     % if the underwriters’ option to purchase additional shares is exercised in full).

 

 

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The tables below present an overview of our organizational structure before and after the completion of this offering.

Current Organizational Structure

LOGO

 

(1) Represents membership interests indirectly held by First Reserve through FR Midstates Holdings LLC and affiliates.
(2) Includes membership interests held directly by certain members of management and Midstates Petroleum Holdings, Inc., a subchapter S corporation, through which our founders, management and certain of our employees hold their equity interest in us.

 

(3) Midstates Petroleum Holdings LLC is a holding company and its sole material asset is its 100% equity interest in Midstates Petroleum Company LLC, through which we conduct our operations.

 

(4) Certain members of management and certain of our employees own incentive units through Midstates Incentive Holdings LLC that entitle them to receive a portion of any proceeds to be received by FR Midstates Holdings LLC from any sale of its equity interest in Midstates Petroleum Holdings LLC in excess of certain multiples of First Reserve’s aggregate capital contributions and investment expenses.

 

 

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Organizational Structure After Giving Effect to this Offering

 

LOGO

 

(1) Represents membership interests indirectly held by First Reserve through FRMI and affiliates.
(2) Certain members of management and certain of our employees will own incentive units through Midstates Incentive Holdings LLC that entitle them to receive a portion of the proceeds to be received by First Reserve upon sales of shares of common stock in Midstates Petroleum Company, Inc. by FRMI in excess of certain multiples of First Reserve’s aggregate capital contributions and investment expenses.

For more information on our reorganization and the ownership of our common stock by our principal and selling stockholders, see “Corporate Reorganization” beginning on page 123 and “Principal and Selling Stockholders” beginning on page 124.

Corporate Information

Our principal executive offices are located at 4400 Post Oak Parkway, Suite 1900, Houston, Texas 77027, and our telephone number at that address is (713) 595-9400. Our website is located at www.midstatespetroleum.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, or 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 herein and does not constitute a part of this prospectus.

 

 

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THE OFFERING

 

Common stock offered by Midstates Petroleum Company, Inc.

             shares (         shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Common stock offered by the selling stockholders

             shares (         shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Total common stock offered

             shares (         shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Common stock to be outstanding after the offering

             shares (         shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Common stock owned by the selling stockholders after the offering

             shares (         shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Option to purchase additional shares

We and the selling stockholders have granted the underwriters a 30-day option to purchase up to an aggregate of          additional shares of our common stock.

 

Use of proceeds

We expect to receive approximately $         million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

 

  We intend to use $         million of the net proceeds from this offering to repay all outstanding indebtedness under our revolving credit facility.

We intend to use $             million of the net proceeds from this offering to redeem preferred units that were previously issued by Midstates Petroleum Holdings LLC to an affiliate of First Reserve.

 

  We intend to use $             million of the net proceeds from this offering to fund a portion of our exploration and development program.

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders.

 

 

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  Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering. See “Use of Proceeds” on page 41 and “Underwriting—Conflicts of Interest” beginning on page 138.

 

Dividend policy

We do not anticipate paying any cash dividends on our common stock. In addition, our revolving credit facility prevents us from paying cash dividends. See “Dividend Policy” on page 41.

 

Risk factors

You should carefully read and consider the information beginning on page 17 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

 

Listing and trading symbol

We have applied to list our common stock on the New York Stock Exchange under the symbol “MPO.”

 

 

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Summary Historical Consolidated Financial Data

You should read the following summary financial data in conjunction with “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited financial information and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Set forth below is our summary historical consolidated financial data as of and for the years ended December 31, 2011, 2010 and 2009.

 

     Year Ended December 31,  
     2011     2010     2009  
    

(in thousands)

 

Statement of operations data

Revenues:

      

Oil, gas and natural gas liquids revenues

   $ 213,812      $ 89,111      $ 30,133   

Losses on commodity derivative contracts-net

     (4,844     (26,268     (5,987

Other revenue

     465        209        108   

Total revenues

     209,433        63,052        24,254   

Expenses:

      

Lease operating

     15,234        8,733        5,312   

Workover

     2,101        4,683        5,226   

Severance tax

     12,422        6,431        2,849   

Asset retirement accretion

     334        175        120   

General and administrative

     27,970        16,847        5,886   

Depreciation, depletion and amortization

     91,699        41,827        12,322   

Impairment in carrying value of oil and natural gas properties

                   4,297   

Total expenses

     149,760        78,696        36,012   

Income (loss) from operations

     59,673        (15,644     (11,758

Other income (expense):

      

Interest income

     23        9        6   

Interest expense-net of amounts capitalized

     (2,094              

Net income (loss)

   $ 57,602      $ (15,635   $ (11,752

 

 

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     As of December 31,  
     2011      2010      2009  
     (in thousands)  

Balance sheet data:

        

Cash and cash equivalents

   $ 7,344       $ 11,917       $ 4,353   

Net property and equipment

     574,079         397,126         271,726   

Total assets

     624,656         427,004         284,034   

Long-term debt (1)

     234,800         89,600         29,800   

Total members’/stockholders’ equity

     285,502         255,879         235,334   

 

     Year Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Other financial data:

      

Net cash provided by operating activities

   $ 140,700      $ 50,768      $ 10,595   

Net cash used in investing activities

     (242,771     (139,618     (75,215

Net cash provided by financing activities

     97,498        96,414        65,759   

Adjusted EBITDA (2)

     152,616        53,274        12,539   

 

(1) As of February 1, 2012, Midstates Petroleum Holdings LLC had $20.0 million of preferred units outstanding. We intend to redeem all preferred units outstanding with a portion of the net proceeds from this offering.
(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “— Non-GAAP Financial Measures and Reconciliations” below.

Non-GAAP Financial Measures and Reconciliations

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as earnings before interest income and expense, income taxes, depreciation, depletion and amortization, property impairments, asset retirement obligation accretion, unrealized derivative gains and losses and non-cash share-based compensation expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

We believe that Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude items such as property impairments, asset retirement obligation accretion, unrealized derivative gains and losses and non-cash share-based compensation expense from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

 

 

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The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

 

     Year Ended December 31,  
     2011     2010     2009  
    

(in thousands)

 

Adjusted EBITDA reconciliation to net income (loss):

      

Net income (loss)

   $ 57,602      $ (15,635   $ (11,752

Depreciation, depletion and amortization

     91,699        41,827        12,363   

Impairment in carrying value of oil and gas properties

                   4,297   

Change in unrealized (gain) loss on commodity derivative contracts

     (11,889     25,398        7,283   

Interest income

     (23     (9     (6

Interest expense-net of amounts capitalized

     2,094                 

Asset retirement obligation accretion

     334        175        120   

Share-based compensation

     12,799        1,518        234   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 152,616      $ 53,274      $ 12,539   
  

 

 

   

 

 

   

 

 

 

 

     Year Ended December 31,  
     2011      2010     2009  
    

(in thousands)

 

Adjusted EBITDA reconciliation to net cash provided by operating activities:

       

Net cash provided by operating activities

   $ 140,700       $ 50,768      $ 10,595   

Changes in working capital

     9,845         2,515        1,950   

Interest income

     (23)         (9     (6

Interest expense-net of amounts capitalized

     2,094                  
  

 

 

    

 

 

   

 

 

 

Adjusted EBITDA

   $ 152,616       $ 53,274      $ 12,539   
  

 

 

    

 

 

   

 

 

 

 

 

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Summary Historical Operating and Reserve Data

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves as of the dates indicated. For additional information regarding our reserves, see “Business” beginning on page 65. The reserve estimates at December 31, 2011, 2010 and 2009 presented in the table below are based on reports prepared by NSAI. NSAI’s reports were prepared consistent with the rules and regulations of the SEC regarding oil and natural gas reserve reporting in effect during such periods.

 

     At December 31,  
     2011     2010     2009  

Reserve Data:

      

Estimated proved reserves:

      

Oil (MMBbls)

     15.7        11.9        7.6   

Natural gas (Bcf)

     38.7        27.9        13.3   

Natural gas liquids (MMBbls)

     4.0        0.3        0.1   

Total estimated proved reserves (MMBoe)

     26.2        16.9        9.9   

Proved developed reserves:

      

Oil (MMBbls)

     6.5        5.4        2.8   

Natural gas (Bcf)

     18.0        14.2        4.4   

Natural gas liquids (MMBbls)

     1.8        0.1        0.0   

Total proved developed (MMBoe)

     11.3        7.9        3.5   

Percent proved developed

     43     47     36

Proved undeveloped reserves:

      

Oil (MMBbls)

     9.2        6.5        4.8   

Natural gas (Bcf)

     20.7        13.7        8.9   

Natural gas liquids (MMBbls)

     2.2        0.2        0.1   

Total proved undeveloped (MMBoe)

     14.9        9.0        6.4   

The following table sets forth the benchmark prices used to determine our estimated proved reserves from proved oil and natural gas reserves for the periods indicated.

 

     At December 31,  
     2011      2010      2009  

Oil and Natural Gas Prices (1):

        

Oil (per Bbl)

   $ 92.71       $ 75.96       $ 57.65   

Natural gas (per MMBtu)

   $ 4.118       $ 4.376       $ 3.866   

 

(1) Benchmark prices for oil and natural gas at December 31, 2011, 2010 and 2009 reflect the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months, using Plains WTI posted prices for oil and Platt’s Gas Daily Henry Hub prices for natural gas.

 

 

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The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical basis for the periods presented:

 

     Year Ended December 31,  
     2011      2010      2009  

Operating data:

        

Net production volumes:

        

Oil (MBbls)

     1,610         945         497   

Natural gas (MMcf)

     4,918         2,253         690   

Natural gas liquids (MBbls)

     308         74         2   

Total oil equivalents (MBoe)

     2,737         1,394         614   

Average daily production (Boe/d)

     7,499         3,820         1,682   

Average sales prices:

        

Oil, without realized derivatives (per Bbl)

   $ 110.25       $ 80.29       $ 55.07   

Oil, with realized derivatives (per Bbl)

     100.26         79.37         57.69   

Natural gas (per Mcf)

     4.20         4.66         3.89   

Natural gas liquids (per Bbl)

     50.98         36.92         47.66   

Cost and expenses (per Boe of production):

        

Lease operating

   $ 5.12       $ 5.86       $ 8.31   

Workover

     0.77         3.36         8.51   

Severance and ad valorem tax

     4.98         5.01         4.99   

Asset retirement accretion

     0.12         0.13         0.20   

General and administrative

     10.22         11.73         9.59   

Depreciation, depletion and amortization

     33.50         30.00         20.08   

 

 

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RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the risks described below together with the other information set forth in this prospectus before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil and, to a lesser extent, natural gas, prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

 

   

worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

 

   

the actions of the Organization of Petroleum Exporting Countries;

 

   

the price and quantity of imports of foreign oil and natural gas;

 

   

political conditions in or affecting other oil and natural gas-producing countries;

 

   

the level of global oil and natural gas exploration and production;

 

   

the level of global oil and natural gas inventories;

 

   

localized supply and demand fundamentals and transportation availability;

 

   

weather conditions and natural disasters;

 

   

domestic, local and foreign governmental regulations and taxes;

 

   

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

 

   

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

 

   

technological advances affecting energy consumption; and

 

   

the price and availability of alternative fuels.

Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. If oil and natural gas prices deteriorate, we anticipate that the borrowing base under our revolving credit facility, which is revised periodically, may be reduced. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

 

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A reduction in the premium to NYMEX WTI oil prices we receive by selling to the LLS market could significantly reduce the relative price advantage we receive for our production.

Because our producing properties are geographically concentrated in central Louisiana, we are vulnerable to fluctuations in pricing in that area. Our oil production is generally sold in the LLS market, which has recently commanded a premium to NYMEX WTI prices due to its proximity to U.S. Gulf Coast refiners and international markets that are typically correlated with Brent oil prices as well as take-away constraints at the Cushing, Oklahoma hub where NYMEX WTI contracts are settled. A reduction in this premium could significantly reduce the relative price advantage we receive for our production. In addition, as a result of this geographic concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, transportation capacity constraints and curtailment or interruption of production from the wells in these areas.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development, drilling and production activities. Our oil and natural gas drilling and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore or develop drilling locations or properties will depend in part on the evaluation of data obtained through 2D and 3D seismic data, geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The production and operating data that is available with respect to the Upper Gulf Coast Tertiary trend based on modern drilling and completion techniques is relatively limited compared to trends where multiple operators have been active for a significant period of time. As a result, we face more uncertainty in evaluating data than operators in more developed trends. For a discussion of the uncertainty involved in these processes, see “— Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these assumptions will materially affect the quantities and present value of our reserves” on page 20. Our costs of drilling, completing and operating wells is often uncertain before drilling commences. In addition, the application of new techniques in this trend, such as high-graded stimulation designs and horizontal completions, some of which we have not previously employed, may make it more difficult to accurately estimate these costs. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

   

shortages of, or delays in, obtaining equipment and qualified personnel;

 

   

facility or equipment malfunctions;

 

   

unexpected operational events;

 

   

pressure or irregularities in geological formations;

 

   

adverse weather conditions;

 

   

reductions in oil and natural gas prices;

 

   

delays imposed by or resulting from compliance with regulatory requirements;

 

   

proximity to and capacity of transportation facilities;

 

   

title problems; and

 

   

limitations in the market for oil and natural gas.

 

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The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2011, 2010 and 2009, we based the discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

 

   

actual prices we receive for oil and natural gas;

 

   

actual cost of development and production expenditures;

 

   

the amount and timing of actual production; and

 

   

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure 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. As a limited liability company, we have not historically been subject to entity level taxation. Accordingly, our standardized measure does not provide for federal or state corporate income taxes because taxable income is passed through to our equity holders. However, pursuant to our corporate reorganization, we will merge into a corporation. As a result, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus which could have a material effect on the value of our reserves.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We use the full cost method of accounting for our oil and gas properties. Accordingly, we capitalize and amortize all productive and nonproductive costs directly associated with property acquisition, exploration and development activities. Under the full cost method, the capitalized cost of oil and gas properties, less accumulated amortization and related deferred income taxes may not exceed the “cost center ceiling” which is equal to the sum of the present value of estimated future net revenues from proved reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, plus the costs of properties not subject to amortization, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income tax effects. If the net capitalized costs exceed the cost center ceiling, we recognize the excess as an impairment of oil and gas properties. This impairment does not impact cash flows from operating activities but does reduce our earnings and shareholders’ equity. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. We recorded a non-cash ceiling test impairment of approximately $26.8 million for the period ended December 31, 2008 and approximately $4.3 million for the year ended December 31, 2009. We could incur additional impairments of oil and natural gas properties in the future, particularly as a result of a decline in commodity prices.

 

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We have incurred losses from operations during certain periods since the beginning of 2008 and may continue to do so in the future.

We incurred net losses of $15.6 million and $11.8 million for the years ended December 31, 2010 and 2009, respectively, and $13.1 million for the period from August 30, 2008 to December 31, 2008. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically acquire and develop oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. See “Business — Our Operations” beginning on page 69 for information about our estimated oil and natural gas reserves.

In order to prepare our estimates, we must estimate production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Estimates of oil and natural gas reserves are inherently imprecise. In addition, reserve estimates for properties that do not have a lengthy production history, including the areas in which we operate, are less reliable than estimates for fields with lengthy production histories. There can be no assurance that analysis of previous production data relating to the Upper Gulf Coast Tertiary trend will accurately predict future production, development expenditures or operating expenses from wells drilled and completed using modern techniques. In addition, this data is based on vertically drilled wells, which may not accurately reflect production, development expenditures or operating expenses that may result from the application of horizontal drilling techniques.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 57% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2011. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

 

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Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

Drilling locations that we have identified may not yield oil or natural gas in commercially viable quantities.

We describe some of our drilling locations and our plans to explore those drilling locations in this prospectus. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations. In addition, we may not be able to raise the amount of capital that would be necessary to drill a substantial portion of our identified potential drilling locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

 

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Part of our strategy involves using some of the latest available horizontal drilling and completion techniques. The results of our horizontal drilling activities are subject to drilling and completion technique risks, and actual drilling results may not meet our expectations for reserves or production. As a result, we may incur material impairment of the carrying value of our unevaluated properties, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Our experience with horizontal drilling utilizing the latest drilling and completion techniques is limited in the Wilcox interval of the trend. We drilled our first horizontal well in the trend in the fourth quarter of 2011, which has not yet been completed. Risks that we face while horizontally drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our horizontal wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these horizontal drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our horizontal drilling results are less than anticipated, the return on our investment in these areas may not be as attractive as we anticipate. The carrying value of our unevaluated properties could become impaired, which would increase our depletion rate per Boe if there were no corresponding additions to recoverable reserves, and the value of our undeveloped acreage could decline in the future.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

We utilize third-party services to maximize the efficiency of our organization. The cost of oilfield services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of frac crews, drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our business depends on transportation by truck for our oil and condensate production, and our natural gas production depends on transportation facilities that are owned by third parties.

We transport all of our oil and condensate production by truck, which is more expensive and less efficient than transportation via pipeline. Our natural gas production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

The disruption of third-party facilities due to maintenance or weather could negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flows, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.

 

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We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

   

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

 

   

abnormally pressured formations;

 

   

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

   

fires, explosions and ruptures of pipelines;

 

   

personal injuries and death; and

 

   

natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

 

   

injury or loss of life;

 

   

damage to and destruction of property, natural resources and equipment;

 

   

pollution and other environmental damage;

 

   

regulatory investigations and penalties;

 

   

suspension of our operations; and

 

   

repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to drill our identified locations and pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Our revolving credit facility contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our revolving credit facility includes certain covenants that, among other things, restrict:

 

   

our investments, loans and advances and the payment of dividends and other restricted payments;

 

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our incurrence of additional indebtedness;

 

   

the granting of liens, other than liens created pursuant to the revolving credit facility and certain permitted liens;

 

   

mergers, consolidations and sales of all or a substantial part of our business or properties;

 

   

the hedging, forward sale or swap of our production of oil or natural gas or other commodities;

 

   

the sale of assets (other than production sold in the ordinary course of business); and

 

   

our capital expenditures.

Our revolving credit facility requires us to maintain certain financial ratios, such as leverage ratios. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Our level of indebtedness may increase and reduce our financial flexibility.

Upon the completion of this offering, we expect to have no indebtedness outstanding and a borrowing base of $235 million under our revolving credit facility. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

 

   

a significant portion of our cash flows could be used to service our indebtedness;

 

   

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

   

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

 

   

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

 

   

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

   

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

 

   

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and

 

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other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations on a semi-annual basis, effective September 1 and March 1, beginning September 1, 2011, and up to one additional time per six-month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent under our revolving credit facility. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

An unfavorable resolution of the Clovelly litigation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In May 2009, Clovelly Oil Company, or Clovelly, filed a lawsuit against us in the 13th Judicial District Court in Louisiana. Clovelly alleges that we are subject to an unrecorded Joint Operating Agreement dated July 16, 1972, as a result of our 2007 purchase of a 43.75% working interest in certain acreage, and accordingly, that it is entitled to 56.25% of our 242.28-acre lease in the Pine Prairie area. For further information regarding this lawsuit, please read “Business — Legal Proceedings” on page 88. We cannot predict the outcome of the Clovelly lawsuit or the amount of time and expense that will be required to resolve the lawsuit. An unfavorable resolution of such litigation could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such litigation could divert the attention of management and resources in general from day-to-day operations.

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

We are subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas during the year ended December 31, 2011 and 2010 was Chevron, accounting for 39% and 66% of our total revenues for these periods, respectively. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, we enter into derivative instruments for a portion of our oil production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk” beginning on page 62 and Notes to Consolidated Financial Statements — Note 4 — Risk Management and Derivative Instruments for a summary of our oil commodity derivative positions. We did not designate any of our derivative instruments as hedges for accounting purposes, and we record all derivative instruments in our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

 

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Derivative instruments expose us to the risk of financial loss in some circumstances, including when:

 

   

production is less than the volume covered by the derivative instruments;

 

   

the counter-party to the derivative instrument defaults on its contractual obligations; or

 

   

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received for basis differentials.

In addition, our derivative arrangements limit the benefit we would receive from increases in the prices for oil.

All of our operations are located in central Louisiana, making us vulnerable to risks associated with operating in one geographic area.

As of December 31, 2011, all of our proved reserves and our annual production were located in central Louisiana. This concentration could disproportionately expose us to operational and regulatory risk or other adverse developments in this area, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance or weather. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more diversified.

Large competitors may be attracted to our core operating areas, which may increase our costs.

Our operations in the Upper Gulf Coast tertiary trend may attract companies that have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Their presence in the trend may also restrict our access to, or increase the cost of, oil and natural gas infrastructure, drilling rigs, equipment, supplies, personnel and oilfield services, including fracking equipment and crews. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Business — Competition” on page 79 for additional discussion of the competitive environment in which we operate.

The loss of senior management or technical personnel could adversely affect our operations.

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including John Crum, our Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Title to the properties in which we have an interest may be impaired by title defects.

We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. The existence of title deficiencies with respect to our oil and natural gas properties could reduce the value or render such properties worthless, which could have a material adverse effect on our business and financial results. A significant portion of our acreage is undeveloped leasehold acreage, which has a greater risk of title defects than developed acreage. Frequently, as a result of title examinations, certain curative work may be required to correct identified

 

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title defects, and such curative work entails time and expense. Our inability or failure to cure title defects could render some locations undrillable or cause us to lose our rights to some or all production from some of our oil and natural gas properties, which could have a material adverse effect on our business and financial results if a comparable additional location to drill a development well cannot be identified.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

 

   

recoverable reserves;

 

   

future oil and natural gas prices and their appropriate differentials;

 

   

development and operating costs; and

 

   

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

 

   

diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

 

   

the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

 

   

difficulty associated with coordinating geographically separate organizations; and

 

   

the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties

 

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relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

The proposed United States federal budget for fiscal year 2012 and proposed legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations and cash flows.

The Obama administration’s budget proposals for fiscal year 2012 contains numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new fees. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing federal oil and gas leases. Should some or all of these provisions become law our taxes could increase, potentially significantly, after net operating losses are exhausted, which would have a negative impact on our net income and cash flows and could reduce our drilling activities. We do not know the ultimate impact these proposed changes may have on our business.

We are subject to various governmental regulations that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected, and in the future could affect, oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect of these adoptions and interpretations may have on our business or financial condition.

Our business is subject to laws and regulations promulgated by federal, state and local authorities relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government, and third parties and may require us to incur substantial costs of remediation.

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

Our oil and natural gas exploration, production and development operations are subject to stringent federal, regional, state and local laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling, completion and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resulting from our operations. We may be required to make significant capital and operating expenditures or perform remedial or other corrective actions at our wells and

 

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properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general in addition to our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

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

In December 2009, the U.S. Environmental Protection Agency, or EPA, determined that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one regulation that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. In addition, in October 2009, the EPA published rules requiring reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published new regulations amending this GHG reporting rule to include, among other things, certain onshore and offshore oil and natural gas production facilities on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

 

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, which could adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, and has begun the process of drafting guidance documents on regulatory requirements for companies that plan to conduct hydraulic fracturing using diesel. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, or FRAC Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations under certain circumstances. For instance, on October 20, 2011, Louisiana adopted new regulations for hydraulic fracturing operations in the state. These new regulations require hydraulic fracturing operators to publicly disclose the volume of hydraulic fracturing fluid, the type, trade name, supplier and volume of additives, and a list of chemical compounds contained in the additive, along with its maximum concentration, subject to certain trade secret protections. However, even trade secret chemicals will have to be identified by their chemical family. A mandatory disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based upon allegations that specific chemicals used in the fracturing process could adversely affect the environment.

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

 

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If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and attendant permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The United States Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010. This comprehensive financial reform legislation changes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission, or CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In December 2011, the CFTC extended temporary exemptive relief from this deadline for certain regulations applicable to swaps, until no later than July 16, 2012. The CFTC recently promulgated regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated regulations, it is not possible at this time to predict when these regulations will become effective because their effectiveness depends on promulgation of other regulations by the CFTC. The CFTC also has proposed regulations to establish minimum capital requirements, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the Dodd-Frank Act. The Dodd-Frank Act also calls for the establishment of margin requirements and clearing and trade-execution requirements in connection with certain derivative activities. The CFTC has proposed regulations that would impose both initial and variation margin requirements on certain derivatives instruments that are not cleared by a registered derivatives clearing organization, although whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the Dodd-Frank Act is not possible to predict at this time. The legislation and new regulations may also require the counterparties to our commodity derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us.

The new legislation and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral or provide other credit support, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

 

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Risks Relating to the Offering and our Common Stock

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholders and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriting” section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

 

   

our operating and financial performance and drilling locations, including reserve estimates;

 

   

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

   

strategic actions by our competitors;

 

   

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

   

speculation in the press or investment community;

 

   

sales of our common stock by us, the selling stockholders or other stockholders, or the perception that such sales may occur;

 

   

changes in accounting principles;

 

   

additions or departures of key management personnel;

 

   

actions by our stockholders;

 

   

general market conditions, including fluctuations in commodity prices; and

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Investors in this offering will experience immediate and substantial dilution of $         per share.

Based on an assumed initial public offering price of $         per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $         per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and

 

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our as adjusted net tangible book value as of December 31, 2011 after giving effect to this offering would be $         per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. In addition, if the underwriters exercise their option to purchase additional shares from us, investors in this offering will experience additional dilution. See “Dilution” on page 43 for additional information.

We may invest or spend the proceeds of this offering in ways with which you may not agree or in ways which may not yield a return.

The net proceeds from this offering may be used for general corporate purposes, including working capital. Our management will have considerable discretion in the application of the net proceeds, and you will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used appropriately. The net proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, they may be placed in investments that do not produce significant income or that may lose value.

Because we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act of 2002, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

 

   

institute a more comprehensive compliance function;

 

   

design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

 

   

comply with rules promulgated by the NYSE;

 

   

prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

   

establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

   

involve and retain to a greater degree outside counsel and accountants in the above activities; and

 

   

establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee and compensation committee, and qualified executive officers. If our profitability is adversely affected because of these additional costs, it could have a negative effect on the trading price of our common stock.

 

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In connection with certain audits and reviews of our financial statements, our independent registered public accounting firm identified and reported adjustments to management. Certain of such adjustments were deemed to be the result of internal control deficiencies that constituted material weaknesses in our internal control over financial reporting. If one or more material weaknesses recur 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 have been a private company with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment to ensure that the design and execution of our controls has consistently resulted in effective review of our financial statements and supervision by appropriate individuals. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. As a result of these factors, certain material misstatements in our financial statements for periods prior to December 31, 2011 were discovered and brought to the attention of our management by our independent registered public accounting firm for correction. We and our independent registered public accounting firm concluded that these control deficiencies constituted a material weakness in our control environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures” beginning on page 61.

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 public company, we will be required to comply with the SEC’s rules implementing Section 302 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. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act of 2002. Further, our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from making any cash dividends pursuant to the terms of our

 

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revolving credit facility. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes              shares that we and the selling stockholders are selling in this offering (assuming no exercise of the underwriters’ option to purchase additional shares), which may be resold immediately in the public market. Following the completion of this offering and after certain distributions by the selling stockholders, the selling stockholders will own              shares, or approximately     % of our total outstanding shares, and certain of our affiliates will own              shares, or              approximately     % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting” beginning on page 134, but may be sold into the market in the future. We expect that certain stockholders will be parties to a registration rights agreement with us which will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. The holders of the remaining              shares and a small portion of shares owned by our affiliates which will be distributed to non-officer employees and other non-affiliates totaling up to approximately              shares, or approximately     % of our total outstanding shares, are not subject to lock-up agreements and, subject to compliance with Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”), may sell such shares into the public market.

Prior to the completion of this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of              shares of our common stock issued or reserved for issuance under our stock incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements,              shares registered under this registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

Certain of our stockholders, directors and members of our senior management team have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part.                         , at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

 

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First Reserve’s ownership of our common stock and rights under the stockholders’ agreement will limit your ability to influence corporate matters and our board of directors’ ability to manage our business.

Upon completion of this offering (assuming no exercise of the underwriters’ option to purchase additional shares), we anticipate that First Reserve will initially own an approximate     % indirect economic interest in us through FRMI, which will initially own approximately    % of our shares of common stock and will be controlled by First Reserve. Consequently, First Reserve will continue to have significant influence over all matters that require approval by our stockholders, including the election and removal of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

In addition, we, FRMI and certain of our other stockholders have entered into a stockholders’ agreement that permits FRMI to designate certain of our director nominees and prohibits us from engaging in certain transactions without the written consent of FRMI. Pursuant to the stockholders’ agreement, FRMI will initially have the right to designate three of our eight director nominees. Once an additional independent director is appointed to our board of directors, FRMI will continue to have the right to designate two of our director nominees as long as it beneficially owns at least 25% of our outstanding shares of common stock. If FRMI no longer beneficially owns at least 25% of our outstanding shares of common stock, it will continue to have the right to designate one of our director nominees as long as it beneficially owns shares of our common stock. In addition, directors nominated by FRMI may not be removed by our stockholders, even for cause, without the written consent of FRMI. FRMI may assign these designation rights under the stockholders’ agreement to a third party in connection with a transfer of its shares of common stock to such party if such third party purchaser agrees to be bound by the stockholders’ agreement.

The stockholders’ agreement also provides that the following actions by us require the consent of FRMI:

 

   

incurrence of debt that would result in a total net indebtedness to EBITDA ratio in excess of 2.50:1;

 

   

authorization, creation or issuance of any equity securities (other than pursuant to compensation plans approved by the compensation committee or in connection with certain permitted acquisitions);

 

   

redemption, acquisition or other purchase of any securities of the Company (other than certain repurchases from employees and directors);

 

   

amendment, repeal or alteration of our certificate of incorporation or bylaws;

 

   

any acquisition or disposition (where the amount of consideration exceeds $100 million in a single transaction or $200 million in any series of transactions during a calendar year);

 

   

consummation of a “change in control” transaction;

 

   

adoption, approval or issuance of any “poison pill” or similar rights plan; and

 

   

entry into any plan of liquidation, dissolution or winding-up of the Company.

These actions by us require the consent of FRMI until the earlier of (i) receipt by our board of directors of FRMI’s written election to waive its rights, (ii) the date FRMI ceases to hold at least 35% of our outstanding common stock, (iii) the third anniversary of the closing of this offering or (iv) the date on which there are no directors nominated by FRMI serving as members of our board of directors.

 

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As a result of FRMI’s equity ownership, director nominees and consent rights, our ability to engage in financing transactions or other significant transactions, such as a merger, acquisition, disposition or liquidation, may be limited. In connection with such transactions, conflicts of interest could arise between us and FRMI, and any conflict of interest may be resolved in a manner that does not favor us. As a result, our board of directors and management may not be able to manage our business in a manner that it believes is in the best interests of our stockholders.

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

Conflicts of interest could arise in the future between us, on the one hand, and First Reserve and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. First Reserve is a private equity firm in the business of making investments in entities primarily in the global energy sector. As a result, First Reserve’s existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time presented to First Reserve or its affiliates or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or her capacity as our director or officer.

As a result, First Reserve or its affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to First Reserve and its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See “Description of Capital Stock” beginning on page 125.

We will be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and will rely on exemptions from certain corporate governance requirements.

Upon completion of this offering First Reserve and certain of our stockholders, including the Chairman of our board of directors and members of our executive management team, will continue to control a majority of the combined voting power of all classes of our outstanding voting stock and we will be a “controlled company” within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

 

   

a majority of the board of directors consist of independent directors;

 

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the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

 

   

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

 

   

there be an annual performance evaluation of the nominating and corporate governance and compensation committees.

These requirements will not apply to us as long as we remain a “controlled company.” Following this offering, we may utilize some or all of these exemptions. We will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent by the date that our common stock first trades on the NYSE, a majority of members that are independent within 90 days of the effectiveness of the registration statement of which this prospectus forms a part and all members that are independent within one year of the effective date. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus, including the sections entitled “Prospectus Summary,” “Risk Factors,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business,” contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

 

   

business strategy;

 

   

reserves;

 

   

technology;

 

   

cash flows and liquidity;

 

   

financial strategy, budget, projections and operating results;

 

   

oil and natural gas realized prices;

 

   

timing and amount of future production of oil and natural gas;

 

   

availability of drilling and production equipment;

 

   

availability of oilfield labor;

 

   

the amount, nature and timing of capital expenditures, including future development costs;

 

   

availability and terms of capital;

 

   

drilling of wells including our identified drilling locations;

 

   

successful results from our identified drilling locations;

 

   

marketing of oil and natural gas;

 

   

property acquisitions;

 

   

costs of developing our properties and conducting other operations;

 

   

general economic conditions;

 

   

effectiveness of our risk management activities;

 

   

environmental liabilities;

 

   

counterparty credit risk;

 

   

governmental regulation and taxation of the oil and natural gas industry;

 

   

developments in oil-producing and natural gas-producing countries;

 

   

uncertainty regarding our future operating results;

 

   

estimated future net reserves and present value thereof; and

 

   

plans, objectives, expectations and intentions contained in this prospectus that are not historical.

 

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All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus.

These factors include:

 

   

variations in the market demand for, and prices of, oil and natural gas;

 

   

uncertainties about our estimated quantities of oil and natural gas reserves;

 

   

the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;

 

   

access to capital and general economic and business conditions;

 

   

uncertainties about our ability to replace reserves and economically develop our current reserves;

 

   

risks related to the concentration of our operations onshore in central Louisiana;

 

   

drilling results;

 

   

the potential adoption of new governmental regulations; and

 

   

our ability to satisfy future cash obligations and environmental costs.

These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

 

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USE OF PROCEEDS

We expect to receive approximately $         million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering to repay all outstanding indebtedness under our revolving credit facility, redeem preferred units that were previously issued by Midstates Petroleum Holdings LLC to an affiliate of First Reserve and fund our exploration and development program.

We intend to use the following amounts for the above uses:

 

Use of Proceeds

   Amount  

Repayment of revolving credit facility

   $                        

Redeem preferred units that were previously issued by
Midstates Petroleum Holdings LLC to an affiliate of First Reserve

  

Exploration and development program

  
  

 

 

 

Total

   $     

Our revolving credit facility matures in December 2014 and bears interest at a variable rate, which was approximately 3.2% per annum as of December 31, 2011. Our outstanding borrowings under our revolving credit facility were incurred to fund exploration, development and other capital expenditures. While we do not currently have any plans to immediately borrow additional amounts under the revolving credit facility, we may at any time reborrow amounts repaid under the revolving credit facility and expect to do so to fund a portion of our exploration and development program.

The preferred units issued by Midstates Petroleum Holdings LLC to an affiliate of First Reserve bear interest, payable upon redemption, at a variable rate, which was approximately 9.5% per annum as of February 1, 2012. In addition, a fixed interest charge of 1.5% of the aggregate amount of capital contributions made with respect to the preferred units is payable upon redemption. Proceeds from the issuance of the preferred units were used to fund exploration, development and other capital expenditures. In connection with the completion of our corporate reorganization, Midstates Petroleum Holdings LLC will no longer exist as a separate entity and therefore no additional preferred units will be available for issuance. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Preferred Units” beginning on page 58.

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling stockholders.

Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering. Please read “Underwriting  — Conflicts of Interest” beginning on page 138.

DIVIDEND POLICY

We have never declared and paid, and we do not anticipate declaring or paying, any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our revolving credit facility prohibits us from paying dividends other than for tax purposes.

 

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CAPITALIZATION

The following table sets forth the cash and cash equivalents and capitalization of Midstates Petroleum Holdings LLC and Midstates Petroleum Company, Inc., as applicable, as of December 31, 2011:

 

   

on an actual basis;

 

   

on an as adjusted basis to give effect to the transactions described under “Corporate Reorganization” that will occur simultaneously with the closing of this offering; and

 

   

on an as further adjusted basis to give effect to the application of the net proceeds from this offering as set forth under “Use of Proceeds,” assuming an initial public offering price of $         per share (the mid-point of the range set forth on the cover of this prospectus).

You should read the following table in conjunction with “Use of Proceeds,” “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto appearing elsewhere in this prospectus.

 

     As of December 31, 2011  
     Actual      As
Adjusted
     As
Further
Adjusted
 
     (in thousands)  

Cash and cash equivalents

   $ 7,344       $ 7,344       $                

Long-term debt, including current maturities:

        

Revolving credit facility (1)

     234,800         234,800      
  

 

 

    

 

 

    

 

 

 

Total long-term debt (2)

     234,800         234,800      
  

 

 

    

 

 

    

 

 

 

Members’ equity / stockholders’ equity:

        

Members’ equity

     285,502                   

Common stock, $0.01 par value; no shares authorized, issued and outstanding (actual);              shares authorized (as adjusted and as further adjusted);              shares issued and outstanding (as adjusted);             shares issued and outstanding (as further adjusted)

             

Preferred stock, $0.01 par value; no shares authorized (actual); shares authorized (as adjusted and as further adjusted); no shares issued and outstanding

                       

Additional paid-in capital

             

Retained earnings (accumulated loss)

             

Total members’ / stockholders’ equity

     285,502         
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 520,302       $         $                
  

 

 

    

 

 

    

 

 

 

 

(1) As of February 1, 2012, we had $234.8 million of indebtedness outstanding under our revolving credit facility. We intend to repay in full all amounts outstanding under our revolving credit facility with a portion of the net proceeds from this offering.
(2) As of February 1, 2012, Midstates Petroleum Holdings LLC had $20.0 million of preferred units outstanding. We intend to redeem all preferred units outstanding with a portion of the net proceeds from this offering.

 

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of December 31, 2011, after giving pro forma effect to the transactions described under “Corporate Reorganization,” was approximately $         million, or $         per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering including giving effect to our corporate reorganization. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of December 31, 2011 would have been approximately $         million, or $         per share. This represents an immediate increase in the net tangible book value of $         per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $         per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

 

Assumed initial public offering price per share

      $                

Pro forma net tangible book value per share as of December 31, 2011 (after giving effect to our corporate reorganization)

   $                   
  

 

 

    

Increase per share attributable to new investors in this offering

     

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering

     
     

 

 

 

Dilution in pro forma net tangible book value per share to new investors in this offering

      $                
     

 

 

 

The following table summarizes, on an adjusted pro forma basis as of December 31, 2011, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $            , the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions:

 

     Shares Acquired     Total Consideration     Average
Price Per
Share
 
     Number    Percent     Amount      Percent    

Existing stockholders (1)

               $                             $                

New investors (2)

                          
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Total

               $                             $                
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

 

(1) The number of shares disclosed for the existing stockholders includes              shares being sold by the selling stockholders in this offering.
(2) The number of shares disclosed for the new investors does not include the              shares being purchased by the new investors from the selling stockholders in this offering.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

You should read the following selected financial data in conjunction with “Capitalization,” “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Set forth below is (i) our selected historical consolidated financial data as of and for the years ended December 31, 2011, 2010 and 2009, which has been derived from our audited consolidated financial statements included elsewhere in this prospectus, and as of and for the period from August 30, 2008 through December 31, 2008, which has been derived from our audited consolidated financial statements not included elsewhere in this prospectus; (ii) selected historical consolidated financial data for the period from January 1 to August 29, 2008 of Midstates Petroleum Corporation, our accounting predecessor, which has been derived from the audited financial statements of Midstates Petroleum Corporation not included elsewhere in this prospectus; and (iii) selected historical consolidated financial data as of and for the year ended December 31, 2007 of Midstates Petroleum Corporation, which has been derived from the unaudited consolidated financial statements of Midstates Petroleum Corporation not included elsewhere in this prospectus.

 

    Successor          Predecessor  
    Year Ended
December 31,
    Period from
August 30 to
December 31,
2008
         Period from
January 1 to
August 29,
2008
    Year Ended
December 31,
 
    2011     2010     2009           2007  
          (in thousands)                     

(unaudited)

 

Statement of operations data

               

Oil, gas and natural gas liquids revenues

  $ 213,812      $ 89,111      $ 30,133      $ 8,689          $ 27,458      $ 14,647   

Gains (losses) on commodity derivative contracts - net

    (4,844     (26,268     (5,987     14,062            (7,678     (5,363

Other revenue

    465        209        108        43            113        234   
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Total revenues

    209,433        63,052        24,254        22,794            19,893        9,518   
 

Expenses:

               

Lease operating

    15,234        8,733        5,312        1,542            2,769        1,954   

Workover

    2,101        4,683        5,226        2,376            2,206        1,777   

Severance tax

    12,422        6,431        2,849        805            2,354        1,258   

Asset retirement accretion

    334        175        120        37            79        113   

General and administrative

    27,970        16,847        5,886        1,402            1,816        1,616   

Depreciation, depletion and amortization

    91,699        41,827        12,322        2,995            3,117        3,503   

Impairment in carrying value of oil and gas properties

                  4,297        26,776                     
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Total expenses

    149,760        78,696        36,012        35,933            12,341        10,221   
 

Income (loss) from operations

    59,673        (15,644     (11,758     (13,139         7,552        (703
 

Other income (expense):

               

Interest income

    23        9        6        7            12        34   

Interest expense - net of amounts capitalized

    (2,094                              (854     (1,100
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

Net income (loss)

  $ 57,602      $ (15,635   $ (11,752   $ (13,132       $ 6,710      $ (1,769
 

 

 

   

 

 

   

 

 

   

 

 

       

 

 

   

 

 

 

 

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    Successor          Predecessor  
    As of December 31,     Period from
August 30 to
December 31,
2008
         As of
December 31,
 
    2011     2010     2009         2007  
          (in thousands)            

(unaudited)

 

Balance sheet data:

             

Cash and cash equivalents

  $ 7,344      $ 11,917      $ 4,353      $ 3,214          $ 1,000   

Net property and equipment

    574,079        397,126        271,726        209,939            30,640   

Total assets

    624,656        427,004        284,034        222,074            35,447   

Long-term debt (1)

    234,800        89,600        29,800        21,800            20,100   

Total members’/stockholders’ equity

    285,502        255,879        235,334        192,006            2,510   

 

    Successor          Predecessor  
    Year Ended December 31,     Period from
August 30 to
December 31,
2008
         Period from
January 1 to
August 29,
2008
    Year Ended
December 31,
 
    2011     2010     2009           2007  
          (in thousands)            

(unaudited)

 

Other financial data:

               

Net cash provided by operating activities

  $ 140,700      $ 50,768      $ 10,595      $ 3,670          $ 10,046      $ 7,429   

Net cash used in investing activities

    (242,771     (139,618     (75,215     (5,451         (9,480     (15,709

Net cash provided by financing activities

    97,498        96,414        65,759        4,995            1,792        8,275   

 

(1) As of February 1, 2012, Midstates Petroleum Holdings LLC had $20.0 million of preferred units outstanding. We intend to redeem all preferred units outstanding with a portion of the net proceeds from this offering.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that are based on management’s current expectations, estimates and projections about our business and operations, and involves risks and uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and elsewhere in this prospectus.

Overview

We are an independent exploration and production company focused on the development of oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. Our current acreage positions and evaluation efforts are concentrated in the Wilcox interval of the trend. We are currently focused on the development of our significant inventory of identified drilling locations, to which we will selectively allocate capital by applying rigorous investment analysis in an effort to maximize our potential returns. We are focused on maximizing the net present value of our drilling opportunities by measuring risk and financial return, among other factors. In addition, we are the operator of the substantial majority of our properties, which enables us to better control timing, costs and drilling and completion techniques. As of December 31, 2011, our properties consisted of approximately 92 gross active producing wells, 95% of which we operate, and in which we held an average working interest of approximately 99% across our 77,100 net acre leasehold.

As of December 31, 2011, our estimated net proved reserves were 26.2 MMBoe, of which 75% was oil or NGLs and 43% was proved developed. During December 2011, our properties had aggregate average net daily production of approximately 9,897 Boe per day.

All of our growth has been driven through the development of our leasehold acreage. We initiated operations in 1993 in our North Cowards Gully project area and slowly aggregated leasehold acreage in that project area and others over the next eighteen years. In August 2008, First Reserve acquired a majority interest in us and, along with members of our senior management, provided a significant amount of growth capital to expand our exploration and development program. As a result of this increase in capital available for our operations, we have increased our average daily production at a compound annual growth rate of 101% from 1,024 Boe/d in the month ended September 30, 2008 to 9,897 Boe/d in the month ended December 31, 2011. Our current activities are focused on evaluating and developing our asset base, optimizing our acreage position, and identifying potential expansion areas across the trend.

Factors that Significantly Affect our Results

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we

 

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expect to reduce some of the variability in our cash flow from operations. See “Liquidity and Capital Resources – Commodity Derivative Contracts” beginning on page 59 and “Quantitative and Qualitative Disclosures About Market Risk – Commodity price exposure” beginning on page 62 for discussion of our hedging and hedge positions.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost of such capital and operational considerations.

The volumes of oil and natural gas that we produce are driven by several factors, including:

 

   

success in the drilling of new wells, including exploratory wells, and the recompletion of existing wells;

 

   

the amount of capital we invest in the leasing and development of our oil and natural gas properties;

 

   

facility or equipment availability and unexpected downtime;

 

   

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

 

   

the rate at which production volumes on our wells naturally decline.

The following table sets forth summary data with respect to our production volumes for the periods presented:

 

    Year Ended
December 31,
 
    2011     2010     2009  

Production data:

     

Oil (MBbls)

    1,610        945        497   

Natural gas (MMcf)

    4,918        2,253        690   

Natural gas liquids (MBbls)

    308        74        2   

Oil equivalents (MBoe)

    2,737        1,394        614   

Average daily production (Boe/d)

    7,499        3,820        1,682   

Growth Drivers 2012 and Beyond

We intend to drill and develop our current acreage position in the oil-prone portion of the Upper Gulf Coast Tertiary trend to maximize the value of our resource potential. We also plan to increase our leasehold position in the trend. We have identified an inventory of 600 gross vertical drilling locations on our current leased acreage position that we believe will increase our reserves, production and cash flow. We have identified approximately 40 additional geologic structures throughout the trend that we believe have characteristics similar to our existing operating areas and we are actively pursuing the

 

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increase of our acreage position through leasing in these areas. In addition to increasing our acreage position through leasing, we may selectively pursue potential acquisitions of strategic assets or operating companies in the trend. Over time, we also expect to selectively target additional onshore basins in North America that would allow us to extend our competencies to large undeveloped acreage positions in hydrocarbon trends similar to our existing core area.

Our total 2011 capital expenditures were $264 million and we drilled or spud 32 wells. Our total 2012 capital expenditure budget is $380 million, approximately 17% of which will be spent developing acreage currently under lease in our expansion areas. Our 2012 budget consists of:

 

   

$306 million for drilling and completion capital;

 

   

$58 million for acquisition of acreage and seismic data; and

 

   

$16 million in unallocated funds which are available for facilities.

While we have budgeted $380 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results as the year progresses.

Basis of Presentation

On August 29, 2008, First Reserve purchased an approximate 72% interest in Midstates Petroleum Holdings LLC (the “FR Investment”). For financial reporting purposes, the FR Investment was accounted for as a purchase and resulted in a new basis of accounting reflecting estimated fair values for 100% of our assets and liabilities that were recorded at their estimated fair value as of the closing date, based on the purchase price paid in the transaction. Accordingly, the financial statements for periods subsequent to August 29, 2008, are presented on Midstates Petroleum Holdings LLC’s new basis of accounting giving effect to the transaction. Including its initial investment in August 2008, First Reserve has acquired an approximate 77% aggregate equity interest in Midstates Petroleum Holdings LLC.

Sources of Our Revenues

Oil, natural gas and natural gas liquids. Our revenues are derived from the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from our high Btu content natural gas. Our oil and gas revenues do not include the effects of derivatives, and may vary significantly from period to period as a result of changes in production volumes or commodity prices.

Realized and unrealized gain (loss) on commodity derivative financial contracts. We utilize commodity derivatives to reduce our exposure to fluctuations in the prices of oil. In addition, we utilize derivatives to help mitigate our exposure to fluctuations in Louisiana Light Sweet (“LLS”) oil prices as compared to West Texas Intermediate (“NYMEX WTI”) benchmark oil prices. Accordingly, our income statements reflect (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivatives contracts expire or new ones are entered into, and (ii) our realized gains or losses on the settlement of these commodity derivative contracts. Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized losses are recognized. Conversely, if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized. Since we have elected not to apply hedge accounting to our derivatives, we reflect the unrealized and realized gains and losses in our current income statement periods based on the mark-to-market value at the end of each month. Cash flows associated with derivative financial instruments are reflected in cash flow from operations in our consolidated statement of cash flows.

 

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Commodity prices. Our revenues are heavily influenced by commodity prices, which are subject to wide fluctuations in response to changes in supply and demand. For a description of factors that may impact future commodity prices, please read “Risk Factors — Risks Related to the Oil and Natural Gas Industry and Our Business” beginning on page 17.

The table below sets forth the prices we received per unit of volume for our oil, natural gas, and NGLs, both including and excluding the effects of our commodity derivative contracts.

 

     Year Ended December 31,  
     2011      2010      2009  

Average sales prices:

        

Oil, without realized derivatives ($/Bbl)

   $ 110.25       $ 80.29       $ 55.07   

Oil, with realized derivatives ($/Bbl)

     100.26         79.37         57.69   

Natural gas liquids, without realized derivatives ($/Bbl)

     50.98         36.92         47.66   

Natural gas, without realized derivatives ($/Mcf)

     4.20         4.66         3.89   

In general, differentials are adjustments to the benchmark price for oil based on grade and location of the sales point. All of our oil is sold at the market price for LLS, which has recently traded at a significant premium to NYMEX WTI prices. Our oil production benefits from higher pricing differentials relative to many other oil producers in other areas of North America. For example, for the three months ended December 31, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $115.46 per Bbl, compared to an average NYMEX WTI settlement price of $94.06 per Bbl for the same time period. In addition, our gas production benefits from relatively rich Btu content. As a result of natural gas processing, we benefit from an overall higher realized pricing relative to the Henry Hub benchmark. For example, for the year ended December 31, 2011, the average realized price for our gas production was $4.20 per Mcf, compared to an average Henry Hub settlement price of $4.00 per MMBtu for the same period.

Other revenue. Other revenue consists of income derived from the recovery of administrative overhead, gas compression charges and saltwater disposal fees from third parties for their share of costs on company owned assets.

Our Expenses

Lease operating expenses. These are daily costs incurred to bring oil and gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include natural gas transportation and treating expenses, as well as maintenance and repair expenses related to our oil and gas properties. Lease operating expenses include both a portion of costs that are fixed in nature, such as infrastructure costs, as well as variable costs resulting from additional wells and production. As production increases, our average lease operating expense per barrel of oil equivalent is typically reduced because fixed costs do not increase proportionately with production. Ad valorem taxes are property taxes assessed based on the value of property and are also included in our lease operating expenses.

Workover expense. Workover expense includes major remedial operations on a completed well to restore, maintain, or improve a well’s production and is closely correlated to the levels of workover activity. Because workover projects are pursued on an as needed basis and are not regularly scheduled, workover expense is not necessarily comparable from period to period.

Severance taxes. Severance taxes are paid on produced oil and gas based on a percentage of revenues from products sold at market prices or at fixed rates established by federal, state, or local taxing authorities. We attempt to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the severance taxes we pay correlate to the changes in oil and gas revenues.

 

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Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and systematically expense those costs on a unit of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties for which proved reserves have not yet been assigned, less accumulated amortization; (ii) estimated future expenditures to be incurred in developing proved reserves; and (iii) estimated dismantlement and abandonment costs.

Impairment of oil and gas properties/Ceiling test. Our historical policy as a privately-owned company has been to perform a ceiling test on an annual basis, and we performed a ceiling test at December 31, 2011, 2010 and 2009. However, we will apply Rule 4-10 of Regulation S-X going forward, which requires the ceiling test to be performed on at least a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price we received as of the first trading day of each month over the preceding twelve months (such average price is held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

General and administrative expense. General and administrative expense consists of overhead, including payroll and benefits for our corporate staff, non-cash charges for share-based compensation, costs of maintaining our headquarters, franchise taxes, audit and other professional fees and legal compliance. General and administrative expenses related to being a publicly traded company will include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with listing on the NYSE; legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs; and director compensation. As a publicly-traded company at the closing of this offering, we expect that our general and administrative expenses will increase.

Certain of our employees hold units in Midstates Incentive Holdings LLC that entitle the holders to a portion of the proceeds to be received by First Reserve upon sales of our common stock by FRMI. Any payments with respect to these units will only occur if and when First Reserve achieves certain minimum return hurdles (defined as certain multiples of First Reserve’s capital contributions plus investment expenses) on its investment through the sale of its shares of common stock. While these proceeds will not involve any cash payment by us, we will recognize a non-cash compensation expense, which may be material, in the period such payment is made. In addition, certain of our employees held shares of restricted stock in Midstates Petroleum Holdings, Inc. which vested on November 22, 2011. As a result of the vesting of such shares of restricted stock, we recognized a non-cash compensation expense of $9.2 million in the fourth quarter of 2011. See Note 7 to our audited financial statements for the year ended December 31, 2011.

Interest expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facility in interest expense.

 

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We capitalize a portion of our interest costs on unproved properties. Capitalized interest is depreciated over the useful life of assets in the same manner as the depreciation of the underlying assets.

Income Taxes. Midstates Petroleum Holdings LLC has historically not been subject to U.S. federal and certain state income taxes. After consummation of this offering, Midstates Petroleum Company, Inc. will become subject to U.S. federal, state, local and foreign income taxes and taxed at the prevailing corporate tax rates.

Results of Operations

The following table summarizes our revenues and production data for the period indicated.

 

     Year Ended December 31,  
         2011         2010     2009  
    

(in thousands except for operating
data)

 

Revenues:

      

Oil

   $ 177,464      $ 75,875      $ 27,347   

Natural gas

     20,665        10,505        2,683   

Natural gas liquids

     15,683        2,731        103   

Losses on commodity derivative contracts - net

     (4,844     (26,268     (5,987

Other

     465        209        108   
  

 

 

   

 

 

   

 

 

 

Total revenues

   $ 209,433      $ 63,052      $ 24,254   
  

 

 

   

 

 

   

 

 

 

Operating Expenses:

      

Lease operating (1)

   $ 15,234      $ 8,733      $ 5,312   

Workover

     2,101        4,683        5,226   

Severance taxes

     12,422        6,431        2,849   

Asset retirement accretion

     334        175        120   

General and administrative

     27,970        16,847        5,886   

Depreciation, depletion and amortization

     91,699        41,827        12,322   

Impairment in the carrying value of oil and gas properties

                   4,297   
  

 

 

   

 

 

   

 

 

 

Total expenses

   $ 149,760      $ 78,696      $ 36,012   
  

 

 

   

 

 

   

 

 

 

Other Income (Expense):

      

Interest income

     23        9        6   

Interest expense - net of amounts capitalized

     (2,094              
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 57,602      $ (15,635   $ (11,752
  

 

 

   

 

 

   

 

 

 

Production data:

      

Oil (MBbls)

     1,610        945        497   

Natural gas (MMcf)

     4,918        2,253        690   

Natural gas liquids (MBbls)

     308        74        2   

Oil equivalents (MBoe)

     2,737        1,394        614   

Average daily production (Boe/d)

     7,499        3,820        1,682   

Average sales prices:

      

Oil, without realized derivatives (per Bbl)

   $ 110.25      $ 80.29      $ 55.07   

Oil, with realized derivatives (per Bbl)

     100.26        79.37        57.69   

Natural gas (per Mcf)

     4.20        4.66        3.89   

Natural gas liquids (per Bbl)

     50.98        36.92        47.66   

 

(1) Includes ad valorem taxes of $1,218,000, $555,000 and $210,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGLs sales revenues increased by $124.7 million, or 140%, to $213.8 million during the year ended December 31, 2011 as compared to $89.1 million for the year ended December 31, 2010. Our revenues are a function of oil, natural gas, and NGLs production volumes sold and average sales prices received for those volumes. Of the $124.7 million revenue variance, sales volume increases contributed $74.4 million of the total, while price variance contributed $50.3 million. Average daily production sold increased by 3,679 Boe per day, or 96%, to 7,499 Boe per day during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in average daily production sold was primarily due to increased drilling activity resulting in 31 additional producing wells in operation during 2011 as compared to the prior year period. Average oil sales prices, without realized derivatives, increased by $29.96 per barrel, or 37%, to $110.25 per barrel for the year ended December 31, 2011 as compared to $80.29 per barrel for the year ended December 31, 2010.

Losses on commodity derivative contractsnet. Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $25.4 million as of December 31, 2010 to an unrealized gain of $11.9 million as of December 31, 2011. The MTM change results from higher average hedge volumes and prices on December 31, 2011 compared to the open positions on December 31, 2010. The NYMEX WTI closing price on December 30, 2011 (the last trading day of 2011) was $98.83 per barrel compared to a closing price of $91.38 per barrel on December 31, 2010. The realized loss on derivatives for the year ended December 31, 2011 was $16.7 million compared to a realized loss of $0.9 million for the year ended December 31, 2010. The loss for the year ended December 31, 2011 was a result of realized oil prices rising substantially for the year versus the prices at which we had oil production hedged for the period. Realized oil sales prices, without realized derivatives, averaged $110.25 per barrel for the year ended December 31, 2011 compared with $80.29 per barrel for the year ended December 31, 2010.

Expenses.

Lease operating expenses. Lease operating expenses increased $6.5 million, or 74%, to $15.2 million for the year ended December 31, 2011 compared to $8.7 million for the year ended December 31, 2010. This increase was primarily due to 31 additional producing wells in operation during the period, which resulted in additional salt water disposal costs of $2.9 million, additional compression charges of $0.8 million, additional gas dehydration and chemical costs of $1.0 million, with the remaining variance primarily attributable to increases in labor related costs. Lease operating expenses decreased to $5.57 per Boe at December 31, 2011 from $6.26 per Boe at December 31, 2010, a decrease of 11%. This decrease was primarily a result of the 162% increase in production volumes from the year ended December 31, 2010 to the year ended December 31, 2011, without a commensurate increase in fixed costs.

Workover expenses. Workover expenses decreased $2.6 million, or 55%, to $2.1 million for the year ended December 31, 2011 compared to $4.7 million for the year ended December 31, 2010. Workover expenses decreased to $0.77 per Boe at December 31, 2011 from $3.36 per Boe at December 31, 2010, a decrease of 77%. This decrease in workover expense per Boe was a result of both lower workover activity in the year ended December 31, 2011, which equated to a reduction of $0.94 per Boe and the previously described substantial growth in production volumes between the two periods, which equated to a reduction of $1.65 per Boe.

Severance taxes. Severance taxes increased $6 million, or 93%, to $12.4 million for the year ended December 31, 2011 as compared to $6.4 million for the year ended December 31, 2010. This increase was primarily attributable to higher oil, natural gas and NGLs sales revenue during the 2011 period. Our severance taxes for the year ended December 31, 2011 and 2010 were 5.8% and 7.2%, respectively, as a percentage of oil, natural gas and NGLs sales revenue. The severance tax rate for

 

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the year ended December 31, 2011 was lower than the severance tax rate for the year ended December 31, 2010 due to an increase in production on wells qualifying for severance tax exemptions, which reduced 2011 severance tax expense by approximately $0.9 million.

Depreciation, depletion and amortization (DD&A). Depreciation, depletion and amortization expense increased $49.9 million, or 119%, to $91.7 million for the year ended December 31, 2011 compared to $41.8 million for the year ended December 31, 2010. The DD&A rate for the year ended December 31, 2011 was $33.50 per Boe compared to $30.00 per Boe for the year ended December 31, 2010. The increase in DD&A expense for the year ended December 31, 2011 was primarily due to the higher capital expenditures related to increased drilling and completion activities during the year, which resulted in a higher amortization base, and increased oil, natural gas and NGLs production, partially offset by the impact of higher total proved reserves.

General and administrative. Our general and administrative expenses increased to $28.0 million for the year ended December 31, 2011 from $16.8 million for the year ended December 31, 2010. The increase in general and administrative expenses of $11.2 million, or 66%, was primarily due to the expenses related to share-based compensation, which included a $12.8 million non-cash charge for share-based compensation for the year ended December 31, 2011, compared to a $1.5 million non-cash charge for the year ended December 31, 2010. Share-based compensation expense for the year ended December 31, 2011 included $9.2 million in expense related to the accelerated vesting in November 2011 of restricted stock of one of our affiliates held by certain of our employees, as well as $3.6 million attributable to the change in fair value of certain equity awards accounted by the Company as liability awards up to December 5, 2011. (See “Notes to Consolidated Financial Statements—Note 7—Member’s Equity and Share-Based Compensation”). As of December 31, 2011, we had 51 full-time employees as compared to 43 employees as of December 31, 2010. The additional expenses related to the increase in headcount and professional fees paid to contractors of approximately $1.9 million, were offset by approximately $2.4 million less being paid in employee bonuses between periods.

Interest expense. Interest expense for the year ended December 31, 2011 and December 31, 2010 was $4.7 million and $1.7 million, respectively. The increase in interest expense is primarily due to the increase in outstanding balances under our revolving credit facility, resulting in an additional $2.7 million of interest expense and an increase in our interest rate, which increased such expense by $0.3 million. Of total interest expenses, $2.6 million and $1.7 million were capitalized, resulting in $2.1 million and no interest expenses for the years ended December 31, 2011 and 2010, respectively.

Year Ended December 31, 2010 as Compared to the Year Ended December 31, 2009

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGLs sales revenues increased by $59 million, or 196%, to $89.1 million during the year ended December 31, 2010 as compared to $30.1 million for the year ended December 31, 2009. Of the $59 million revenue variance, sales volume increases contributed $34.2 million of the total, while price variance contributed $24.8 million. Average daily production sold increased by 2,139 Boe per day, or 127%, to 3,820 Boe per day during the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in average daily production sold was primarily due to the increased drilling activity in 2010 versus 2009. Average oil sales prices, without realized derivatives, increased by $25.22 per barrel or 46% to $80.29 per barrel for the year ended December 31, 2010 as compared to $55.07 per barrel the year ended December 31, 2009.

Gains (losses) on commodity derivative contracts — net. Our MTM derivative unrealized loss increased from $7.3 million as of December 31, 2009 to an unrealized loss of $25.4 million as of December 31, 2010. The MTM change results from the increase in NYMEX WTI prices between these two dates and the open volume hedge positions at the end of each period at prices lower than NYMEX

 

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WTI. The NYMEX WTI closing price on December 31, 2010 was $91.38 per barrel while the same price for December 31, 2009 was $79.36 per barrel. The realized loss on derivatives for the year ended December 31, 2010 was $0.9 million compared to a realized gain of $1.3 million for the year ended December 31, 2009. The loss for the year ended December 31, 2010 was a result of realized oil prices rising substantially for the year versus the prices at which we had oil production hedged for the period. Realized oil sales prices averaged $80.29 per barrel for the year ended December 31, 2010 compared with $55.07 per barrel for the year ended December 31, 2009.

Expenses.

Lease operating expenses. Lease operating expenses increased $3.4 million, or 64%, to $8.7 million for the year ended December 31, 2010 compared to $5.3 million for the year ended December 31, 2009. This increase was primarily due to the increase in our number of operating wells during 2010 versus 2009, which led to additional surface maintenance costs of $1.0 million, additional compression charges of $0.6 million, additional gas dehydration and chemical costs of $0.5 million, and the remainder from saltwater disposal and increases in labor related costs. Lease operating expenses decreased to $6.26 per Boe at December 31, 2010 from $8.66 per Boe at December 31, 2009, a decrease of 28%. This decrease was primarily a result of the 127% increase in production volumes from the year ended December 31, 2009 to the year ended December 31, 2010.

Workover expenses. Workover expenses decreased $0.5 million, or 10%, to $4.7 million for the year ended December 31, 2010 compared to $5.2 million for the year ended December 31, 2009. This decrease was primarily due to fewer workovers on our active wells and better cost control. Workover expenses decreased to $3.36 per Boe at December 31, 2010 from $8.51 per Boe at December 31, 2009, a decrease of 61%. This decrease was primarily a result of the 127% increase in production volumes from the year ended December 31, 2009 to the year ended December 31, 2010 and equated to $4.77 per Boe of the total $5.16 per Boe reduction. Fewer workovers and cost control contributed to the remaining $0.39 per Boe reduction.

Severance taxes. Severance taxes increased $3.5 million, or 125%, to $6.4 million for the year ended December 31, 2010 compared to $2.8 million for the year ended December 31, 2009 primarily due to an increase in production during the same periods, which accounted for $4.2 million of the increase. Our severance taxes for the year ended December 31, 2010 and 2009 were 7.2% and 9.5%, respectively, as a percentage of oil, natural gas and NGLs revenues. The severance tax rate for the year ended December 31, 2010 was lower than the severance tax rate for the year ended December 31, 2009 due to an increase in production on wells qualifying for severance tax exemptions, which reduced severance taxes by approximately $0.7 million in 2010.

Depreciation, depletion and amortization (DD&A). Depreciation, depletion and amortization expense increased $29.5 million, or 239%, to $41.8 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. The increase in DD&A expense for the year ended December 31, 2010 was primarily due to both increased production volumes and an increase in the DD&A rate. The DD&A rate for the year ended December 31, 2010 was $30.00 per Boe compared to $20.08 per Boe for the year ended December 31, 2009. This increase in the DD&A rate was due to an increase in capital expenditures without proportional associated proved reserve additions being booked within the period.

Impairment of oil and gas properties/Ceiling test. During the year ended December 31, 2010, we did not record a non-cash impairment charge. For the year ended December 31, 2009, we recorded non-cash impairment charges of $4.3 million as a result of net capitalized costs exceeding the ceiling limit calculated from the reserves data. In determining the amount of the non-cash impairment charges for such periods, we considered the application of the factors described under “— Critical Accounting Policies and Estimates — Impairment of oil and gas properties/Ceiling test.”

 

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General and administrative. Our general and administrative expenses increased to $16.8 million for the year ended December 31, 2010 from $5.9 million for the year ended December 31, 2009, resulting in a change of $10.9 million, or 186%. In the year ended December 31, 2010, we incurred employee bonuses of approximately $4.9 million. In addition, our general and administrative expenses included a $1.5 million non-cash charge for stock-based compensation expense for the year ended December 31, 2010, compared to a $0.2 million non-cash charge for the year ended December 31, 2009. The increase in general and administrative expenses was primarily due to a $4.8 million increase in employee bonuses, a $4.8 million increase in expenses due to the addition of a significant number of employees to support our growth and a $1.3 million increase in expenses related to share-based compensation.

Interest expense. Interest costs for the years ended December 31, 2010 and 2009 were $1.7 million and $0.8 million, respectively. The $0.9 million increase in interest cost is primarily a result of a $1.0 million increase in outstanding balances under our revolving credit facility partially offset by $0.1 million from a reduction in interest rates. Of the total interest cost, all of the $1.7 million and $0.8 million were capitalized for the years ended December 31, 2010 and 2009.

Liquidity and Capital Resources

Giving effect to the completion of this offering, our liquidity as of December 31, 2011 would have been $         million, consisting of $         million available under our revolving credit facility and $         million in cash and cash equivalents. Our primary sources of liquidity to date have been equity provided by First Reserve and our management team, borrowings under our revolving credit facility and cash flows from operations. Our primary use of capital has been the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt capital markets, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our total 2011 capital expenditures were $264 million, which consisted of:

 

   

$227 million for drilling and completion capital;

 

   

$27 million for acquisition of acreage and seismic data; and

 

   

$10 million in unallocated funds which are available for facilities.

Our total 2012 capital expenditure budget is $380 million, which consists of:

 

   

$306 million for drilling and completion capital;

 

   

$58 million for acquisition of acreage and seismic data; and

 

   

$16 million in unallocated funds which are available for facilities.

While we have budgeted $380 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. We believe the net proceeds from this offering together with cash flows from operations and additional borrowings under our revolving credit facility should be more than sufficient to fund our 2012 capital expenditure budget and a portion of our 2013 capital expenditure budget. However, because wells funded by our 2012 future drilling plan represent only a small percentage of our gross identified operated drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “Risk Factors — Risks Related to the Oil and Natural Gas Industry and Our Business — A

 

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substantial or extended decline in oil and, to a lesser extent, natural gas, prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments” on page 17 and “— Quantitative and Qualitative Disclosures About Market Risk” beginning on page 62.

We review leasehold acquisition opportunities on an ongoing basis. In addition, we may selectively pursue the acquisition of businesses that may be complimentary to ours. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Our cash flows for the years ended December 31, 2011, 2010 and 2009 and are presented below:

 

    Year Ended December 31,  
    2011     2010     2009  
    (in thousands)  

Net cash provided by operating activities

  $ 140,700      $ 50,768      $ 10,595   

Net cash used in investing activities

    (242,771     (139,618     (75,215

Net cash provided by financing activities

    97,498        96,414        65,759   
 

 

 

   

 

 

   

 

 

 

Net change in cash

  $ (4,573)      $ 7,564      $ 1,139   
 

 

 

   

 

 

   

 

 

 

Cash flows provided by operating activities

Net cash provided by operating activities was $140.7 million, $50.8 million and $10.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. The increases in net cash provided by operating activities for the year ended December 31, 2011 compared to the year ended December 31, 2010 and for the year ended December 31, 2010 compared to the year ended December 31, 2009 were primarily the result of an increase in oil, natural gas, and NGLs production as well as an increase in realized oil prices.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “— Quantitative and Qualitative Disclosures About Market Risk” beginning on page 62.

Cash flows used in investing activities

We had net cash used in investing activities of $242.8 million, $139.6 million and $75.2 million during the years ended December 31, 2011, 2010 and 2009, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increases in net cash used in investing activities during the year ended December 31, 2011 compared to the year ended December 31, 2010 and during the year ended December 31, 2010 compared to the year ended December 31, 2009 were attributable to continued expansion of our drilling programs and growth of our business.

We expect our 2012 capital expenditure budget to be $380 million, which is a 44% increase over the $264 million incurred for 2011. Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term

 

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cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Cash flows provided by financing activities

Net cash provided by financing activities was $97.5 million, $96.4 million and $65.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. For these periods and years, cash sourced through financing activities was provided primarily by First Reserve and members of our management and borrowings under our revolving credit facility. Our long-term debt was $234.8 million, $89.6 million and $29.8 million at December 31, 2011, 2010 and 2009, respectively.

Reserve-based credit facility

As of December 31, 2011, we had a $300 million reserve-based revolving credit facility with a borrowing base of $235 million. The facility matures in December 2014. The borrowing base under our revolving credit facility will be subject to redetermination on a semi-annual basis, effective September 1 and March 1, beginning September 1, 2011, and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent, acting at the direction of lenders holding at least two-thirds of the outstanding loans and other obligations. The borrowing base will be determined by the lenders in good faith and consistent with their usual and customary oil and gas lending criteria in existence at that particular time. Our revolving credit facility is available for general corporate purposes, including, without limitation, working capital for exploration and production operations. In addition, in the event we elect to issue senior unsecured notes, the borrowing base will reduce by 25% of the aggregate principal amount of such notes. Our obligations under our revolving credit facility are secured by substantially all of our assets. Our credit agreement is filed as an exhibit to the registration statement of which this prospectus is a part.

As of February 1, 2012, we had $234.8 million outstanding under our revolving credit facility. In the year ended December 31, 2011, the average amount outstanding under our revolving credit facility was $147.3 million. We anticipate that a portion of the net proceeds from this offering will be used to repay all of our borrowings outstanding as of the closing.

At our election, interest is generally determined by reference to:

 

   

the London interbank offered rate, or LIBOR, plus an applicable margin between 2.00% and 2.75% per annum; or

 

   

the higher of (x) a domestic bank prime rate, (y) the federal funds rate plus 0.50% and (z) one-month LIBOR plus 1.00%, plus an applicable margin between 1.00% and 1.75% per annum.

Interest is generally payable quarterly for domestic bank rate loans and on the last day of the applicable interest period for LIBOR loans, but not less frequently than quarterly.

Our revolving credit facility contains various covenants that limit our ability to:

 

   

incur indebtedness;

 

   

grant certain liens;

 

   

make certain loans, advances and investments;

 

   

make dividends, distributions or redemptions;

 

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merge or consolidate;

 

   

engage in certain asset dispositions, including a sale of all or substantially all of our assets;

 

   

enter into certain sale or leaseback arrangements;

 

   

enter into certain transactions with affiliates;

 

   

grant negative pledges or agree to restrict dividends or distributions from subsidiaries;

 

   

allow gas imbalances, take-or-pay or other prepayments with respect to oil and gas properties that would require us to deliver hydrocarbons in the future without then or thereafter receiving full payment therefor; or

 

   

enter into certain derivative arrangements.

Our revolving credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

 

   

a current ratio, consisting of consolidated current assets, including the unused amount of the total commitments and any letters of credit issued for the benefit of the lenders, to consolidated current liabilities, of not less than 1.0 to 1.0, excluding non-cash derivative assets and liabilities, as of the last day of any fiscal quarter; and

 

   

a debt coverage ratio, consisting of consolidated debt minus all unrestricted cash and cash equivalents to EBITDA, of not more than 3.75 to 1.0 for the four quarters ended on the last day of each fiscal quarter.

We believe that we are in compliance with the terms of our revolving credit facility. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

 

   

failure to pay any principal or interest due under the revolving credit facility or any amount of principal under any letter of credit when due or any fees or other amount within certain grace periods;

 

   

a representation or warranty is proven to be incorrect in any material respect on or as of the date made or deemed made;

 

   

failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

 

   

default by us on the payment of any other indebtedness in excess of 5.0% of borrowing base currently in effect, or any other event occurs that permits or causes the acceleration of such indebtedness;

 

   

bankruptcy or insolvency events involving us or our subsidiaries;

 

   

the entry of one or more judgments, orders, decrees, or arbitration awards involving in the aggregate a liability as to any single or related series of transactions, incidents or conditions in excess of 5.0% of borrowing base currently in effect that remains unsatisfied, unvacated and unstayed pending appeal for a period of thirty days after the entry thereof; and

 

   

a change of control, as defined in the credit agreement.

New Preferred Units

In December 2011, Midstates Petroleum Holdings LLC entered into an amended and restated limited liability company agreement to provide for the issuance of redeemable convertible preferred units (the “New Preferred Units”) to an affiliate of First Reserve in the aggregate amount of $40 million.

 

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The New Preferred Units are redeemable at the option of Midstates Petroleum Holdings LLC and may be converted by the holder at any time after the first anniversary of issuance. The New Preferred Units are convertible into common units in Midstates Petroleum Holdings LLC, with the conversion ratio determined by the fair market value of the common units on the date of conversion. The New Preferred Units will bear interest, payable either upon redemption or conversion, of 8.0% plus the greater of LIBOR or 1.5%. In addition, a fixed interest charge of 1.5% of the aggregate capital contributions made with respect to the New Preferred Units will be payable upon redemption or conversion.

On January 4, 2012, the Company issued 20,000 New Preferred Units to FR Midstates for aggregate cash proceeds of $20,000,000. Due to the mandatory redemption feature, issuances of New Preferred Units will be classified as a liability in the Company’s consolidated balance sheets. The Company intends to use a portion of the proceeds from this offering to redeem all of the outstanding New Preferred Units. See “Use of Proceeds” and “Certain Relationships and Related Party Transactions — Transactions With First Reserve and Our Executive Officers.”

Commodity Derivative Contracts

Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, such as collars, swaps, puts, and basis differential swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss. For a summary of our commodity derivative contracts as of December 31, 2011, please see “Quantitative and Qualitative Disclosures About Market Risk — Commodity price exposure” beginning on page 62.

Obligations and Commitments

We have the following contractual obligations and commitments as of December 31, 2011 (in thousands):

 

     Payments due by period  
      Total      Less than
1 year
     1 - 3 years      3 - 5 years      More than
5 years
 

Contractual Obligations

              

Revolving credit facility (1)

   $ 234,800       $       $ 234,800       $       $   

Operating leases (2)

     1,339         581         758                   

Drilling contracts (2)

     7,210         7,210                           

Seismic contracts (2)

     7,213         7,213                           

Asset retirement obligations (3)

     7,627                                 7,627   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 258,189       $ 15,004       $ 235,558       $       —       $ 7,627   

 

(1) Amount excludes interest on our revolving credit facility as both the amount borrowed and applicable interest rate is variable. As of December 31, 2011, we had $234.8 million of indebtedness outstanding under our revolving credit facility. See “Notes to Consolidated Financial Statements — Note 6 — Long-Term Debt.”
(2) See “Notes to Consolidated Financial Statements — Note 10 — Commitments and Contingencies” for a description of operating lease, drilling contract, and seismic contract obligations.
(3)

Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based

 

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  upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See “Notes to Consolidated Financial Statements — Note 5 — Asset Retirement Obligations.”

Amounts related to our derivative financial instruments are not included in the table above. See Note 4 to our Consolidated Financial Statements.

Critical Accounting Policies and Estimates

We prepare our financial statements and the accompanying notes in conformity with GAAP, which requires our management to make estimates and assumptions about future events that affect the reported amounts in our financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Our management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of our most critical accounting policies:

Reserves Estimates. Effective December 31, 2009, we adopted revised oil and gas disclosure requirements set forth by the SEC in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries — Oil and Gas.” The rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other revised definitions and disclosures.

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing operating conditions and government regulations.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Reserves as of December 31, 2011, 2010 and 2009 were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month, held flat for the life of the production, except where prices are defined by contractual arrangements.

We have elected not to disclose probable and possible reserves or reserve estimates in this filing.

Revenue Recognition. Our revenue recognition policy is significant because revenue is a key component of the results of operations and of the forward-looking statements contained in the analysis

 

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of liquidity and capital resources. We record revenue in the month our production is delivered to the purchaser, but payment is generally received 30 to 90 days after the date of production. At the end of each month, we estimate the amount of production that was delivered to the purchaser and the price that will be received. We use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other factors as the basis for these estimates. We record the variances between our estimates and the actual amounts received in the month payment is received.

Financial Instruments. Our financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivatives. Commodity derivatives are recorded at fair value. The carrying amount of our other financial instruments approximate fair value because of the short-term nature of the items or variable pricing.

Derivative financial instruments are recorded in our consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative’s fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded within revenues in “Gains (losses) on commodity derivative contracts — net.” The related cash flow impact is reflected within cash flows from operating activities.

Asset Retirement Obligations. We have significant obligations to remove tangible equipment and facilities associated with our oil and natural gas wells, and to restore land at the end of oil and natural gas production operations. The removal and restoration obligations are associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

Internal Controls and Procedures

Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. Our independent registered accounting firm and we have concluded that these control deficiencies represented a material weakness in internal control over financial reporting for each of the years ended December 31, 2010 and 2009. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment.

Management has taken steps to address the causes of these material weaknesses by putting into place new accounting processes and control procedures, including a new methodology to improve tracking of unevaluated properties and related costs. In addition, we have added five experienced

 

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accounting personnel in response to our identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company. As of December 31, 2011, we believe that steps taken to date have remediated the control deficiencies identified in prior years that resulted in material weaknesses during those periods; however, our evaluation of internal control over financial reporting is not complete.

While we have begun the process of evaluating our internal control over financial reporting, we are in the early phases of our review and will not complete our review until well 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 represent significant deficiencies and other material weaknesses, in addition to the material weaknesses previously identified, that require remediation by the Company. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

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 public company, we will be required to comply with the SEC’s rules implementing Section 302 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. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management 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. Once 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, operated or reviewed.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2011, 2010 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged in the past and expect to hedge a significant portion of our future production.

We utilize derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2011, we utilized fixed price swaps, collars, deferred-premium puts and basis differential swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

 

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For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

The following is a summary of our commodity derivative contracts as of December 31, 2011:

 

     Hedged
Volume
     Weighted-
Average
Fixed Price
 

Oil (Bbls):

     

Swaps – 2012

     893,400         84.16   

Swaps – 2013

     679,125         84.73   

Swaps – 2014

     262,450         83.00   

Collars – 2012

     164,700       $ 85.00 – $127.28   

Deferred Premium Puts – 2012 (1)

     549,000         79.01   

Basis Differential Swaps – 2012 (2)

     1,134,600         9.78   

Basis Differential Swaps – 2013 (2)

     182,500         7.50   

 

     Year Ended
December 31, 2011
 
     (in thousands)  

Derivative fair value at period end — liability (included in the balance sheet)

   $ 17,232   
  

 

 

 

Realized net (loss) gain (included in the statement of operations)

   $ (16,733
  

 

 

 

Unrealized net (loss) gain (included in the statement of operations)

   $ 11,889   
  

 

 

 

 

(1) 2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.
(2) We enter into swap arrangements intended to capture the positive differential between LLS pricing and NYMEX WTI pricing.

As of December 31, 2011, 2010 and 2009, assets and liabilities recorded at fair value in the balance sheets were categorized based upon the level of judgment associated with the inputs used to measure their value. Our only financial assets and liabilities that are measured at fair value as of December 31, 2011, 2010 and 2009 are the derivative instruments discussed above. At December 31, 2011 and 2010, all of our commodity derivative contracts were with two and one bank counterparties, respectively, and are all classified as Level 2. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

Interest rate risk. At December 31, 2011, we had indebtedness outstanding under our credit facility of $234.8 million, which bore interest at floating rates. The average annual interest rate incurred on this indebtedness for the years ended December 31, 2011, 2010 and 2009 was approximately 3.2%, 3.0% and 3.3%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the years ended December 31, 2011 and 2010 would have resulted in an estimated $1.5 million and $0.6 million, respectively, increase in interest expense, of which a portion may be capitalized.

We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

 

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Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. See “Business — Marketing and Major Customers” on page 78 for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility with investment grade ratings, and we are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility which also carry investment grade ratings. Several of our significant customers for oil and gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

 

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BUSINESS

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources in previously discovered yet underdeveloped hydrocarbon trends. We were founded in 1993 to focus on oilfields in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. The Upper Gulf Coast Tertiary trend extends from south Texas to Mississippi across our current operating areas in central Louisiana and is characterized by well-defined geology, including tight sands featuring multiple productive zones typically located within large geologic traps. Many of the oilfields in this trend were discovered by major oil companies in the 1940’s and 1950’s, but were not fully developed due to then-prevailing oil prices, the adoption of a state-level severance tax in Louisiana, restrictive production allowables and other regulatory limitations. We have applied modern formation evaluation and drilling and completion techniques to the trend, and, as a result, we have identified a large inventory of development drilling opportunities that we believe will provide strong economic returns. Our early entry and relatively long history in the trend have positioned us as a first-mover. We have accumulated approximately 77,100 net acres in the trend and have options to acquire an aggregate of approximately 31,700 additional targeted net acres.

Our development operations are currently focused in the Wilcox interval of the trend, drilling vertical wells and commingling production from multi-stage hydraulically fractured completions across stacked oil-producing intervals. Our strategy has been validated by the 57 gross wells we have drilled in the trend since the third quarter of 2008, approximately 93% of which produced commercially. Since that time, we have increased our average daily production at a compound annual growth rate of 101%, from 1,024 Boe/d in the month ended September 30, 2008 to 9,897 Boe/d in the month ended December 31, 2011. We believe that, based on the results of our drilling program and our understanding of the geology underlying our acreage, we have a total of 600 specifically identified gross vertical drilling locations in the trend. In addition, we believe this trend may further benefit from the application of horizontal drilling and completion techniques. We drilled our first horizontal well in the trend in the fourth quarter of 2011 and it is currently undergoing completion.

NSAI, our independent reserve engineers, estimated our net proved reserves to be 26.2 MMBoe as of December 31, 2011, 75 % of which were comprised of oil and NGLs. As of December 31, 2011, our properties included approximately 92 gross active producing wells, 95% of which we operate, and in which we held an average working interest of approximately 99% across our 77,100 net acre leasehold. The following table presents summary data regarding our reserves and production for each of our four primary operating areas as well as other acreage we hold that we have identified as having significant hydrocarbon structures, as measured by either production tests or well log analysis, which we refer to as our expansion areas. The information in the table is as of December 31, 2011, unless otherwise indicated:

 

    Average Daily
Production (1)
    Estimated
Net
Proved
Reserves
    Acreage     Identified
Vertical
Drilling
Locations (3)
    2011
Wells (4)
    Budget  
              2012
Wells (5)
    2012
D&C (6)
 
    (Boe/d)     (% Oil) (2)     (MMBoe)     (Gross)     (Net)     (Gross)     (Gross)     (Gross)     (In millions)  

Pine Prairie

    3,793        71     12.1        3,101        3,076        150        13        26      $ 90   

South Bearhead Creek/Oretta

    4,367        60     5.3        3,645        3,559        39        6        8        47   

West Gordon

    1,002        68     5.5        10,617        10,488        73        8        15        98   

North Cowards Gully

    149        77     3.0        7,109        7,109        75        1        2        6   

Expansion Areas (7):

                 

Acreage under lease

    122        78     0.3        54,392        52,840        263        4        16        65   

Acreage under option

                         32,067        31,669                               
 

 

 

     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    9,433        66     26.2        110,931        108,741        600        32        67      $ 306   
 

 

 

     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Average daily production for the three months ended December 31, 2011.
(2) Includes volumes attributable to oil and NGLs.
(3) Our drilling locations are specifically identified based on our interpretation of 2D and 3D seismic data, study of previously drilled wells and analogous well performance. We have selected our drilling locations to optimize the initial testing and subsequent delineation of all potential reservoirs in a given field or geologic structure. Drilling locations in our Pine Prairie area are primarily based on 10-acre spacing, while other drilling locations are primarily based on 40-acre spacing or greater. Of our 600 specifically identified gross vertical drilling locations, approximately 100 are classified as proved undeveloped according to NSAI’s December 31, 2011 reserve report.
(4) Includes wells spud between January 1, 2011 and December 31, 2011; 31 wells were drilled to total depth and one well was in the process of drilling at December 31, 2011.
(5) Includes wells spud or expected to be spud between January 1, 2012 and December 31, 2012.
(6) Represents drilling and completion expenditures.
(7) For a description of our expansion areas, see “Business — Our Areas of Operation — Expansion Areas Within the Trend” beginning on page 71.

 

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Our total 2011 capital expenditures were $264 million, and we drilled or spud 32 wells in 2011. Our total 2012 capital expenditure budget is $380 million, approximately 17% of which will be spent developing acreage currently under lease in our expansion areas. Our 2012 budget consists of:

 

   

$306 million for drilling and completion capital;

 

   

$58 million for acquisition of acreage and seismic data; and

 

   

$16 million in unallocated funds which are available for facilities.

While we have budgeted $380 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” beginning on page 55.

Our Business Strategy

Our goal is to increase stockholder value by growing reserves, production and cash flows at an attractive return on invested capital. We seek to achieve this goal through the following strategies:

 

   

Accelerate development of our multi-year drilling inventory. We intend to drill and develop our current acreage position to maximize the value of our resource potential. Our assets are characterized by thick geologic sections of tight sands featuring multiple productive zones located within large geologic structural traps that are identifiable with 2D seismic data. Our primary operating areas have well-established production histories and relatively low terminal production decline rates. We have identified an inventory of 600 gross vertical drilling locations targeting large, well-defined geologic structures that we believe will increase our reserves, production and cash flow. Since the third quarter of 2008, we have drilled 57 gross wells in the trend, approximately 93% of which produced commercially, making us the most active driller in the trend during that period. As of December 31, 2011, we had four drilling rigs in operation. We expect to operate up to six drilling rigs by the end of 2012, which would enable us to drill as many as 67 gross operated wells during that year, 16 of which we anticipate drilling in our expansion areas.

 

   

Utilize our technical and operating expertise to enhance returns. Our management team is focused on the application of modern reservoir evaluation and drilling and completion techniques to reduce risk and enhance returns. We utilize 2D seismic data and existing sub-surface well control data to identify large, undeveloped or under-developed geologic traps that we believe have significant development potential as targets for our leasing activity. Once we have identified a potential target, we attempt to efficiently verify the economic viability of the target reservoir utilizing existing wellbores and techniques such as sidetracking and slim-hole drilling. Once the development potential of the target reservoir has been established, we seek to economically develop the opportunity by incorporating 3D seismic data and reservoir evaluation methods such as conventional and rotary sidewall coring pressure sampling and other reservoir description techniques. We have accumulated 3D seismic data covering 80% of the acreage in our primary operating areas and 60% of our total acreage. We believe our primary operating areas represent the successful execution of this exploration to development approach. We are applying this same approach to our expansion areas, where we have recently leased approximately 52,800 net acres and have also entered into lease option agreements covering approximately 31,700 additional targeted net acres. We believe future development across our entire acreage position may be further optimized through specialized completion techniques, infill drilling, horizontal drilling and other enhanced recovery methods.

 

   

Strategically increase our acreage position. While we believe our existing inventory of specifically identified drilling locations provides significant growth opportunities, we continue to

 

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use the in-depth knowledge that we have gained as a first mover in the region to increase our leasehold position in the oil-prone portion of the Upper Gulf Coast Tertiary trend. We believe that this portion of the trend extends from east Texas through central Louisiana and into southern Mississippi and offers us significant opportunities to acquire additional acreage. We have screened more than 300 geologic structures in the oil-prone portion of the trend. Our current acreage position, including acreage under option, has captured only 18 of these structures, of which we have drilled eight, all of which have established commercial production in multiple horizons. We have specifically identified approximately 40 additional geologic structures throughout the trend that we believe have characteristics similar to our existing operating areas. In addition to increasing our acreage position through leasing, we may selectively pursue potential acquisitions of strategic assets or operating companies in the trend. Over time, we also expect to selectively target additional onshore basins in North America that would allow us to extend our competencies to large undeveloped acreage positions in hydrocarbon trends similar to our existing core area.

 

   

Apply rigorous investment analysis to capital allocation decisions. We employ rigorous investment analysis to determine the allocation of capital across our many drilling opportunities. We are focused on maximizing the internal rate of return on our investment capital and screen drilling opportunities by measuring risk and financial return, among other factors. We continually evaluate and rank our inventory of potential investments by these measures, incorporating past drilling results and new information we have gathered. This approach has allowed us to maintain attractive operational and efficiency metrics, measured by finding and development costs, even as our capital expenditures and drilling activities have significantly increased over the last three years.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

 

   

Extensive technical knowledge, history and first-mover advantage in the Upper Gulf Coast Tertiary trend. We have had operations in the Upper Gulf Coast Tertiary trend since 1993. We believe our extensive operating experience in the trend provides us with an expansive technical understanding of the geology underlying our acreage and of the application of completion technologies and infrastructure design and optimization to our properties. We believe our relatively long history in this area and experience interpreting well control data, core data and 2D and 3D seismic data provides us with an information advantage over our competitors in the trend and has allowed us to identify and acquire quality acreage at a relatively low cost. In addition, we have developed amicable and mutually beneficial relationships with acreage owners in our operating areas, which we believe provides us with a competitive advantage with respect to our leasing and development activity. We also benefit from long-term relationships with local service companies and infrastructure providers that we believe contribute to our efficient low-cost operations.

 

   

Louisiana Light Sweet oil-weighted reserves, production and drilling locations with attractive economics. Our reserves, production and drilling locations are primarily oil with associated liquids rich natural gas. For the three months ended December 31, 2011, our production was comprised of approximately 55% oil and 12% NGLs. We benefit from selling our oil production to the LLS market, which has historically commanded a premium to NYMEX WTI oil prices due to its proximity to U.S. Gulf Coast refiners and the higher quality of the oil production sold in the LLS market. This premium has averaged approximately $7.82 per Bbl in the three years ended December 31, 2011. For the three months ended December 31, 2011, the average realized price before the effect of commodity derivative contracts for our oil production was $115.46 per Bbl, compared to an average NYMEX WTI price of $94.06 per Bbl for the same

 

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period, representing a premium of $21.40 per barrel. Our ability to capture a premium for our oil production in the LLS market provides us with a significant competitive advantage over companies with assets in other well known plays, such as the Bakken and Eagle Ford, where oil price realizations are typically at a discount to NYMEX WTI. In addition, our assets are located in an area with developed legacy infrastructure that reduces our development and transportation costs relative to other onshore basins in North America.

 

   

Multi-year drilling inventory with significant upside potential. We have an inventory of approximately 600 specifically identified gross vertical drilling locations. This inventory includes drilling locations in our expansion areas that have been meaningfully risked given the early stage of development. We believe our expansion areas possess substantially similar characteristics as our primary operating areas, and expect that the execution of our 2012 drilling plan will allow us to reduce our risk profile on this acreage and could add materially to our drilling opportunities. We also believe the potential drilling inventory on our existing acreage may increase significantly by targeting additional productive zones and through infill drilling. Based on the results of our development activities in our primary operating areas, we believe that infill drilling within thick geologic sections of tight sands increases the ultimate resource recovery. We have successfully downspaced to 10-acre spacing in portions of our Pine Prairie area. We are currently testing downspacing in our South Bearhead Creek/Oretta and North Cowards Gully areas and intend to apply this concept in our other primary operating areas and our expansion areas. In addition, we may be able to enhance the total recovery in the trend through specialized completion techniques, horizontal drilling and secondary recovery techniques.

 

   

Operating control over 96% of our portfolio. In order to maintain better control over our assets, we have established a leasehold position comprised primarily of properties that we expect to operate. Controlling operations allows us to dictate the pace of development and better manage the cost, type and timing of exploration and development activities. We expect to operate 96% of our 600 specifically identified gross drilling locations. For the three months ended December 31, 2011, approximately 99% of our production was attributable to properties that we operate.

 

   

Experienced management team with extensive operating expertise. Our management team has extensive operating expertise in the oil and gas industry and significant public company executive experience at Apache Corporation, Burlington Resources, ConocoPhillips, Noble Corporation, and SM Energy. Our management team has an average of 30 years of industry experience, including prior experience in the Upper Gulf Coast Tertiary trend and similar trends. We believe our management team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record of efficiently operating exploration and development programs.

 

   

Conservative financial position. We believe that our capital structure and hedge positions following this offering will allow us to continue our development program and acquire additional acreage even in challenging commodity price environments and periods of capital markets dislocation. Giving effect to the completion of this offering, our liquidity as of December 31, 2011 would have been $         million, consisting of $         million available under our revolving credit facility and $         million in cash and cash equivalents. After the completion of this offering, we believe we will have the liquidity and financial flexibility to more than fund our 2012 drilling program and production growth. In addition, we have an active hedging program in place, with swaps, collars and puts covering approximately 1.6 million barrels of our oil production in 2012.

 

   

Alignment among management, founders and public stockholders. Upon the completion of this offering, our management team will have a significant direct ownership interest in us. In addition, our management team will also own an indirect economic interest in us through their

 

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ownership of incentive units in FRMI. FRMI is controlled by First Reserve. The incentive units entitle our management to a portion of the proceeds to be received by First Reserve upon sales of our common stock by FRMI. Our management may significantly increase the value allocated to their incentive units by increasing the return on investment for First Reserve. We believe our management team’s direct ownership interest and incentive units provide significant incentives to grow the value of our business for the benefit of all stockholders.

Our Operations

Overview of the Geologic Structure of the Upper Gulf Coast Tertiary Trend

 

The Upper Gulf Coast Tertiary trend is an approximately 65 million year old geologic system. The lower portion of the trend, also known as the Paleogene system, exists as a continuous event along the Upper Gulf Coast region of Texas, Louisiana, and Mississippi. There are three major geologic series in the Paleogene system — the Oligocene, Eocene, and Paleocene. Each of these geologic series contain numerous strata exhibiting viable reservoir rock qualities. Our current acreage position and evaluation efforts are concentrated in the trend within the state of Louisiana. The Yegua/Cockfield, Cook Mountain, Sparta, and Wilcox formations, which are specific to the Eocene geologic series underlying the state of Louisiana, have evidence of numerous hydrocarbon trap systems along the trend. In Louisiana, the trend has cumulatively produced nearly 800 million barrels of oil.

 

The Wilcox interval is prevalent in our primary operating areas and our expansion areas and is the principal target of our identified drilling locations. The Wilcox interval spans a gross thickness of 3,000 to 4,000 feet and lies at depths between 9,000 to 17,000 feet across our focus area in the trend. It consists of silty sandstone with clean sandstone and shales inter-bedded throughout. Porosities are typically between 6% and 18% with permeability ranging from 0.1 to 10 millidarcies.

  

 

LOGO

Hydrocarbon discoveries in the Wilcox interval in Louisiana occurred as early as the 1930’s and continued thereafter as numerous new field discoveries were made. Most new field discoveries were made by drilling exploratory wells targeting structures using gravity data, and later by the use of 2D seismic surveys. These structures consist of basic 3- or 4-way rollover anticline closures against large “down-to-the-coast” expansion faults and geologic closures caused by deeper underlying salt deformations along the trend. In some instances, the exploratory wells were tested under natural conditions in select, thin-sand intervals through the use of a drill-stem test. Regulatory requirements in place at the time limited completion intervals to individual sands rather than a collection of stacked sands. Because of the Wilcox interval’s tendency to have lower permeability than traditional Gulf Coast reservoirs, most of the drill-stem tests showed marginally economic production rates, and consequently, the exploratory wells were abandoned. In other instances, the exploratory wells were completed in a single pay interval and flowed until production rates became marginally economic. At

 

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that time, the existing completed interval was abandoned and a new interval was completed. In almost all cases, minimal reservoir delineation or down spacing efforts were made beyond the exploratory well due to the marginal production tests realized and then prevailing oil prices associated with this area. Some of the early wells continue to produce at very low decline rates.

The hydrocarbon characteristics of the Wilcox interval in Louisiana are consistent with black and/ or volatile oils. A high quality, 45º to 50º API gravity oil is produced along with significant yields of high Btu gas that can be processed for NGLs. The primary drive mechanism for most of the reservoirs is pressure depletion, as opposed to the strong water drive commonly seen in traditional Gulf Coast reservoirs. This typically results in a longer reserve life with minimal or no water production. The hydrocarbon characteristics seen in Louisiana in the Wilcox interval vary considerably to those seen in Texas in the Wilcox interval where historical data indicates a gaseous hydrocarbon production stream. The differences in fluid properties across the entire trend are the result of the hydrocarbon source rocks having different organic compositions and thermal maturities across the play.

We believe advances in drilling and completion techniques have created significant development potential in the trend. Specifically, hydraulic fracture stimulation techniques have been developed by the industry to increase ultimate resource recoveries in tight geologic formations. Infill drilling has also been utilized by the industry to further enhance recoveries from thick, tight geologic intervals. We have successfully implemented infill drilling in our Pine Prairie area and are currently testing the technique in our South Bearhead Creek/Oretta and North Cowards Gully areas. We also intend to apply this concept to our other primary operating areas and expansion areas. There are many plays that contain similar thick, tight geologic sections onshore in the United States that illustrate that the application of these advancements can achieve strong economic results. The Wolfberry trend in the Permian Basin and the Williams Fork trend in the Piceance Basin are two examples.

Our Areas of Operation

Pine Prairie

Our properties in the Pine Prairie area represented 46% of our total proved reserves as of December 31, 2011. During the three months ended December 31, 2011, our average production from these properties was 3,793 net Boe/d consisting of 2,143 Bbls of oil, 565 Bbls of NGLs and 6,508 Mcf of natural gas per day. As of December 31, 2011, we held an average working interest and average net revenue interest of 92.2% and 68.9%, respectively, on our acreage in this area. Our current development drilling is targeting the Upper and Lower Wilcox, the Sparta and the shallower Miocene and Frio intervals. We are currently drilling on primarily 10-acre spacing in this area. In 2011, we invested approximately $73 million in the drilling of 13 wells in the Pine Prairie area, and in 2012, we plan to invest approximately $90 million in the drilling of 26 wells. We have an additional 150 identified drilling locations in this area based primarily on 10-acre spacing.

South Bearhead Creek/Oretta

Our properties in the South Bearhead Creek/Oretta area represented 20.3% of our total proved reserves as of December 31, 2011. During the three months ended December 31, 2011, our average production from these properties was 4,367 net Boe/d consisting of 2,196 Bbls of oil, 438 Bbls of NGLs and 10,396 Mcf of natural gas per day. As of December 31, 2011, we held an average working interest and average net revenue interest of 100% and 78.5%, respectively, on our acreage in this area. Our current development drilling is targeting the Upper and Lower Wilcox intervals. The field is being developed on 40-acre spacing by commingling production from the Upper and Lower Wilcox. In 2011, we invested approximately $61 million in the drilling of 6 wells in the South Bearhead Creek/Oretta area, and in 2012, we plan to invest approximately $47 million in the drilling of 8 wells. We have an additional 39 identified drilling locations in this area based primarily on 40-acre spacing and are currently testing downspacing to 20-acre spacing.

 

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West Gordon

Our properties in the West Gordon area represented 21% of our total proved reserves as of December 31, 2011. During the three months ended December 31, 2011, our average production from these properties was 1,002 net Boe/d consisting of 617 Bbls of oil, 68 Bbls of NGLs and 1,901 Mcf of natural gas per day. As of December 31, 2011, we held an average working interest and average net revenue interest of 95.9% and 71.2%, respectively, on our acreage in this area. Our current development drilling is targeting the Upper Wilcox interval, where we are drilling on 40-acre spacing. In 2011, we invested approximately $60 million in the drilling of 8 wells in the West Gordon area, and in 2012, we plan to increase our investment to approximately $98 million in the drilling of 15 wells. We have an additional 73 identified drilling locations in this area based primarily on 40-acre spacing.

North Cowards Gully

Our properties in the North Cowards Gully area represented 11.5% of our total proved reserves as of December 31, 2011. During the three months ended December 31, 2011, our average production from these properties was 149 net Boe/d consisting of 103 Bbls of oil, 11 Bbls of NGLs, and 211 Mcf of natural gas per day. As of December 31, 2011, we held an average working interest and average net revenue interest of 94.3% and 71.2%, respectively, on our acreage in this area. Our current development drilling is targeting the Upper Wilcox interval, where we are drilling on 40-acre spacing. In 2011, we invested approximately $9 million in the drilling of one well in North Cowards Gully area, and in 2012, we plan to invest approximately $6 million in the drilling of 2 wells. We have an additional 75 identified drilling locations in this area based primarily on 40-acre spacing and are currently testing downspacing to 20-acre spacing.

Expansion Areas Within the Trend

In late 2010, we began acquiring seismic data and additional acreage in a focused effort to expand our asset base in the trend. As part of this effort, we screened more than 300 geologic structures in the trend utilizing existing sub-surface well control and 2D seismic. We further narrowed the group of identifiable structures based on our prior experience. Subsequently, we acquired approximately 52,600 net acres in our expansion areas in late 2010 and early 2011. We are currently evaluating prospects on this acreage. In 2011, we drilled four wells on this acreage of which three wells are currently producing and one well is in the process of being completed. We have identified 263 drilling locations on this acreage and are planning to spend approximately $65 million to drill 16 wells in 2012 on this acreage. These drilling locations have been meaningfully risked given the early stage of development. We expect that the execution of our 2012 drilling plans will allow us to reduce our risk profile on this acreage and could add materially to our drilling opportunities. During 2011, we also negotiated options to acquire an additional 31,700 net acres in the trend. We have committed to shoot 3D seismic over the optioned acreage which is expected to be completed by October 2012. We may acquire additional acreage within the 3D seismic shoot pending evaluation of the results.

To date, our existing acreage position, including acreage under option, has captured 18 of the previously screened geologic structures, of which we have drilled eight, all of which have established commercial production in multiple horizons. The successful conversion of our primary operating areas from exploration to development and the early results in our expansion areas gives us confidence in our ability to add significant additional value within our expansion areas. Further, we have specifically identified approximately 40 additional geological structures throughout the trend that we may target for future leasehold acquisition.

Estimated Proved Reserves

Unless otherwise specifically identified in this prospectus, the summary data with respect to our estimated proved reserves presented below has been prepared by our independent reserve

 

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engineering firms in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. For a definition of proved reserves under the SEC rules, see the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.

The reserve estimates at December 31, 2011 and at December 31, 2010 and 2009 presented in the table below are based on reports prepared by NSAI. NSAI’s reports were prepared consistent with the rules and regulations of the SEC regarding oil and natural gas reserve reporting in effect during such periods.

 

     At December 31,  
     2011     2010     2009  

Reserve Data:

      

Estimated proved reserves:

      

Oil (MMBbls)

     15.7        11.9        7.6   

Natural gas (Bcf)

     38.7        27.9        13.3   

Natural gas liquids (MMBbls)

     4.0        0.3        0.1   

Total estimated proved reserves (MMBoe)

     26.2        16.9        9.9   

Proved developed reserves:

      

Oil (MMBbls)

     6.5        5.4        2.8   

Natural gas (Bcf)

     18.0        14.2        4.4   

Natural gas liquids (MMBbls)

     1.8        0.1        0.0   

Total proved developed (MMBoe)

     11.3        7.9        3.5   

Percent proved developed

     43     47     36

Proved undeveloped reserves:

      

Oil (MMBbls)

     9.2        6.5        4.8   

Natural gas (Bcf)

     20.7        13.7        8.9   

Natural gas liquids (MMBbls)

     2.2        0.2        0.1   

Total proved undeveloped (MMBoe)

     14.9        9.0        6.4   

The following table sets forth the benchmark prices used to determine our estimated proved reserves from proved oil and natural gas reserves for the periods indicated.

 

     At December 31,  
     2011      2010      2009  

Oil and Natural Gas Prices (1):

        

Oil (per Bbl)

     $92.71         $75.96         $57.65   

Natural gas (per MMBtu)

     $4.118         $4.376         $3.866   

 

(1) Benchmark prices for oil and natural gas at December 31, 2011, 2010 and 2009 reflect the unweighted arithmetic average first-day-of-the-month prices for the prior twelve months, using Plains WTI posted prices for oil and Platt’s Gas Daily Henry Hub prices for natural gas.

Our proved reserves have grown from 9.9 to 16.9 MMBoe from year end 2009 to 2010 and 16.9 to 26.2 MMBoe from year end 2010 to year end 2011. Our reserve growth in these periods is due directly to the extensions and discoveries associated with our drilling activities in each year. As a result of our drilling efforts, we have increased our average daily production at a compound annual growth rate of 101% from 1,024 Boe/d in the month ended September 30, 2008 to 9,897 Boe/d in the month ended December 31, 2011.

Our proved undeveloped reserves have grown from 9.0 MMBoe to 14.9 MMBoe from December 31, 2010 to December 31, 2011. During this time, we spent $43.0 million of our capital expenditures on drilling proved undeveloped locations and converted 2.1 MMBoe from proved

 

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undeveloped reserves to proved developed reserves. In addition, we added 10.2 MMBoe of proved undeveloped reserves through extensions and discoveries. Also, we had a negative revision of 2.2 MMBoe of proved undeveloped reserves.

Independent petroleum engineers

Our estimated reserves and related future net revenues at December 31, 2011, 2010 and 2009 are based on reports prepared by NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect in effect during such period established by the SEC. Copies of these reports have been filed as an exhibit to the registration statement containing this prospectus.

The reserves estimates as of December 31, 2011, December 31, 2010, and December 31, 2009 shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg, Mr. Philip R. Hodgson, and Mr. Thomas C. Woolley. Mr. Barg has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Barg is a Registered Professional Engineer in the State of Texas (License No. 71658) and has over 28 years of practical experience in petroleum engineering, with over 22 years experience in the estimation and evaluation of reserves. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Hodgson has been practicing consulting petroleum geology at NSAI since 1998. Mr. Hodgson is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 1314) and has over 27 years of practical experience in petroleum geosciences, with over 13 years experience in the estimation and evaluation of reserves. He graduated from Purdue University in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Mr. Woolley practiced consulting petroleum engineering at NSAI from 2006 to 2011. Mr. Woolley is a Registered Professional Engineer in the State of Texas (License No. 100562) and has over 8 years of practical experience in petroleum engineering, with over 4 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 2002 with a Bachelor of Science Degree in Petroleum Engineering. All three technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; all three are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Technology used to establish proved reserves

Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

 

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In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.

Internal controls over reserves estimation process

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. Curtis Newstrom, PE, our Vice President of Business Development, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has 25 years of industry experience with positions of increasing responsibility in engineering and evaluations and holds a Bachelor of Science in Petroleum Engineering from Marietta College. Our Vice President of New Ventures reports directly to the CEO and is a registered professional engineer in the state of Louisiana (License No. 25260). Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our senior management with representatives of our independent reserve engineers and internal technical staff.

Production, revenues and price history

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand for oil increased during 2010, but demand for natural gas remained sluggish. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

 

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The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2011, 2010 and 2009. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

 

     Year Ended December 31,  
     2011      2010      2009  

Operating data:

        

Net production volumes:

        

Oil (MBbls)

     1,610         945         497   

Natural gas (MMcf)

     4,918         2,253         690   

Natural gas liquids (MBbls)

     308         74         2   

Total oil equivalents (MBoe)

     2,737         1,394         614   

Average daily production
(Boe/d)

     7,499         3,820         1,682   

Average sales prices:

        

Oil, without realized derivatives (per Bbl)

   $ 110.25       $ 80.29       $ 55.07   

Oil, with realized derivatives (per Bbl)

     100.26         79.37         57.69   

Natural gas (per Mcf)

     4.20         4.66         3.89   

Natural gas liquids (per Bbl)

     50.98         36.92         47.66   

Cost and expenses (per Boe of production):

        

Lease operating

   $ 5.12       $ 5.86       $ 8.31   

Workover

     0.77         3.36         8.51   

Severance and ad valorem tax

     4.98         5.01         4.99   

Asset retirement accretion

     0.12         0.13         0.20   

General and administrative

     10.22         11.73         9.59   

Depreciation, depletion and amortization

     33.50         30.00         20.08   

 

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The following table sets forth information regarding oil, natural gas, oil and NGLs production for each of the fields that represented more than 15% of our estimated total proved reserves as of the dates indicated.

 

     Year Ended
December 31,
 
   2011      2010      2009  

Pine Prairie

        

Net production volumes:

        

Oil (MBbls)

     786         745         386   

Natural gas (MMcf)

     2,476         1,850         537   

NGLs (MBbls)

     190         59           
  

 

 

    

 

 

    

 

 

 

Total oil equivalents (MBoe)

     1,389         1,113         476   
  

 

 

    

 

 

    

 

 

 

South Bearhead Creek/Oretta

        

Net production volumes:

        

Oil (MBbls)

     645         136         73   

Natural gas (MMcf)

     2,032         373         144   

NGLs (MBbls)

     104         12         2   
  

 

 

    

 

 

    

 

 

 

Total oil equivalents (MBoe)

     1,087         211         99   
  

 

 

    

 

 

    

 

 

 

West Gordon

        

Net production volumes:

        

Oil (MBbls)

     115         19         27   

Natural gas (MMcf)

     346         40         2   

NGLs (MBbls)

     10         2           
  

 

 

    

 

 

    

 

 

 

Total oil equivalents (MBoe)

     183         27         27   
  

 

 

    

 

 

    

 

 

 

Productive wells

The following table presents the total gross and net productive wells as of December 31, 2011:

 

     Oil      Natural Gas      Total  
     Gross      Net      Gross      Net      Gross      Net  

Total productive wells

     88         83.7         4         3.4         92         87.1   

Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.

 

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Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we have a controlling interest as of December 31, 2011 for each of our project areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

 

     Developed Acres      Undeveloped Acres      Total Acres  
     Gross      Net      Gross      Net      Gross      Net  

Pine Prairie

     2,047         2,033         1,054         1,043         3,101         3,076   

South Bearhead Creek/Oretta

     2,855         2,855         790         704         3,645         3,559   

West Gordon

     1,679         1,679         8,938         8,809         10,617         10,488   

North Cowards Gully

     1,594         1,594         5,515         5,515         7,109         7,109   

Expansion Areas (1):

                 

Acreage Under Lease

     2,340         2,340         52,052         50,500         54,392         52,840   

Acreage Under Option

                     32,067         31,669         32,067         31,669   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     10,515         10,501         100,416         98,240         110,931         108,741   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) For a description of our Expansion Areas, see “— Our Areas of Operation — Expansion Areas Within the Trend” on page 71.

Undeveloped acreage expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2011 that will expire over the next three years by project area unless production is established within the spacing units covering the acreage prior to the expiration dates:

 

     Expiring 2012      Expiring 2013      Expiring 2014  
     Gross      Net      Gross      Net      Gross      Net  

Pine Prairie

     35         35         518         499         286         249   

South Bearhead Creek/Oretta

                                     239         239   

West Gordon

     52         52         1,529         824         3,062         2,547   

North Cowards Gully

     623         593         3,540         3,520         807         786   

Expansion Areas:

                 

Acreage Under Lease

     156         131         1,824         1,155         10,153         9,419   

Acreage Under Option

                                               
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     866         811         7,411         5,998         14,547         13,240   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Approximately 77% of our net acreage, including acreage under option, was acquired in 2011, with the majority of such leases under five year primary term leases. In addition, our typical lease terms along with unit regulatory rules provide us flexibility to continue lease ownership through either establishing production or actively drilling prospects.

 

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Drilling activity

The following table summarizes our drilling activity for the years ended December 31, 2011, 2010 and 2009. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

 

     Years Ended December 31,  
     2011      2010      2009  
     Gross      Net      Gross      Net      Gross      Net  

Development wells:

                 

Productive

     29         29         16         16         5         5   

Dry holes

     0         0         2         2         0         0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     29         29         18         18         5         5   

Exploratory wells:

                 

Productive

     2         2         1         1         0         0   

Dry holes

     0         0         0         0         2         2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     2         2         1         1         2         2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total wells

     31         31         19         19         7         7   

As of December 31, 2011, there was 1 gross (1 net) exploratory well being drilled and 8 gross (7 net) development wells that have been drilled and are undergoing completion.

Our drilling activity has increased over the last three years, and we were operating four drilling rigs on our properties as of December 31, 2011. Our drilling activity has primarily focused on delineation and appraisal of our primary operating areas in the Pine Prairie, South Bearhead Creek/Oretta, West Gordon and North Cowards Gully fields, as well as recent expansion into newly acquired acreage. In addition to the drilling activity listed above, a portion of our capital program over the last three years has also been focused on re-entering and recompleting productive zones in existing wellbores. In 2011, 2010 and 2009 we had a total of 4 gross (4 net) wells that were deemed dry wells, two of which were geologic dry holes and two of which were caused by mechanical problems encountered while drilling which prevented us from reaching the reservoir targets.

Marketing and Major Customers

We sell our oil and natural gas to third-party purchasers. We are not dependent upon, or contractually limited to, any one purchaser or small group of purchasers. However, for the year ended December 31, 2011, Chevron and Gulfmark accounted for 39% and 38% of our revenues, respectively. For the year ended December 31, 2010, Chevron, Crosstex, and Gulfmark accounted for 66%, 19%, and 12% of our revenues, respectively. For the year ended December 31, 2009, Chevron and Gulfmark accounted for 66% and 14% of our revenues, respectively. Due to the nature of oil and natural gas markets and because we sell our oil production to purchasers that transport by truck rather than by pipelines, we do not believe the loss of a single purchaser or a few purchasers would materially affect our ability to sell our production.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect

 

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defects affecting those properties, we are typically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have cured known material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant properties and, depending on the materiality of properties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

Seasonality

Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas.

Competition

The oil and natural gas industry is highly competitive. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see “Risk Factors” beginning on page 17.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently

 

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amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, or FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of Transportation of Oil

Currently 100% of our oil sales are transported by truck. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an annual indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index ceiling slightly, effective July 2001. FERC reviews the annual indexing factor every five years. For the five-year period commencing July 1, 2011, the annual indexing factor is equal to the Producer Price Index for Finished Goods plus 2.65%. We cannot predict whether or what extent the index factor may change in the future.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

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