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EX-23.3 - CONSENT OF RALPH E. DAVIS ASSOCIATES, INC. - New Source Energy Corpd218427dex233.htm
EX-23.2 - CONSENT OF BDO USA, LLP - New Source Energy Corpd218427dex232.htm
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on April 23, 2012.

Registration No. 333-176548

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 5

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

New Source Energy Corporation

(Exact name of registrant as specified in its charter)

 

 

 

Delaware
  1311
  45-2735455
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)

914 North Broadway, Suite 230

Oklahoma City, Oklahoma 73102

(405) 272-3028

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

 

 

Kristian B. Kos President and Chief Executive Officer

New Source Energy Corporation

914 North Broadway, Suite 230

Oklahoma City, Oklahoma 73102

(405) 272-3028 (Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Roger A. Stong

James W. Larimore

Crowe & Dunlevy, A Professional Corporation

20 North Broadway, Suite 1800

Oklahoma City, Oklahoma 73102

(405) 235-7700

 

Edward S. Best

Dallas Parker

Mayer Brown LLP
700 Louisiana Street, Suite 3400

Houston, Texas 77002
(713) 238-3000

 

 

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. (Check one):

 

Large accelerated filer  ¨   Accelerated filer  ¨   Non–accelerated filer  x   Smaller reporting company  ¨
    (Do not check if a smaller reporting company)  

CALCULATION OF REGISTRATION FEE

 

 

 

Title of Each Class of

Securities to be Registered

   Amount to be
Registered(1)
     Proposed Maximum
Offering Price
Per Share
     Proposed Maximum
Aggregate Offering
Price(2)
     Amount of
Registration
Fee(3)
 

Common Stock, par value $0.001 per share

     10,465,000       $ 12.00       $ 125,580,000       $ 14,541.47   

 

 
(1) Includes 1,365,000 shares of common stock which may be issued on exercise of a 30-day option granted to the underwriters to cover over-allotments, if any.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(a) under the Securities Act of 1933.
(3) The registration fee is equal to the sum of (a) the product of (i) the proposed maximum aggregate offering price of $100,000,000, as previously proposed on the initial filing of this Registration Statement on August 29, 2011 and (ii) the then-current statutory rate of $116.10 per $1,000,000 (previously paid) and (b) the product of (i) the marginal increase of $25,580,000 in the proposed maximum aggregate offering price hereunder and (ii) the current statutory rate of $114.60 per $1,000,000.

 

 

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

 

 

 


Table of Contents
Index to Financial Statements

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

 

 

 

 

 

Prospectus    Subject to Completion, dated April 23, 2012

 

 

9,100,000 Shares

Common Stock

LOGO

New Source Energy Corporation

New Source Energy Corporation is offering 9,100,000 shares of its common stock. 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 $10.00 and $12.00 per share.

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

Investing in our common stock involves a high degree of risk. See “Risk Factors ” beginning on page 17 of this prospectus for a discussion of certain risks that you should consider before investing.

 

      Per Share        Total  

Public offering price

   $                              $                        

Underwriting discount and commissions

   $           $     

Net proceeds to us, before expenses

   $           $     

We have granted the underwriters an option to purchase up to an additional 1,365,000 shares from us at the initial public offering price, less underwriting discount and commissions, within 30 days after the date of this offering to cover over-allotments, if any.

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

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

 

 

 

BMO Capital Markets   KeyBanc Capital Markets
SunTrust Robinson Humphrey   Johnson Rice & Company L.L.C.

Baird

 

 

The date of this prospectus is             , 2012


Table of Contents
Index to Financial Statements

LOGO

 

LOGO

 

LOGO    LOGO

Our core operating area is east-central Oklahoma. We expect to acquire additional properties in and around our core operating area to take advantage of our and our affiliated contract operator’s knowledge, experience, and access to existing infrastructure in the area. We target conventional resource plays in our area of concentration, focusing on the large area of hydrocarbons and water that exists below the free oil zone.


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     17   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     41   

USE OF PROCEEDS

     44   

DIVIDEND POLICY

     45   

CAPITALIZATION

     46   

DILUTION

     47   

SELECTED HISTORICAL FINANCIAL DATA

     49   

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

     52   

BUSINESS

     67   

MANAGEMENT

     91   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     95   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     104   

PRINCIPAL STOCKHOLDERS

     107   

DESCRIPTION OF CAPITAL STOCK

     108   

SHARES ELIGIBLE FOR FUTURE SALE

     110   

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS

     112   

UNDERWRITING; CONFLICTS OF INTEREST

     115   

LEGAL MATTERS

     121   

EXPERTS

     121   

WHERE YOU CAN FIND MORE INFORMATION

     121   

GLOSSARY OF CERTAIN INDUSTRY TERMS

     121   

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. We have not authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We 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.

Until             , 2012 (the 25th day after the date of this prospectus), all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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 and estimates are reliable and that the information is accurate and complete, we have not independently verified the third-party information and actual data may differ materially from our estimates.

 

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Index to Financial Statements

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained 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 financial statements and related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of our common stock is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus under the heading “Glossary of Certain Industry Terms.” In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and the “company” refer to New Source Energy Corporation.

Unless otherwise stated or the context otherwise requires, all financial, reserve and historical operations data presented in this prospectus as of dates and for periods ended prior to August 12, 2011 reflect only the portion of our oil and natural gas assets acquired from Scintilla, LLC (“Scintilla”) on August 12, 2011 (the “Scintilla Assets”) and do not reflect the portion of our oil and natural gas assets acquired from certain other parties on August 12, 2011 (the “Other Contributed Assets”). All financial, reserve and historical operations data as of dates and for periods after August 12, 2011, reflect both the Scintilla Assets and the Other Contributed Assets, which together we refer to as the “Acquired Assets.” For further discussion of the accounting treatment of the Acquired Assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview and Basis of Presentation.” For further discussion of our presentation of reserve and operations data, see “Summary Reserve and Operations Data.”

NEW SOURCE ENERGY CORPORATION

We are an independent energy company engaged in the development and production of onshore oil and liquids-rich natural gas projects in the United States. Our primary business strategy is to utilize specialized processes and low cost access to existing infrastructure to consistently and economically develop and produce hydrocarbons from known reservoirs previously deemed not prospective by others. See “Business—Specialized Processes” and “—Our Principal Business Relationships—Low Cost Access.” Our current properties consist of non-operated working interests in the Misener-Hunton (the “Hunton”) formation, a conventional resource reservoir in east-central Oklahoma. This formation has a 90-year history of exploration and development and thousands of wellbore penetrations that have led to more accurate geologic mapping. We believe our position as non-operator and our strategic relationship as an affiliate of our contract operator, New Dominion, LLC (“New Dominion” or our “contract operator”), allow us to maintain low fixed operating expenses by utilizing a limited in-house employee base aside from our management team. We are committed to pursuing conventional resource plays in proximity to our existing asset base that are similar in profile and that carry what we believe is minimal exploration risk. As of December 31, 2011, the estimated proved reserves on our properties were approximately 23.8 MMBoe, of which approximately 34% were classified as proved developed reserves and of which approximately 63% were comprised of oil and natural gas liquids. Average net daily production from our properties during the year ended December 31, 2011 was 3,725 Boe/d. Based on net production from our properties for the year ended December 31, 2011, the total proved reserves associated with our properties had a reserve to production ratio of 17.5 years.

We were formed on July 12, 2011, to acquire and develop oil and natural gas properties. On August 12, 2011, we acquired the Acquired Assets in exchange for 21.2 million shares of our common stock and $60.0 million in cash. At the time of our acquisition of the Acquired Assets, we became a party to agreements by which New Dominion will continue as the contract operator of those properties. In addition to the Acquired Assets,

 

 

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Index to Financial Statements

effective as of December 1, 2011, we entered into an agreement to acquire from New Dominion certain undeveloped leasehold in the Hunton formation located in the Golden Lane field, which we refer to as the “Golden Lane Extension.” Both Scintilla and New Dominion are owned and controlled by our principal stockholder, chairman and senior geologist, David J. Chernicky. Scintilla has served as Mr. Chernicky’s holding company for his working interests, while New Dominion has acted as the operator of those assets and related infrastructure. New Dominion has operated the Acquired Assets for 12 years, completing and economically producing from more than 98% of all wells it has drilled in the Hunton formation using the same specialized processes that will be utilized in the operation and development of our properties. As a result of our relationship as an affiliate of Scintilla and New Dominion, we will benefit from the operational efficiencies of these specialized processes to maintain our low average finding, developing and operating costs.

We have a right of first refusal to acquire up to 90% of Scintilla and New Dominion’s combined interest in all future oil and natural gas projects they pursue for 25 years (i.e., until August 12, 2036). As of March 1, 2012, Scintilla and New Dominion collectively held approximately 74,713 net acres in other formations above and below the Hunton formation that we believe have reservoir profiles similar to our properties. If we exercise our right of first refusal in full with respect to these interests as or after they are developed, we could acquire as much as 67,241 net acres in these formations. Pursuant to our right of first refusal agreement, we have the right to acquire oil and natural gas projects from New Dominion and Scintilla at and after the point in time such properties are determined to have proved reserves of oil and natural gas. We believe our strategic partnership with New Dominion and Scintilla and the common ownership of Mr. Chernicky in New Dominion, Scintilla and our company enhance our ability to grow our production and expand our proved reserve base over time. In addition, this relationship provides us with significant influence over the rate of development of our long-lived, low cost asset base as compared to other traditional non-operators. It also provides us access to personnel with extensive technical expertise and industry relationships and perpetual access to existing infrastructure at what we believe are favorable rates. See “Business—Material Definitive Agreements” and “Certain Relationships and Related Party Transactions.”

Our properties are located in east-central Oklahoma and consist of mature, legacy oil and natural gas reservoirs. We believe that, through application of specialized processes, our properties are low risk due to predictable production profiles, low decline rates, long reserve lives and modest capital requirements. Our properties consist of non-operated working interests in producing and undeveloped leasehold acreage and in identified producing wells with an average working interest of 55% in our wells within the Luther field and a working interest ranging from 21% to 87% (38% weighted average) in our wells within the Golden Lane field. As of March 1, 2012, we had 46,080 gross (13,387 net) acres in the Luther field and 155,360 gross (42,481 net) acres in the Golden Lane field.

Ralph E. Davis Associates, Inc., our independent reserve engineers, estimated the net proved reserves on our properties to be approximately 23.8 MMBoe as of December 31, 2011, 63% of which were classified as oil and natural gas liquids and 37% of which were classified as natural gas. The average net daily production rate from our properties during the year ended December 31, 2011 was 3,725 Boe/d.

 

 

2


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Index to Financial Statements
    Estimated Proved Reserves at
December 31, 2011 (1)
    Production for the
Year Ended
December 31, 2011
    Projected
2012
Capital
Expenditures
(MM)
    Proved
Undeveloped
Drilling
Locations as
of
December 31,
2011
 

Field

  Total
Proved
(MBoe)
    Percent
of
Total
    Percent
Proved
Developed
    Percentage
of

Depletion  (2)
    Percent
Oil and
Liquids
    PV-10
(MM)(3)
    Average
Net
Daily
Production
(Boe/d)
    Percent
of
Total
     
                    Gross     Net  

Golden Lane

    18,284        76.9     40.8     53.8     71.3   $ 275.3        3,450        92.6   $ 28.9        231        54.7   

Luther

    5,507        23.1     9.4     7.4     35.0   $ 52.8        275        7.4   $ 24.9        59        16.2   
 

 

 

   

 

 

         

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    23,791        100.0     33.5     47.7     62.9   $ 328.1        3,725        100.0   $ 53.8        290        70.9   

 

(1) Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months, which were $96.19 per Bbl of crude oil, $50.02 per Bbl of natural gas liquids and $4.12 per Mcf of natural gas. Adjustments were made for location and the grade of the underlying resource, which resulted in an average decrease of $3.24 per Bbl of crude oil, an average decrease of $1.69 per Bbl of natural gas liquids and a decrease of between $0.12 and $0.28 per Mcf of natural gas.
(2) Percentage of depletion was calculated by dividing cumulative production from our properties in these fields by the sum of proved reserves attributable to such properties and cumulative production from such properties.
(3) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 typically differs from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) because it does not include the effects of income tax. However, the Scintilla Assets’ PV-10 and Standardized Measure as of December 31, 2009 and 2010 are equivalent because as of those dates the Scintilla Assets were held by a limited liability company not subject to entity-level taxation. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.

The following table provides an illustration of our PV-10 and our Standardized Measure reflecting the effect of income taxes:

 

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

PV-10

   $ 142,018       $ 178,471       $ 328,137   

Estimated income taxes(a)

     55,245         69,425         118,139   
  

 

 

    

 

 

    

 

 

 

Standardized Measure

   $ 86,773       $ 109,046       $ 209,998   
  

 

 

    

 

 

    

 

 

 

 

 

  (a) Scintilla, which owned the Scintilla Assets before they were contributed to us, is a partnership for federal income tax purposes and, therefore, is not subject to entity-level taxation. Historically, federal or state income taxes have been passed through to the member owners of Scintilla. However, as a corporation, we are subject to U.S. federal and state income taxes. The estimated taxes shown above illustrate the effect of estimated income taxes on net revenues as of December 31, 2009 and 2010, assuming we had been subject to corporate-level income tax and further assuming an estimated statutory combined 38.9% federal and state income tax rate.
  (b) Our PV-10 and Standardized Measure as of December 31, 2009 and 2010, respectively, are derived from revised estimates of our proved reserves after the retroactive application of a change in methodology utilized in estimating proved undeveloped reserves. The related effects of this change in methodology on our results of operations and financial condition were immaterial and therefore have not been reflected in our historical financial statements included in this prospectus. For further information regarding this change in methodology, see the discussion in the unaudited supplementary information to our financial statements beginning on page F-25.

We use the term “conventional resource play” to refer to high water saturation (35 – 99%) hydrocarbon reservoirs that typically have been deemed not prospective by others. Conventional resource plays are usually located around and below conventional reservoirs, although they can exist independently. These reservoirs tend to be continuous hydrocarbon zones existing over a contiguous and potentially large geographical area.

 

 

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Index to Financial Statements

Conventional resource plays exhibit low exploration risk with consistent results and predictable estimated ultimate recovery (“EUR”). With the implementation of specialized processes, we believe we have the ability to economically develop these large-scale reservoirs.

Our contract operator and senior geologist have developed conventional resource plays for 25 years, which has provided them with insights on the physical processes at work and a significant amount of practical operating experience in how to economically produce from these reservoirs. As a result of this experience, they have developed and refined processes that they will utilize in developing our conventional resource plays. Prior conventional resource plays in which our contract operator and senior geologist have used these specialized processes to successfully and economically produce oil and natural gas include the Red Fork formation in the Mount Vernon field in central Oklahoma, which they developed in the late 1980s, and the Hunton formation in the Carney and Golden Lane fields in central Oklahoma, which they commenced developing in 1999. Each of these projects had been passed over by other industry operators because of its high saltwater content. The cumulative production from these fields from January 1, 1989 through December 31, 2011 following application of their specialized processes is 33.4 MMBoe.

The Hunton formation is our primary conventional resource play in east-central Oklahoma. We intend to continue to develop our Golden Lane and Luther fields in this formation where we maintained interests in approximately 219 gross (86.1 net) producing wells as of December 31, 2011. Our acreage position had 290 gross (70.9 net) proved undeveloped (PUD) locations as of December 31, 2011. Our contract operator is currently using four rigs to drill on our properties, which may be increased to up to eight over the next twelve months. Our contract operator has completed an average of 25 gross wells per year on our acquired properties over the past six years.

Our 25-year right of first refusal agreement includes, among other potential opportunities, existing rights to produce in areas covering approximately 74,713 net acres of prospective conventional resource reservoir formations located above and below the Hunton formation, such as the Cleveland, Red Fork, Caney, Mississippian and Arbuckle. If we exercise our right of first refusal in full with respect to these interests as or after they are developed, we could acquire as much as 67,241 net acres in these formations. These reservoirs have current production, and our contract operator is in the process of estimating the proved reserves associated with the properties currently held by it and Scintilla in these reservoirs, pending third-party evaluation. We also have identified similar conventional resource play leaseholds held by third parties in and around our primary acreage in east-central Oklahoma that we will attempt to acquire to increase our proved reserves and drilling inventory.

Our method of hydrocarbon recovery relies upon exploiting the reservoir through development, rather than exploration. Our technical team, in conjunction with our contract operator, has geologic and engineering expertise in horizontal well design, submersible pump placement, fluid and hydrocarbon separation and saltwater disposal. We believe this experience helps us realize production efficiencies utilizing methodologies that provide a predictable ultimate recovery of hydrocarbons. In developing new reserves in conventional resource plays, we employ, in conjunction with our contract operator, the following six essential components:

 

   

proper geologic assessment of the reservoir, which is facilitated by data from numerous existing well penetrations;

 

   

a well-trained and knowledgeable technical team to maintain efficient production;

 

   

strategic placement of wells to maximize the benefit of wells working in concert to create the appropriate draw down in reservoir pressure;

 

   

an economic high-volume saltwater transportation and disposal system;

 

   

abundant and economic high-current three-phase electrical power; and

 

   

a high-volume, liquids-rich gas gathering and processing system.

 

 

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Index to Financial Statements

Business Strategy

Our objective is to increase stockholder value by increasing reserves, production and cash flows at an attractive return on capital. We intend to accomplish these objectives by executing on the following key strategies:

 

   

Focus on Conventional Oil and Liquids-Rich Resource Plays. We are focused on developing and converting conventional oil and liquids-rich resource plays into cost-efficient development projects. This strategy enables us to leverage our expertise in economically producing reserves that previously have been deemed not prospective by others.

 

   

Accelerate Development of Existing Low Cost Proved Inventory. In the near term, we and our contract operator intend to accelerate the drilling of our low risk, long lived PUD inventory to maximize the value of our resource potential using existing infrastructure. We and our contract operator will continuously evaluate our drilling program and expect to select the types and spacing of wells we will drill in a manner aimed at optimizing flow and maximizing the recovery of hydrocarbons from the reservoir. We have identified 102 gross (34.1 net) PUD locations as of December 31, 2011 for prospective development through increased density wells.

 

   

Maintain Our Low Cost Operating Structure. We are focused on continuous improvement of our operating measures through our contract operator. We believe that the size and concentration of our acreage within our project areas provide us with the opportunity to continue to capture economies of scale, including the ability to use our contract operator’s existing infrastructure at what we believe to be attractive rates. In addition, we, along with our contract operator, attempt to reduce the drilling, completion and infrastructure costs associated with the development of our properties by drilling multiple wells from a single pad site.

 

   

Leverage Strategic Relationships with New Dominion and Scintilla. We intend to maximize the benefits of our relationships as an affiliate of New Dominion and Scintilla to help control our costs, access existing infrastructure at what we believe are favorable rates, reduce exploration risk, and maintain flexibility to determine where and when to deploy our capital. Additionally, under our agreements with New Dominion as our contract operator, New Dominion acquires and holds title to undeveloped leasehold for our benefit. New Dominion may allow us to defer paying for our interest until such time as development of this acreage commences, which allows us to focus our capital expenditures on properties with near-term drilling and completion activities.

 

   

Pursue Accretive Acquisitions. We intend to pursue bolt-on acquisitions of properties complementary to our core acreage, including properties subject to our right of first refusal agreement, when we determine such properties carry minimal or no exploration risk. We will pursue additional acquisition opportunities when we believe we possess a strategic or technical advantage due to our existing liquidity, operational experience and access to infrastructure.

Competitive Strengths

We will rely upon the following combination of strengths to implement our strategies:

 

   

Management Team with Proven Ability to Develop Conventional Resource Plays. Our senior management team averages over 25 years of industry experience, including our senior geologist, David J. Chernicky, who has over 28 years of experience in producing oil and natural gas from conventional resource plays in the area of our core assets. Our management team has developed specialized processes that allow us to develop assets that historically have been deemed not prospective by others.

 

   

Strategic Relationship with Related Parties. Our relationships with Scintilla and New Dominion provide us with access to saltwater disposal and other key infrastructure, drilling rigs, completion services, oilfield equipment and oilfield services at what we believe are favorable rates. In addition, the right of first refusal we hold from Scintilla and New Dominion provides us with an exclusive option to acquire additional assets meeting our reservoir criteria at and after the point in time they are determined

 

 

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Index to Financial Statements
 

to have proved reserves of oil and natural gas through the efforts of Scintilla and our contract operator. Our contract operator has a strong track record, completing and economically producing from more than 98% of all wells it has drilled in the Hunton formation since beginning to develop the play in 1999. The extensive knowledge and experience of our contract operator relating to the Hunton formation also permits it to more easily identify additional opportunities for the acquisition of prospective Hunton formation interests. Our arrangements with our contract operator grant us rights in these additional interests in our areas of mutual interest when acquired, and our contract operator may defer our obligation to pay for them until development commences.

 

   

Large, Multi-Year Drilling Inventory with Predictable Results. As of December 31, 2011, there were 290 gross (70.9 net) PUD locations targeting the Hunton formation on our properties. With a large portion of our leasehold held by production, and because of our relationship as an affiliate of our contract operator, we have the ability to influence the timing of our drilling projects. Our reserves have significant production history and predictable decline rates.

 

   

Long-Lived Reserves with High and Increasing Liquids Yield. The average productive life of our wells producing from the Hunton formation (on 640-acre spacing) is 18.5 years. The initial average Btu content of natural gas produced from this formation is approximately 1100 Btu, increases at an average of 5% per year and, based on past experience, can ultimately reach approximately 2100 Btu.

 

   

Competitive Cost Structure. Our position as non-operator and our ability to leverage our relationship as an affiliate of our contract operator allow us to mitigate significant fixed operating expenses by maintaining a limited in-house employee base apart from our management team. Our focus on conventional resource plays utilizing our contract operator’s specialized processes has resulted in average all-in finding and development costs, including revisions, on our properties of $5.68 per Boe over the three-year period ended December 31, 2011, excluding the estimated future development costs associated with PUD reserves. Production costs on our properties averaged $6.76 per Boe during the year ended December 31, 2011.

 

   

Forced Pooling. We expect to acquire additional working interests through “forced pooling” pursuant to Oklahoma law. A forced pooling action, which is very common in Oklahoma, allows a working interest owner to compel the pooling of acreage in a subject spacing unit for the purposes of causing a well or wells to be drilled. Assuming a successful application for a forced pooling order, in our contract operator’s experience this process would allow us to develop our properties with little risk of another interest owner preventing such development. During the three-year period ended December 31, 2011, our contract operator has successfully utilized forced pooling procedures to drill 78 wells in the Golden Lane and Luther fields. For a discussion regarding additional working interests we may obtain through forced pooling, see “Business—Specialized Processes—Forced pooling process.”

 

   

Accessible Centralized Core Geographic Area. All of our existing acreage, as well as many potential opportunities we have identified for future growth, are within a 150-mile radius of our corporate headquarters in Oklahoma City, Oklahoma. This allows us to utilize and extend existing infrastructure at a reduced cost.

 

   

Financial Flexibility. Existing internal cash flow generation allows us to continue the current rate of development of our properties. As of December 31, 2011, pro forma for this offering, we would have had minimal indebtedness and $92.3 million of total liquidity, including availability under our credit facility and cash on hand, that would allow us to accelerate growth, make strategic acquisitions and develop additional reservoirs.

Acquisition of Assets and Related Transactions

On August 12, 2011, we entered into a four-year, $150.0 million credit agreement with a syndicate of banks led by Bank of Montreal providing for a senior secured revolving credit facility with an initial borrowing base of

 

 

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Index to Financial Statements

$72.5 million and with a $5.0 million subfacility for standby letters of credit. For a description of the material terms of our credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facility.”

On the same date, pursuant to two contribution agreements, one of which was with Scintilla, an entity controlled by our chairman and senior geologist, David J. Chernicky, we acquired the Acquired Assets, which consist of (i) certain oil and natural gas leases and a working interest ranging from 21% to 87% (38% weighted average) in certain wells in the Hunton formation located in the Golden Lane field (the “Golden Lane Assets”), and (ii) certain oil and natural gas leases and an average 55% working interest in certain wells in the Hunton formation located in the Luther field (the “Luther Assets”). We issued 20.0 million shares of our common stock and paid a total of $60.0 million in cash, which we borrowed under our credit facility, for the Scintilla Assets. Scintilla assigned its rights to receive these shares of common stock to the David J. Chernicky Trust. In exchange for the Other Contributed Assets, we issued an additional 1.2 million shares of our common stock. Since the Other Contributed Assets were acquired from parties not under common control with us, the Other Contributed Assets are not included in our historical financial statements and proved reserves as of dates and for periods ended prior to August 12, 2011, but are included in our financial statements and proved reserves as of dates and for periods ended after that date. For further discussion of the accounting treatment of the Acquired Assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview and Basis of Presentation.”

We also entered into a registration rights agreement with the parties contributing the Acquired Assets with customary provisions requiring us to register the shares of our common stock issued in connection with the contribution transactions. Certain of the contributing parties, including the David J. Chernicky Trust as successor in interest of Scintilla, will be subject to lock-up agreements generally precluding their sale of shares of our common stock for 180 days from the date of this prospectus. See “Underwriting; Conflicts of Interest.”

Under agreements entered into in connection with the contribution of assets, we obtained a right of first refusal from Scintilla and New Dominion for a 25-year period to acquire up to 90% of their combined interest in oil and natural gas projects determined to have proved reserves.

We also entered into a new joint operating agreement related to the Luther Assets (the “Luther JOA”) and became a party to an existing participation agreement related to the Golden Lane Assets (the “Golden Lane Participation Agreement”) pursuant to which New Dominion will serve as the contract operator of these properties. We and the other parties to these agreements have access to New Dominion’s existing infrastructure, particularly saltwater disposal pipelines and wells and electricity, at what we believe are favorable rates.

On February 27, 2012, we entered into an agreement confirming a prior oral agreement with Scintilla and New Dominion under which, effective December 1, 2011, we acquired and agreed to participate in the development of 90% of Scintilla and New Dominion’s combined interest in undeveloped Hunton acreage in the Golden Lane Extension, which is located to the north and east of the area of mutual interest defined in the Golden Lane Participation Agreement. The Golden Lane Extension accounts for 4,626 MBoe of our proved undeveloped reserves and 96 gross (15.7 net) PUD locations as of December 31, 2011. We are obligated to reimburse New Dominion for our proportionate share of the costs of this leasehold, plus a fee equal to 15% of such costs. In connection with the development of this acreage, we expect to enter into one or more joint operating agreements with New Dominion and Scintilla on terms substantially similar to our Luther JOA with those same parties.

For further discussion of these and other transactions, see “Business—Material Definitive Agreements” and “Certain Relationships and Related Party Transactions.

Private Placement of Common Stock

On August 12, 2011, we completed a private placement of 157,500 shares of our common stock at a price of $10.00 per share, solely to accredited investors, raising gross proceeds of approximately $1.6 million. While our

 

 

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Index to Financial Statements

existing cash flow is sufficient to maintain our current rate of development, we completed this private placement to provide us with additional financial flexibility pending the completion of this offering.

Recent Developments

During the three months ended March 31, 2012, our contract operator continued to execute our drilling program, spudding 11 wells, six of which have been completed and are currently producing. We estimate that our average daily production during the first two months of 2012 was approximately 3,659 Boe/d. We estimate that our capital expenditures during the first two months of 2012 were approximately $6.3 million, which is in line with our current 2012 capital expenditure budget of $53.8 million based on the number of wells we drilled in the first two months of the year compared to our full year drilling plans for 2012.

Summary Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas development, 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 activities on our properties and our ability to execute our business strategies, 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 decline in oil and 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.

 

   

Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

 

   

We do not currently operate any of our properties, and therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of our assets.

 

   

Our agreements with our contract operator contain terms that may be disadvantageous to us.

 

   

We rely on relationships with affiliates to access infrastructure that is critical to the development of our assets. Adequate infrastructure may not be available at an economic rate.

 

   

Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

   

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

 

   

A substantial portion of our estimated proved reserves is undeveloped and may not ultimately be developed or become commercially productive, which could have a material adverse effect on our future oil and natural gas reserves and production, and therefore, our future cash flow and income.

 

   

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

 

   

Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

 

   

We expect to be a “controlled company” within the meaning of the NYSE rules and, if applicable, would qualify for and may rely on exemptions from certain corporate governance requirements.

 

   

Following this offering, we will be a public company and will be required to expend significant time and commit substantial financial resources to complying with reporting and disclosure requirements, stock exchange rules and related matters applicable to public companies.

 

 

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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.”

Principal Stockholders

As a result of the transaction by which we acquired the Scintilla Assets, the David J. Chernicky Trust became our principal stockholder. Following the completion of this offering, we expect that the David J. Chernicky Trust and its affiliates will own approximately 61% of the outstanding shares of our common stock.

Corporate Information

Our principal executive offices are located at 914 N. Broadway, Suite 230, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 272-3028. Our website is www.newsource.com. 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 us

9,100,000 Shares

 

Common stock to be outstanding after this offering

32,991,500 Shares

 

Over-allotment option

1,365,000 Shares

 

Use of proceeds

We expect to receive approximately $90.3 million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $11.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses. Each $1.00 increase (decrease) in the public offering price will increase (decrease) our expected net proceeds by approximately $8.5 million. We intend to use the net proceeds from this offering first to repay outstanding indebtedness under our credit facility, which as of March 1, 2012, was approximately $68.5 million.

In addition, 1.2 million shares of restricted stock held by our executive officers will vest upon the completion of this offering. We expect that certain of our executive officers will request that we withhold shares of their common stock to satisfy the withholding tax obligations of these executives incurred upon the vesting of such stock. Assuming an offering price of $11.00 per share and an assumed combined state and federal tax rate of 30.5%, we estimate that up to approximately $4.0 million of the remaining net proceeds from this offering will be used to pay this withholding tax. Remaining proceeds will be used to fund our development program, to fund acquisitions and for general corporate purposes. See “Use of Proceeds.”

 

Dividend policy

We do not intend to pay any cash dividends on our common stock for the foreseeable future. Instead, we intend to retain any earnings for use in the operation of our business and to fund future growth. In addition, our credit facility prohibits us from paying cash dividends. See “Dividend Policy.”

 

Proposed New York Stock Exchange listing

We have applied to list shares of our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “NSE.”

 

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.

 

Conflict of interest

Certain of the underwriters or their affiliates currently hold outstanding indebtedness under our credit facility. Because affiliates of each of BMO Capital Markets Corp., KeyBanc Capital Markets Inc., and SunTrust Robinson Humphrey, Inc. will receive, in the

 

 

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Index to Financial Statements
 

aggregate, more than 5% of the net proceeds from this offering as a result of the repayment of such indebtedness from the proceeds of this offering, this offering is being made in compliance with Rule 5121 of the Financial Industry Regulatory Authority (“FINRA”). FINRA Rule 5121 requires that a “qualified independent underwriter” participate in the preparation of the registration statement of which this prospectus forms a part and exercise the usual standards of due diligence with respect thereto. Johnson Rice & Company L.L.C. has assumed the responsibilities of acting as the qualified independent underwriter in this offering. No underwriter having a conflict of interest under FINRA Rule 5121 will confirm sales to any account over which the underwriter exercises discretionary authority without the specific written approval of the accountholder. See “Underwriting; Conflicts of Interest.”

Unless specifically stated otherwise, all information in this prospectus assumes no exercise of the over-allotment option. In addition, the number of shares of common stock to be outstanding after this offering, unless otherwise indicated:

 

   

is based on 24,257,500 shares of common stock outstanding as of April 23, 2012, including 2.9 million shares of restricted common stock held by our executive officers, of which 1.2 million shares will vest upon the completion of this offering; and

 

   

excludes 366,000 shares of restricted common stock we expect our executive officers to surrender to satisfy withholding tax obligations incurred upon the vesting of such stock.

 

 

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SUMMARY HISTORICAL FINANCIAL DATA

The following tables set forth summary financial data relating to our operations and financial condition on a historical basis as of and for the periods indicated. Because Scintilla is under common control with us, we recognized the Scintilla Assets and related liabilities acquired from Scintilla at their historical carrying values, and we have presented the historical operations of the Scintilla Assets on a retrospective basis for all applicable periods presented in this prospectus. Since the Other Contributed Assets were acquired from parties not under common control with us, they have been accounted for as purchases at fair value, with the results of operations attributable to such properties included in our financial statements only from the acquisition date. As such, the Other Contributed Assets are not included in our historical financial statements prior to August 12, 2011. For further discussion of the accounting treatment of the Acquired Assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview and Basis of Presentation.” In addition to the Acquired Assets, our financial, reserve and historical operations data for periods after December 1, 2011 also reflect our interest in the Golden Lane Extension.

The summary historical financial data as of December 31, 2010 and 2011 and for each of the years ended December 31, 2009, 2010 and 2011 are derived from our audited historical financial statements included elsewhere in this prospectus. The summary historical financial data as of December 31, 2009 are derived from our audited historical financial statements, which are not included in this prospectus. In management’s opinion, these financial statements include all adjustments necessary for the fair presentation of financial condition as of such dates and results of operations for such periods.

Our historical financial statements included in this prospectus may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand-alone public company during all periods presented. The summary historical financial data reflect historical accounts attributable to the Scintilla Assets on a “carve-out” basis, including allocated overhead from our predecessor in interest, for periods prior to our acquisition of the Scintilla Assets on August 12, 2011 and do not reflect any estimate of additional overhead that we may incur as a separate company. We expect to incur additional annual costs associated with our compliance and disclosure obligations as a public company and to incur significant non-cash compensation expense in the financial quarter in which this offering occurs upon the vesting of restricted common stock granted to management as part of our formation, and our overhead costs could be materially different. Accordingly, for this and other reasons, the summary historical financial data should not be relied upon as an indicator of our future performance.

For a detailed discussion of the summary historical financial information contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following tables should also be read in conjunction with “Selected Historical Financial Data” and our historical financial statements and the notes to those financial statements 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.

 

 

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Index to Financial Statements
     Year Ended
December 31,
 
   2009     2010     2011  
   (in thousands, except
per share amounts)
 

Statement of Operations Data:

      

Revenues:

      

Oil sales

   $ 4,388      $ 5,336      $ 4,912   

Natural gas sales

     7,773        9,866        9,886   

Natural gas liquids sales

     18,895        26,522        35,179   
  

 

 

   

 

 

   

 

 

 

Total revenues

     31,056        41,724        49,977   
  

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

      

Oil and natural gas production expenses

     8,153        8,101        9,186   

Oil and natural gas production taxes

     1,215        2,968        2,304   

General and administrative

     578        670        7,660   

Depreciation, depletion, and amortization

     13,942        15,404        16,159   

Accretion expense

     44        51        59   
  

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     23,932        27,194        35,368   
  

 

 

   

 

 

   

 

 

 

Operating income

     7,124        14,530        14,609   

Other income (expense):

      

Interest expense

     (1,943     (2,648     (3,735

Realized and unrealized gains (losses) from derivatives

     —          (573     (1,504
  

 

 

   

 

 

   

 

 

 

Income before income taxes

     5,181        11,309        9,370   

Income tax expense(1)

     —          —          10,015   
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 5,181      $ 11,309      $ (645
  

 

 

   

 

 

   

 

 

 

ALLOCATION OF 2011 NET LOSS

      

Net loss

       $ (645

Net income prior to purchase of properties from Scintilla in exchange for common stock on August 12, 2011

         10,146   
      

 

 

 

Net loss subsequent to purchase of properties from Scintilla in exchange for common stock on August 12, 2011

       $ (10,791
      

 

 

 

Net loss per common share from August 12, 2011 to December 31, 2011 - basic and diluted(2)

       $ (0.51
      

 

 

 

Weighted average shares outstanding used in computing net loss per share - basic and diluted(2)

         21,358   
      

 

 

 

Pro forma net income reflecting change of tax status

      

(unaudited)(3)

      

Income before income taxes

   $ 5,181      $ 11,309      $ 9,370   

Pro forma income tax expense

     1,259        3,733        3,028   
  

 

 

   

 

 

   

 

 

 

Pro forma net income

   $ 3,922      $ 7,576      $ 6,342   
  

 

 

   

 

 

   

 

 

 

Pro forma earnings per share - basic and diluted

      

(unaudited)(3)

      

Pro forma net income per common share

   $ 0.20      $ 0.38      $ 0.31   
  

 

 

   

 

 

   

 

 

 

Shares used in computing earnings per share

     20,000        20,000        20,524   
  

 

 

   

 

 

   

 

 

 

 

(1) Scintilla, which owned the Scintilla Assets before they were acquired by us on August 12, 2011, is treated as a partnership for income tax purposes and, as such, Scintilla paid no income taxes. The Scintilla Assets were contributed to us for stock and cash. Under Section 351 of the Internal Revenue Code of 1986, as amended (the “Code”), we inherited the historical tax basis of the assets transferred plus a step-up in basis attributable to the cash received by Scintilla. Since we are a taxable entity, we were required to accrue non-recurring deferred income taxes attributable to the acquisition of the Scintilla Assets of $10.9 million. We also acquired the Other Contributed Assets from other parties as part of the same plan under Section 351 of the Code purely for stock. As a result, we inherited the historical tax basis of the Other Contributed Assets and recorded a deferred tax liability of $4.2 million and a corresponding amount of goodwill.
(2) Scintilla is a limited liability company with ownership interests represented by units rather than shares.
(3) Pro forma net income and earnings per share reflect income tax expense resulting from income before taxes, as if the Scintilla Assets had been held by a taxable corporation beginning as of January 1, 2009. For further explanation, see Note 1 to our financial statements included elsewhere in this prospectus.

 

 

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     As of December 31,      Pro Forma
As of
December 31,
2011(1)(2)
 
     2009      2010      2011     
     (in thousands)  

Balance Sheet Data:

           

Cash and cash equivalents

   $ —         $ —         $ 738       $ 19,779   

Oil and natural gas sales receivables

     6,536         6,445         7,108         7,108   

Other current assets

     —           994         1,485         1,485   

Total property and equipment, net

     82,620         94,885         125,346         125,346   

Other assets(3)

     —           1,453         8,227         6,961   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 89,156       $ 103,777       $ 142,904       $ 160,679   
  

 

 

    

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 2,871       $ 6,009       $ 6,467       $ 6,467   

Long-term debt

     60,000         60,000         68,500         —     

Deferred tax liability(4)

     —           —           14,145         9,010   

Other long-term liabilities

     837         2,175         5,164         5,164   

Total parent net investment/stockholders’ equity

     25,448         35,593         48,628         140,038   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and parent net investment/stockholders’ equity

   $ 89,156       $ 103,777       $ 142,904       $ 160,679   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) On August 12, 2011, we acquired the Other Contributed Assets, which are included from the date of acquisition forward.
(2) Reflects (i) the proceeds from this offering at an assumed initial public offering price of $11.00 per share, which is 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 and (ii) the application of proceeds as described in “Use of Proceeds.” Each $1.00 increase (decrease) in the assumed initial public offering price of $11.00 per share would increase (decrease) the amount of pro forma cash and cash equivalents, total assets, parent net investment/stockholders equity and total liabilities and parent net investment/stockholders’ equity by approximately $8.1 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. Similarly, each increase (decrease) of one million shares in the number of shares of common stock offered by us would increase (decrease) cash and cash equivalents, total assets, parent net investment/stockholders’ equity and total liabilities and parent net investment/stockholders’ equity by approximately $10.2 million, assuming the assumed initial public offering price remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(3) Pro forma amount reflects the exclusion of approximately $1.3 million associated with deferred offering costs of this offering, which will be offset against the proceeds of the offering.
(4) On August 12, 2011, in connection with the acquisition of the Scintilla Assets, we became a taxable entity. At the time of becoming a taxable entity, the aggregate net book basis of the oil and natural gas properties exceeded the aggregate net tax basis resulting in us recording a deferred tax liability of approximately $10.9 million. Prior to that time, the Scintilla Assets were owned by a limited liability company that is treated as a partnership for federal and state income tax purposes.

 

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

Other Financial Data:

      

Net cash provided by operating activities

   $ 17,042      $ 28,674      $ 26,498   

Net cash used in investing activities

   $ (22,834   $ (26,074   $ (32,234

Net cash provided by (used in) financing activities

   $ 5,792      $ (2,600   $ 6,474   

Non-GAAP Financial Measure and Reconciliation

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, and is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

 

 

 

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We define Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, stock compensation expense and unrealized derivative gains and losses.

Our management believes Adjusted EBITDAX 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 the items listed above from net income in arriving at Adjusted EBITDAX 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 EBITDAX 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 EBITDAX 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 EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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

 

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

Adjusted EBITDAX Reconciliation to Net Income:

       

Net income (loss)

   $ 5,181       $ 11,309      $ (645

Unrealized (gain) loss on derivative instruments

     —           1,429        (118

Accretion expense

     44         51        59   

Interest expense

     1,943         2,648        3,735   

Stock-based compensation

     —           —          4,946   

Income tax expense

     —           —          10,015   

Depreciation, depletion and amortization

     13,942         15,404        16,159   
  

 

 

    

 

 

   

 

 

 

Adjusted EBITDAX

   $ 21,110       $ 30,841      $ 34,151   
  

 

 

    

 

 

   

 

 

 

Adjusted EBITDAX Reconciliation to Net Cash Provided By Operating Activities:

       

Net cash provided by operating activities

   $ 17,042       $ 28,674      $ 26,498   

Cash interest expense

     1,894         2,262        2,250   

Changes in operating assets and liabilities

     2,174         (95     5,403   
  

 

 

    

 

 

   

 

 

 

Adjusted EBITDAX

   $ 21,110       $ 30,841      $ 34,151   
  

 

 

    

 

 

   

 

 

 

 

 

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SUMMARY RESERVE AND OPERATIONS DATA

The following tables present summary information regarding our estimated net proved oil and natural gas reserves and the historical operating data. Our reserve and historical operations data for periods prior to August 12, 2011 reflect only the Scintilla Assets and not the Other Contributed Assets, while our reserve and historical operations data after that date reflect both the Scintilla Assets and the Other Contributed Assets. For a further discussion of the accounting treatment of the Acquired Assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview and Basis of Presentation.” In addition to the Acquired Assets, our reserve and historical operations data for periods after December 1, 2011 also reflect our interest in the Golden Lane Extension. The estimates of our net proved reserves at December 31, 2011 are based on a reserve report prepared by Ralph E. Davis Associates, Inc., our independent reserve engineers.

For additional information regarding our reserves, please see “Business—Our Operations” and the unaudited supplementary information in the notes to our financial statements included elsewhere in this prospectus.

 

     Reserves  
     As of December 31, 2011  
Reserves Category(1)    Crude
Oil

(MBbls)
     Natural
Gas

(MMcf)
     Natural
Gas
Liquids

(MBbls)
     Total
(MBoe)(2)
 

Proved developed

     286         12,672         5,576         7,973   

Proved undeveloped

     911         40,258         8,196         15,818   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved

     1,197         52,930         13,772         23,791   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

 

(1) All reserves are located within the United States.
(2) Determined using the ratio of 6 Mcf of natural gas being equivalent to one Bbl of crude oil.

 

    Year Ended
December 31,
 
    2009     2010     2011  

Net Sales Data:

     

Crude oil (Bbls)

    74,908        70,561        53,349   

Natural gas (Mcf)

    3,272,490        3,050,086        3,234,173   

Natural gas liquids (Bbls)

    651,749        673,969        767,076   
 

 

 

   

 

 

   

 

 

 

Total crude oil equivalent (Boe)(1)

    1,272,072        1,252,878        1,359,454   

Average daily volumes (Boe/d)

    3,485        3,433        3,725   

Average Sales Price (Excluding Derivatives):

     

Crude oil (per Bbl)

  $ 58.58      $ 75.62      $ 92.07   

Natural gas (per Mcf)

  $ 2.38      $ 3.23      $ 3.06   

Natural gas liquids (per Bbl)

  $ 28.99      $ 39.35      $ 45.86   

Average equivalent price (per Boe)

  $ 24.41      $ 33.30      $ 36.76   

Expenses (per Boe):

     

Lease operating expenses

  $ 3.98      $ 4.43      $ 4.69   

Workover expenses

  $ 2.43      $ 2.03      $ 2.07   

Production taxes

  $ 0.96      $ 2.37      $ 1.69   

General and administrative

  $ 0.45      $ 0.53      $ 5.63   

Depreciation, depletion and amortization

  $ 10.96      $ 12.30      $ 11.89   

 

(1) Determined using the ratio of 6 Mcf gas to 1 Bbl of crude oil.

 

 

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RISK FACTORS

An investment in our common stock involves risks. You should carefully consider the risks described below before investing in our common stock. The risks and uncertainties described below are not the only ones we may face. The following risks, together with additional risks and uncertainties not currently known to us or that we may currently deem immaterial, could impair our financial position and results of operations.

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

A decline in oil and 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 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 and political conditions impacting the global supply and demand for oil and natural gas;

 

   

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

 

   

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 and foreign governmental regulations;

 

   

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

 

   

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

 

   

the actions of the Organization of Petroleum Exporting Countries, or OPEC;

 

   

technological advances affecting energy consumption; and

 

   

the price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 63% of our estimated proved reserves as of December 31, 2011 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2011, the daily NYMEX West Texas Intermediate oil spot price ranged from a high of $113.39 per Bbl to a low of $75.40 per Bbl, and the NYMEX natural gas Henry Hub spot price ranged from a high of $4.92 to a low of $2.84 per MMBtu.

Substantially all of our oil production is sold to purchasers under short-term (less than twelve months) 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. Lower prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves.

 

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Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our current proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless we participate in successful development activities or acquire properties containing proved reserves. Thus, our future oil and natural gas production and, therefore, our cash flow and income are highly dependent upon the level of success we, in conjunction with our contract operator, have in finding or acquiring additional reserves. However, we cannot assure you that our future activities will result in any specific amount of additional proved reserves or that our contract operator will be able to drill productive wells at acceptable costs.

Oil and natural gas development activities involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be produced. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

   

lack of acceptable prospective acreage;

 

   

inadequate capital resources;

 

   

reductions in oil and natural gas prices;

 

   

unexpected drilling conditions, including pressure or irregularities in formations and equipment failures or accidents;

 

   

adverse weather conditions, such as tornados, blizzards and ice storms;

 

   

unavailability or high cost of drilling rigs, equipment or labor;

 

   

title problems;

 

   

compliance with governmental regulations;

 

   

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

 

   

mechanical difficulties.

According to estimates included in our December 31, 2011 proved reserve report, if on January 1, 2012 drilling and development on our properties had ceased, including recompletions and workovers, then our proved developed producing reserves base would decline at an annual effective rate of 13.1% over 10 years. If we fail to replace reserves, our level of production and cash flows will be affected adversely. Our total proved reserves will decline as reserves are produced unless our contract operator conducts other successful exploration and development activities or we acquire properties containing proved reserves, or both.

We do not currently operate any of our drilling locations, and therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of our assets.

We do not currently operate any of our properties and do not have plans to develop the capacity to operate any of our properties. As a non-operated working interest owner, we are dependent on our contract operator to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operator over which we have little or no control. Such decisions include:

 

   

the timing and amount of capital expenditures;

 

   

the timing of initiating the drilling and recompleting of wells;

 

   

the extent of operating costs;

 

   

selection of technology and drilling and completion methods; and

 

   

the rate of production of reserves, if any.

 

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Our agreements with our contract operator contain terms that may be disadvantageous to us.

Our contractual arrangements with our operator contain negotiated terms that may depart from those typical in operating agreements, which grant the operator a high degree of control over the development of our properties. Such terms include the following:

 

   

Our contract operator may retain record title to our interest in undeveloped properties for our benefit until after the drilling of and production from such properties.

 

   

Our contract operator may, in its sole discretion, substitute one or more wells intended to be drilled with a new well or add additional wells. We are obligated to pay our proportionate share of any additional costs incurred.

 

   

If we decline to participate in a proposed new well, we will not be eligible to participate in certain additional wells in the drilling and spacing units adjacent to such proposed well, and we also would be obligated to pay for our share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though we have elected not to participate in the well and its associated costs themselves.

 

   

We are obligated to pay to our contract operator our proportionate share of a fee of $300,000 to $400,000, depending on the particular controlling agreement and subject to increase from time to time based on prevailing market conditions, for each new well for saltwater disposal costs, a fee per barrel of saltwater disposed and a proportionate share of the cost to maintain such disposal wells; however, we do not obtain any ownership rights in such disposal wells, pipelines or other infrastructure.

 

   

We are obligated to pay a proportionate share of the capital costs of oil, gas, water and electrical infrastructure; however, such infrastructure remains the property of our contract operator.

 

   

Our contract operator may increase certain of the fees and costs charged to us.

 

   

Certain costs charged to us are “turnkey” costs, which may be higher or lower than the actual costs incurred.

 

   

We may be liable for certain legacy liabilities related to the properties.

 

   

For our properties subject to the Golden Lane Participation Agreement, our contract operator holds the sole right to propose new wells.

 

   

For all our acquired properties, we have acquired rights only to the Hunton formation in specified wells and undeveloped properties. We do not control the use of the wellbores of these wells for access to shallower or deeper formations, nor do we control the costs of such wells that might be allocated to us.

 

   

Our share of oil and gas production is committed to sale arrangements that we do not control and may not reflect market terms at any given time.

 

   

Our right to sell or commit our properties to other ventures is limited by rights held by our contract operator; we may be forced to sell our properties or be unable to sell our properties on terms that we choose.

We expect to enter into additional operating agreements with our contract operator in the future with similar terms.

Our contract operator does not own a working interest in any of the properties it operates on our behalf. As a result, our contract operator may have interests in developing and operating our properties that differ from and may be contrary to our interests.

If our contract operator fails to perform its obligations under our agreements with it, becomes subject to bankruptcy proceedings or otherwise proves to be an undesirable operator, our business could be adversely affected.

The successful execution of our strategy depends on continued utilization of our contract operator’s oil and gas infrastructure and technical staff as the operator of our properties. Failure to continue this relationship

 

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through (i) the termination or expiration of the operating agreements, or the other arrangements with our contract operator and its affiliates or (ii) the bankruptcy or dissolution of our contract operator could have a material adverse effect on our operations and our financial results. In particular, if our contract operator becomes subject to bankruptcy proceedings, our contract operator or the bankruptcy trustee may be able to cancel one or more of our agreements with our contract operator on the basis that they are “executory contracts.” If this were to occur, we would be required either to renegotiate with our contract operator or its successor to continue to serve as the operator of our properties and provide us with access to the saltwater disposal and other infrastructure serving our existing properties or to select another operator and obtain access to similar infrastructure from other sources, any of which would most likely result in higher costs to us for such services and infrastructure. We may also lose our rights to our undeveloped properties or our rights of first refusal from Scintilla and New Dominion if the agreements providing those rights are deemed to be “executory contracts” in any bankruptcy proceeding to which either of them is subject, which would require us to rely more directly on our and third parties’ efforts to locate additional oil and natural gas leasehold acquisition prospects. The loss of these rights also could result in increased competition for any of Scintilla and New Dominion’s existing leasehold that is made available for sale.

The relationships with our affiliates upon which we rely are subject to change, which could diminish our ability to conduct our operations.

Our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with our contract operator and its affiliates, our ability to select and evaluate suitable properties, and our contract operator’s ability to consummate transactions in a highly competitive environment. Our relationships with our contract operator and its affiliates are subject to change, and our inability to maintain close working relationships with these parties or continue to acquire suitable properties may impair our ability to execute our business plan.

We will record substantial compensation expense in the financial quarter in which this offering occurs and we may incur substantial additional compensation expense related to our future grants of stock compensation, which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards that vest upon consummation of this offering, we will report substantial non-cash compensation expense, which we estimate to be approximately $11.9 million million, in the quarter in which this offering is consummated. We also expect that certain of our executive officers will require us to withhold shares of our common stock, which would otherwise be distributed to them, to satisfy their withholding tax obligations incurred as a result of such stock vesting upon the consummation of this offering and in the future. We estimate that up to approximately $4.0 million of the proceeds of this offering will be used to fund such withholding tax payments. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and anticipated employee stock-based incentive plans. These additional expenses will adversely affect our net income. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

We are a new company. If we are unable to implement our business strategy or conduct our business as we currently expect, our operating results may be adversely affected.

As a recently organized company, we only recently commenced operations upon our acquisition of the Acquired Assets on August 12, 2011. Our management team has only recently been assembled, and as a result some members of our management do not have experience in the operation of our assets and business or with one another. If our management fails to develop a close working relationship or is unable to develop expertise in the operation of our business, we may not be able to execute our business strategy as planned, which could negatively impact our financial performance. Businesses such as ours, which are starting up or in their initial stages of development, present substantial business and financial risks and may suffer significant losses. In addition, as a new company we must establish operating procedures, implement new systems and complete other tasks necessary to conduct our intended business activities.

 

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We have only recently acquired our properties from a private company.

As a newly formed entity, our historical financial statements consist primarily of the Scintilla Assets on a carve-out basis and reflect Scintilla’s ownership as predecessor-in-interest. Because Scintilla is a private company, Scintilla may not have had in place internal controls over financial reporting and accounting matters equivalent to those required of a public company. Indeed, in connection with the preparation of our unaudited financial statements for the period ended September 30, 2011, we discovered errors in the prior calculations of natural gas liquids sales volumes and the related effects on the calculation of historical depreciation, depletion and amortization expense of oil and natural gas properties. The correction of these errors required us to restate our financial statements as of and for the years ended December 31, 2008, 2009 and 2010 and as of and for the six months ended June 30, 2010 and 2011.

We have accounted for our acquisition of the Scintilla Assets as a transfer of net assets between entities under common control under GAAP, meaning that we have recognized such properties on our books retrospectively at Scintilla’s historical basis in such properties. We inherited the historical tax basis of the assets transferred plus an additional step-up in basis attributable to the cash paid to Scintilla. Since we are a taxable entity, we were required to accrue non-recurring deferred income taxes attributable to the acquisition of the Scintilla Assets of $10.9 million for the quarter ended September 30, 2011, the quarter in which we acquired the Scintilla Assets.

Our success is dependent on the successful acquisition and development of leasehold and production from reserve rich properties.

We are in the initial stages of the acquisition of our portfolio of leasehold and other natural resource holdings. We intend to continue to supplement this portfolio with additional sites and leasehold. Our oil and gas properties and assets may not perform as we have projected, and any future acquisitions may prove to be unsuccessful. Additionally, our strategy will require that we have access to additional capital. There can be no assurance that we will be able to access the amount of capital necessary to implement our growth strategy on reasonable terms, if at all. Further, our ability to meet our growth and operational objectives may depend on the success of our acquisitions, and there is no assurance that the integration of future assets and leaseholds will be successful. 

Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

Our principal growth strategy is to pursue selective acquisitions of producing and proved undeveloped properties in conventional resource reservoirs through our contract operator. If we choose to participate in an acquisition identified by our contract operator, we will perform a review of the target properties that we believe is consistent with industry practices. However, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.

Our participation in drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial

 

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losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets.

All of our producing properties and interests are currently located in the Hunton formation in east-central Oklahoma, making us vulnerable to risks associated with operating in one primary geographic area.

All of our oil and gas assets and interests are currently in the Hunton formation in east-central Oklahoma. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as in Oklahoma, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

We are subject to significant risks associated with the drilling and completion of wells in which we participate.

Issues that we face with respect to drilling by our contract operator include, but are not limited to, landing the well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks in completing our wells include, but are not limited to, being able to produce the formation, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore. Any of these issues could result in increased costs to drill and complete a well.

Our reliance on specialized processes creates uncertainties that could adversely affect our results of operations and financial condition.

One of our business strategies is to commercially develop conventional resource reservoirs using specialized processes employed by our contract operator. One technique utilized is installing electric submersible pumps to depressurize the targeted hydrocarbon-bearing reservoir, allowing the gas to expand and push oil and natural gas out of the pores in which they are trapped, in order to increase the production of oil and natural gas. The additional production and reserves attributable to the use of these techniques is inherently difficult to predict. If these specialized processes do not allow for the extraction of oil and natural gas in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.

We will engage in transactions with related parties, which creates an increased risk of conflicting interests.

Our business plan largely is reliant on current and anticipated transactions with various related parties. David J. Chernicky, our controlling stockholder and chairman, owns and controls Scintilla and New Dominion, our contract operator. Kristian B. Kos, our president and chief executive officer, has acted and has been compensated as a consultant of New Dominion. The acquisition of the Acquired Assets and the related operating agreements involved transactions with related parties, including Mr. Chernicky and Mr. Kos, in which we issued a significant number of shares of our common stock and paid a significant amount of cash without us having acquired any independent valuation other than our reserve report. At the time the transaction was approved, none of our directors was “disinterested” or “independent.” Furthermore, as a result of our acquisition of the Scintilla Assets and the issuance of shares of stock therefor, Mr. Chernicky currently controls, and will continue to control after this offering, a majority of the outstanding shares of our common stock. Our acquisition of rights relating to the Golden Lane Extension likewise was with related parties and obligates us to enter into operating agreements

 

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with such parties with terms that may be disadvantageous to us. Additionally, a significant component of our business plan and growth strategy is to acquire additional assets and properties from Scintilla and New Dominion. These related party transactions and similar transactions to which we may be party in the future create the risk of conflicting interests that could have a material adverse effect on our business, results of operations and financial condition.

We depend on our key management personnel, and the loss of any of these individuals could adversely affect our business.

If we lose the services of our key management personnel (including Mr. Kos and Mr. Chernicky) or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We depend upon the knowledge, skill and experience of these individuals to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management.

Our key management personnel (including Mr. Kos and Mr. Chernicky) may terminate their employment with us at any time for any reason with little or no notice. Upon termination of their employment, such persons may engage in businesses that compete with us.

We rely on our relationships with affiliates to access infrastructure that is critical to the development of our assets. Adequate infrastructure may not be available at an economic rate.

Execution of our business strategy is dependent on the availability and capability of various infrastructure, including gas gathering and processing, saltwater disposal, and transportation. Future acquisitions may require us to expend significant capital to acquire, develop or access similar infrastructure. Such capital requirements may adversely impact our returns.

Our access to saltwater disposal infrastructure may not be sufficient to handle all saltwater produced, and environmental regulations may impact our ability to handle saltwater.

Our production is dependent on economically disposing of large amounts of saltwater utilizing our contract operator’s existing saltwater disposal infrastructure. Changing environmental regulations or the unexpected production of excessive saltwater could render such infrastructure insufficient and require additional capital expenditures.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by lack of transportation, capacity constraints and interruptions.

The marketability of our production from our producing properties depends in part upon the availability, proximity and capacity of third-party refineries, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through transportation systems that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, field labor issues or strikes, or our contract operator might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our contract operator has identified and scheduled drilling locations on our acreage over a multi-year period. The ability to drill and develop these locations depends on a number of factors, including the availability

 

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of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. The final determination on whether to drill any of these drilling locations will be dependent upon the factors described elsewhere in this prospectus as well as, to some degree, the results of our contract operator’s drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the identified drilling locations will be drilled within our expected time frame or will ever be drilled. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations or financial condition.

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

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. 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 interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus.

To prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the 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. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will 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 development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

A substantial portion of our estimated proved reserves is undeveloped and may not ultimately be developed or become commercially productive, which could have a material adverse effect on our future oil and natural gas reserves and production and, therefore, our future cash flow and income.

Approximately 66% of our total estimated proved reserves at December 31, 2011 were proved undeveloped reserves and may not be ultimately developed or produced. In estimating our proved undeveloped reserves, we rely upon estimates of our working interest and net revenue interest based on our current ownership of leasehold in the proposed drilling unit, and we also use assumed production volumes based on production histories and geological information. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in our reserve report as of December 31, 2011, assume that substantial capital expenditures are required and will be made to develop these reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and 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.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with Securities and Exchange Commission (“SEC”) requirements for the years ended December 31, 2009, 2010 and 2011, we have based the

 

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estimated discounted future net revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

 

   

the actual prices we receive for oil and natural gas;

 

   

our actual 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 discounted future net revenues 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.

Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil prices decline by $10.00 per Bbl, then our Standardized Measure as of December 31, 2011 would decrease by approximately $4.7 million. If natural gas liquids prices decline by $5.00 per Bbl, then our Standardized Measure as of December 31, 2011 would decrease by approximately $20.9 million. If natural gas prices decline by $1.00 per Mcf, then our Standardized Measure as of December 31, 2011 would decrease by approximately $18.4 million.

Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

Our working capital, together with cash generated from anticipated production, may not be sufficient to support our business plan of acquiring and holding working interests in various oil and gas assets. If we realize lower than expected cash from production, either due to lower than anticipated production levels or a decline in commodity prices from recent levels, we would need to curtail our development activities, acquisition activities, or both, or seek alternative sources of capital, including by means of entering into joint ventures with other exploration and production companies, sales of interests in certain of our properties or by undertaking additional financing activities (including through the issuance of equity or the incurrence of debt). If we are forced to make non-consent elections to proposed operations on our properties due to lack of capital, we would be subject to substantial penalties and other adverse consequences under the Golden Lane Participation Agreement or the Luther JOA (as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Material Definitive Agreements”) or other applicable joint operating agreements.

We may not be able to access the capital markets or otherwise secure such additional financing on reasonable terms or at all, and financing may not continue to be available to us under our existing or new financing arrangements. Our business strategy is reliant upon our ability to have access to a substantial amount of outside capital. The availability of these sources of capital will depend upon a number of factors, including general economic and financial market conditions, oil and natural gas prices and our market value and operating performance. If additional capital resources are unavailable, we may curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operations.

Our cash flows from operations and access to capital are subject to a number of variables, including, among others:

 

   

our proved reserves;

 

   

the volume of oil and natural gas we are able to produce and sell from existing wells;

 

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the prices at which our oil and natural gas are sold;

 

   

our ability to acquire, locate and produce new reserves; and

 

   

the ability of our banks to lend.

If our revenues or the borrowing base under our credit facility decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing.

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 and 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 pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. 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.

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 review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future that could have a material adverse effect on our ability to borrow under our credit facility and our results of operations for the periods in which such charges are taken.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance policies.

The oil and natural gas business generally, and our operations, are subject to certain operating hazards such as:

 

   

well blowouts;

 

   

cratering (catastrophic failure);

 

   

explosions;

 

   

uncontrollable flows of oil, natural gas or well fluids;

 

   

fires;

 

   

oil spills;

 

   

pollution;

 

   

releases of toxic gas, petroleum liquids or drilling fluids, into the environment; and

 

   

hazards resulting from the presence of hydrogen sulfide (H2S) or other contaminants in natural gas we produce.

H2S may be present at one of more of our properties at levels that would be hazardous in the event of an uncontrolled natural gas release or unprotected exposure. In addition, our operations are susceptible to damage

 

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from natural disasters such as earthquakes, flooding or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of any one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, our cash flow or could result in a loss of our properties.

Our insurance policies might be inadequate to cover our liabilities.

Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than we do.

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small oil and natural gas company, many of our competitors are major and large independent oil and natural gas companies that possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit and may be willing to pay premium prices that we cannot afford to match. Our ability to acquire additional prospects and develop reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel or raising additional capital.

We do not hold record title to a substantial portion of our proved reserves, and we may incur losses as a result of title deficiencies, including as a result of disputes with, or other matters affecting, our contract operator.

We do not hold record title to certain of our proved undeveloped properties, which comprise approximately 46% of our proved reserves as of December 31, 2011. Under our agreements with our contract operator, it customarily holds record title to our interests, particularly in undeveloped leasehold, for our benefit until after the development of such leasehold through drilling and related activities. As the holder of only an equitable or beneficial interest in these properties until record title is conveyed to us, we are relatively more subject to certain risks relating to these interests, such as our contract operator’s breach of its obligations to convey record title to our interest to us, efforts of creditors of our contract operator to attach or levy upon our interests in an attempt to satisfy liabilities of our contract operator, the bankruptcy or other insolvency of our contract operator, lack of notice of material assessments, claims or other actions with respect to our interests, and other risks associated with third parties not acknowledging or accepting our rights in these interests. Any loss or failure of beneficial title as a result of these risks could have a material adverse affect on our results of operations, financial condition and estimated proved reserves.

We have acquired and will acquire working and revenue interests in oil and natural gas leasehold interests from third parties (some of which are related to us) or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and could adversely affect our estimated proved reserves, results of operations and financial condition. Title insurance covering mineral leaseholds generally is not available and, in all instances, we and our contract operator forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is customary in our industry, we and our contract operator rely upon the

 

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judgment of oil and natural gas lease brokers, in-house landmen or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We will not always perform curative work to correct deficiencies in the marketability of the title to us. Our contract operator generally will obtain title opinions for specific drilling locations prior to the commencement of drilling. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. We may be subject to litigation from time to time as a result of title issues.

To the extent we enter into commodity derivative arrangements, they could result in financial losses or could reduce our earnings.

We enter into financial hedge arrangements (i.e., commodity derivative agreements) from time to time in order to manage our commodity price risk and to provide a more predictable cash flow from operations. We do not intend to designate our derivative instruments as cash flow hedges for accounting purposes. The fair value of our derivative instruments will be marked to market at the end of each quarter, and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Actual future production of our properties may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, to the extent we engage in hedging activities, such hedging activities may not be as effective as we intend in reducing the volatility of our cash flows.

Derivative instruments also 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 contract obligations;

 

   

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

   

the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.

In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil, natural gas or natural gas liquids prices. We cannot assure you that the commodity derivative contracts we have entered into, or will enter into, will adequately protect us from fluctuations in oil prices.

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

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which includes comprehensive financial reform legislation that establishes 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 Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for

 

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certain futures and option contracts in the major energy markets, 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 new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral that could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the 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. Finally, the legislation 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. Our revenues could therefore be adversely affected if commodity prices decline as a consequence of the legislation and regulations. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Our production of oil and natural gas is sold to a limited number of customers and the credit default of one of these customers could have a temporary adverse effect on us.

Our revenues are generated under contracts with a limited number of customers. Historically, all of the natural gas from our properties has been sold to Scissortail Energy, LLC and DCP Midstream, LP and all of the oil from our properties has been sold to United Petroleum Purchasing Company, Sunoco, Inc. and Enterprise Products Company. Our results of operations would be adversely affected as a result of non-performance by any of our customers. A non-payment default by one of these large customers could have an adverse effect on us, temporarily reducing our cash flow.

Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells our contract operator drills and the disposal of saltwater produced from such wells, among other matters. In particular, our business relies heavily on a methodology available in Oklahoma known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the Oklahoma Corporation Commission for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and results of our operations.

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

Among the changes contained in the President’s fiscal year 2013 budget proposal, released by the White House on February 13, 2012, is the elimination or deferral of certain key U.S. federal income tax deductions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Recently, members of the U.S. Congress have considered similar

 

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changes to the existing federal income tax laws that affect oil and natural gas exploration and production companies, which, if enacted, would negatively affect our financial condition and results of operations. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our operations are subject to health, safety, and environmental laws and regulations which may expose us to significant costs and liabilities.

Our oil and natural gas exploration, production and processing operations are subject to stringent and complex federal, state, and local laws and regulations governing health and safety aspects of our operation, the discharge of materials into the environment and the protection of the environment. These laws and regulations may impose on our operations numerous requirements, including the obligation to obtain a permit before conducting drilling or underground injection activities; restrictions on the types, quantities and concentration of materials that can be released into the environment; limitations or prohibitions of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; specific health and safety criteria to protect workers; and the responsibility for cleaning up any pollution resulting from operations. Numerous governmental authorities such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. These laws and regulations may result in the assessment of administrative, civil or criminal penalties for any violations; the imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing some or all of our operations; and delays in granting permits and cancellation of leases.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our contract operator’s handling of petroleum hydrocarbons and wastes, emissions to air and water, the underground injection or other disposal of wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable regardless of whether we were at fault for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant costs or liabilities that could have a material adverse effect on our financial condition or results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for processing, reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, collect penalties for violations or obtain damages for any related personal injury or property damage. Some of our properties are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, emission, waste management or cleanup requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on 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 laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

There is a growing belief that emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in producing oil and natural gas and the demand for and consumption of oil and natural gas (due to change in both costs and weather patterns).

 

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In December 2009, the EPA determined that atmospheric concentrations of carbon dioxide, methane, and certain other GHGs present an endangerment to public health and welfare because such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Consistent with its findings, the EPA has proposed or adopted various regulations under the Clean Air Act to address GHGs. Among other things, the EPA is limiting emissions of greenhouse gases from new cars and light duty trucks beginning with the 2012 model year. In addition, the EPA has published a final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs, pursuant to which these permitting requirements have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions will be required to meet emissions limits that are based on the “best available control technology,” which will be established by the permitting agencies on a case-by-case basis. The EPA has also adopted regulations requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including certain oil and natural gas production facilities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011 and which may form the basis for further regulation. Many of the EPA’s GHG rules are subject to legal challenges, but have not been stayed pending judicial review. Depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules. The EPA’s GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.

Moreover, Congress has from time to time considered adopting legislation to reduce emissions of GHGs or promote the use of renewable fuels. As an alternative, some proponents of GHG controls have advocated mandating a national “clean energy” standard. In 2011, President Obama encouraged Congress to adopt a goal of generating 80% of U.S. electricity from “clean energy” by 2035 with credit for renewable and nuclear power and partial credit for clean coal and “efficient natural gas.” Because of the lack of any comprehensive federal legislative program expressly addressing GHGs, there currently is a great deal of uncertainty as to how and when additional federal regulation of GHGs might take place and as to whether the EPA should continue with its existing regulations in the absence of more specific Congressional direction.

In the meantime, many states already have taken such measures, which have included renewable energy standards, development of GHG emission inventories and/or cap and trade programs. Cap and trade programs typically work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of available allowances reduced each year until the overall GHG emission reduction goal is achieved. These allowances are expected to escalate significantly in cost over time. 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 or to purchase electricity. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. 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.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms and floods. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. Our insurance may not cover some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

 

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Risks Related to Our Indebtedness

Our debt covenants are extremely strict and may inhibit our ability to make certain investments, incur additional indebtedness, or engage in certain transactions. There can be no assurance that our operations will support the expenses associated with our debt.

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

 

   

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

 

   

our incurrence of additional indebtedness;

 

   

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

 

   

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

 

   

transactions with affiliates;

 

   

the sale of assets; and

 

   

our capital expenditures.

Our 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 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 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 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 credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

The variable rate indebtedness in our credit facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Our borrowings under our credit facility bear interest at rates that may vary, exposing us to interest rate risk. If such rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Availability under our credit facility is based on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under our credit facility.

Our ability to make payments due under our credit facility will depend upon our future operating performance, which is subject to general economic and competitive conditions and to financial, business and other factors, many of which we cannot control. In addition, our borrowing base is subject to semi-annual redetermination by our lenders based on valuation of our proved reserves and the lenders’ internal criteria. In the event the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings on an accelerated basis. If we do not have sufficient funds on hand for repayment in such event, or to service our debt obligations generally, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, sell assets or sell additional securities. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. In addition, our credit agreement may limit our ability to take certain of such actions. Failure to make the required repayment could result in a default under our credit facility. Our failure to generate sufficient funds to pay our debts or to undertake any of these actions successfully, or to comply with the covenants under our credit facility mentioned above, could materially adversely affect our business.

 

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

As of March 1, 2012, we had approximately $68.5 million in outstanding debt. In the future, we may incur additional indebtedness 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 could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

 

   

a high level of debt could place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, 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 the borrowing base of our credit facility 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, natural gas and natural gas liquids prices, and financial, business and 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 will 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.

Our obligations under our credit facility are secured at all times by substantially all of our assets.

Our indebtedness under our credit facility is secured by substantially all of our assets. Therefore, if we default on any of our obligations under the credit facility it could result in our lenders foreclosing on our assets or otherwise being entitled to revenues generated by and through our assets.

Risks Related to this Offering and our Common Stock

One of our stockholders will beneficially own or control a majority of our common stock, giving him a controlling influence over corporate transactions and other matters. His interests may conflict with yours, and the concentration of ownership of our common stock by such stockholder will limit the influence of public stockholders.

Upon completion of this offering, one of our stockholders, our chairman David J. Chernicky, will beneficially own, control or have substantial influence over approximately 61% of our outstanding common stock, and approximately 59% if the underwriters exercise their option to purchase additional shares in full. Mr. Chernicky also owns and controls Scintilla and New Dominion, entities with which we have material transactional and operational relationships. Mr. Chernicky has the ability to exert significant influence over our board of directors and its policies. Mr. Chernicky will be able to control or substantially influence the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and possible mergers, corporate control contests and other significant corporate transactions. Mr. Chernicky

 

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could take actions that might be desirable to him, Scintilla or New Dominion but not to our other stockholders. This concentration of ownership may also have the effect of delaying, deterring or preventing a change in control, a merger, consolidation, takeover or other business combination. This concentration of ownership could also discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which could in turn have an adverse effect on the market price of our common stock.

We expect to be a “controlled company” within the meaning of the NYSE rules and, if applicable, would qualify for and may rely on exemptions from certain corporate governance requirements.

One of our stockholders, our chairman David J. Chernicky, beneficially holds more than 50% of the voting power for the election of directors, and as such, we are a “controlled company” as that term is defined in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a “controlled company” may elect not to comply with certain NYSE corporate governance requirements, including:

 

   

the requirement that a majority of our board of directors consist of independent directors;

 

   

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

 

   

the requirement that our compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a “controlled company.” Following this offering, we do not intend to rely on these exemptions but may elect to do so in the future. 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. The significant ownership interest of Mr. Chernicky could adversely affect investors’ perceptions of our corporate governance.

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 trading market for our common stock may not develop and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. Liquid and active 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 and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriting; Conflicts of Interest” 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 the 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;

 

   

changes in revenue or earnings estimates or publication of reports by equity research analysts;

 

   

speculation in the press or investment community;

 

   

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

 

   

general market conditions, including fluctuations in commodity prices; and

 

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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.

Purchasers of common stock in this offering will experience immediate and substantial dilution of $6.95 per share.

Based on an assumed initial public offering price of $11.00 per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $6.95 per share in the pro forma net tangible book value per share of common stock from the initial public offering price, and our pro forma net tangible book value as of December 31, 2011 after giving effect to this offering would be $4.05 per share. See “Dilution” for a complete description of the calculation of pro forma net tangible book value.

As a result of the reporting and disclosure requirements of a public company under the Exchange Act, the NYSE rules and the requirements of the Sarbanes-Oxley Act of 2002, we will incur significant additional costs and expenses and compliance with these requirements will require a substantial amount of our management’s time.

As a public company with listed equity securities, we will be required to comply with applicable laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of 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; and

 

   

involve and retain to a greater degree outside counsel, accountants and other professionals and consultants in the above activities.

In addition, we also expect that being a public company subject to these rules and regulations will increase our cost to obtain director and officer liability insurance coverage and 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 qualified executive officers.

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 to 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

 

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company, we will need to upgrade our systems, including information technology, 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. Additionally, our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate material weaknesses or significant 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 have identified material weaknesses in our internal control relating to our accounting for matters relating to our natural gas and natural gas liquids sales volumes and to accounting for non-recurring transactions. If we fail to remediate these material weaknesses or otherwise fail to achieve and maintain effective internal control over financial reporting, we could face difficulties in preparing timely and accurate financial reports, which could lead to a loss of investor confidence in our reported financial results and a decline in our stock price.

In connection with the preparation of our financial statements for the nine months ended September 30, 2011, we identified errors in the prior calculation of our natural gas and natural gas liquids sales volumes and the related effects of those sales volumes on the calculations of depreciation, depletion and amortization expenses attributable to time periods in which our oil and natural gas properties were owned by Scintilla. We have corrected these errors, which resulted in net increases of our depreciation, depletion and amortization expenses for the years ended December 31, 2008, 2009 and 2010 and the six months ended June 30, 2010 and 2011 of $3.8 million, $3.4 million, $4.0 million, $1.9 million and $1.9 million, respectively, and corresponding decreases of our net income for these periods. These changes also resulted in net decreases of our oil and natural gas properties, net as of December 31, 2008, 2009 and 2010 and June 30, 2010 and 2011 of $6.4 million, $9.8 million, $13.8 million, $11.7 million and $15.7 million, respectively.

Also during the preparation of our financial statements for the nine months ended September 30, 2011, we identified an error in the accounting for the acquisition of the Other Contributed Assets and recorded goodwill related to the acquisition of these properties in the amount of the deferred income tax liability resulting from the carryover of tax attributes from the prior owners to us.

Our management considers the failure to identify these errors in a timely manner to be material weaknesses in our internal control over financial reporting under the standards established by the United States Public Company Accounting Oversight Board, or the “PCAOB Standards.” Under the PCAOB standards, a material weakness is defined as a deficiency, or a combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented, or detected and corrected on a timely basis. In response to these material weaknesses, we have evaluated our historical financial and operations data for further deficiencies and have changed the method by which we compute our natural gas and natural gas liquids sales volumes to ensure that such volumes match the actual volumes processed by our first purchasers. We have also instituted additional control procedures around the research and recording of non-recurring transactions. We have taken all remedial actions we believe to be necessary and are not aware of other material deficiencies at this time. However, until we have further experience with the results of our remedial actions, we cannot assure you that the measures we have taken to date, or any future measures we may implement, will ensure that we maintain adequate control over our financial processes and reporting. In addition, it is possible that we or our independent registered public accounting firm may identify additional errors in our financial statements that may be considered significant deficiencies or material weaknesses in our internal control over financial reporting.

 

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The Sarbanes-Oxley Act of 2002 requires, among other things, that we assess the effectiveness of our internal control over financial reporting on an annual basis and the effectiveness of our disclosure controls and procedures on a quarterly basis. We will be required to perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on, and our independent registered public accounting firm will be asked to attest to, the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002. Our testing, or subsequent testing by our independent registered public accounting firm, may reveal other material weaknesses or that the material weaknesses described above have not been fully remediated.

If we do not remediate the material weaknesses described above, other material weaknesses are identified or we are not able to comply with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 in a timely manner, our reported financial results could be restated or we could receive an adverse opinion regarding our internal control from our independent registered public accounting firm. As a result, we could also fail to meet the periodic reporting obligations applicable to us after the completion of this offering and become subject to investigations or sanctions by regulatory authorities, which would require additional financial and management resources. Any of the foregoing events could cause investors to lose confidence in our reported financial information and lead to a decline in our stock price.

We will have significant obligations under the Exchange Act.

Because we will be a public company required to file reports under the Exchange Act, we will be subject to increased regulatory scrutiny and extensive and complex regulation. The SEC has the right to review the accuracy and completeness of our reports, press releases, and other public documents. In addition, we are subject to extensive requirements to institute and maintain financial accounting controls and for the accuracy and completeness of our books and records. Normally these activities are overseen by an audit committee consisting of qualified independent directors. Only one of the current members of our board of directors is considered “independent.” Consequently, the protections normally provided to stockholders by boards of directors comprised by a majority of persons considered “independent” directors are not available.

Indemnification of officers and directors may result in unanticipated expenses.

The Delaware General Corporation Law and our bylaws provide for the indemnification of our directors, officers, employees, and agents, under certain circumstances, against attorney’s fees and other expenses incurred by them in any litigation to which they become a party arising from their association with us or activities on our behalf. We also will bear the expenses of such litigation for any of our directors, officers, employees, or agents, upon such person’s promise to repay them if it is ultimately determined that any such person is not entitled to indemnification. This indemnification policy could result in substantial expenditures by us that we may be unable to recoup and could direct funds away from our business.

Acquisitions of interests that we may make from time to time from certain related parties pursuant to our right of first refusal or other arrangements may require the retrospective restatement of our financial statements, which could delay our Exchange Act filings and otherwise adversely affect our financial position and the price of our common stock.

Pursuant to certain rights of first refusal we have obtained from Scintilla and New Dominion as part of the transactions pursuant to which we acquired our initial properties, we have the right, but not the obligation, to acquire up to 90% of Scintilla and New Dominion’s combined interest in oil and natural gas projects determined to have proved reserves for a 25-year period in exchange for a payment of fair value for our interest in such projects, determined at the time we elect to participate. Both Scintilla and New Dominion are controlled by David J. Chernicky, our principal stockholder, chairman and senior geologist. As such, so long as Mr. Chernicky continues to be our controlling stockholder, any acquisitions pursuant to this right of first refusal will represent a transfer of net assets between entities under common control for purposes of GAAP. The effect of this accounting treatment is that if the amount we pay exceeds Scintilla or New Dominion’s basis in the net assets

 

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acquired plus an amount representing a reimbursement of Scintilla or New Dominion’s costs of acquiring those net assets, then that excess, if any, will be recognized as a reduction to stockholders’ equity, and we will also recognize a deferred income tax liability, which could be material. As such, any acquisitions of assets from these related parties where the acquisition cost is significantly in excess of their basis in those assets may significantly increase our income tax expense, which would adversely affect our net income, and also may significantly increase debt to capitalization ratios, which could result in a default under our credit facility and adversely affect our financial position, liquidity and the price of our common stock.

Furthermore, under applicable accounting guidance, following any acquisition of assets from one of these related parties we will be required to retrospectively restate the historical periods presented in our historical financial statements to reflect the combined historical results of our operations throughout the periods presented. As private companies, Scintilla and New Dominion do not have in place internal controls over financial reporting and accounting matters equivalent to those required of a public company. Therefore, to the extent that we acquire additional assets from Scintilla or New Dominion in the future, we will need to devote substantial time and resources to the review and audit of prior period financial information associated with such additional assets in order to achieve an appropriate level of comfort over this financial information in connection with restating our historical financial statements to account for such additional assets. The requirement to restate our historical financial statements and the time required to audit the financial information relating to assets we acquire from Scintilla and/or New Dominion could delay our ability to file timely the periodic reports we are required to file pursuant to the Exchange Act, which could have an adverse affect on the trading price of our common stock and its continued listing on a national securities exchange.

We do not intend to pay and we are currently prohibited by our credit facility 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 and a market for our common stock develops.

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 credit facility. Consequently, your only opportunity to achieve a return on your investment in our common stock will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock that will prevail in the market after this offering will ever exceed the price that you pay or that a market for our common stock will develop to enable you to sell your shares.

Future sales of our common stock in the public market could lower 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 32,991,500 outstanding shares of common stock. This number includes 9,100,000 shares that we are selling in this offering, which may be resold immediately in the public market, and 1,700,000 shares of unvested restricted stock held by certain of our executive officers. Following the completion of this offering, our current stockholders will own 23,891,500 shares (including such 1,700,000 shares of unvested restricted stock), or approximately 72% of our total outstanding shares. Many of our current stockholders are parties to a registration rights agreement with us. Pursuant to this agreement, subject to the terms of the lock-up agreement between certain of our current stockholders and the underwriters described under the caption “Underwriting; Conflicts of Interest,” we have agreed to effect the registration of shares held by our current stockholders if they so request or if we conduct other offerings of our common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.” In addition, as soon as practicable after this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of additional shares of our common stock issued or reserved for issuance under our long-term 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.

 

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We cannot predict the size of future issuances of our 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 equity trading markets may be volatile, which could result in losses for our stockholders.

In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to their operating performance. The market price of our common stock could similarly be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

 

   

domestic and worldwide supplies and prices of, and demand for, oil and natural gas;

 

   

changes in environmental and other governmental regulations affecting the oil and natural gas industry;

 

   

variations in our quarterly results of operations or cash flows; and

 

   

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

The realization of any of these risks and other factors beyond our control could cause the market price of our common stock to decline significantly.

Our certificate of incorporation and bylaws contain, and Delaware law contains, provisions that may prevent, discourage or frustrate attempts to replace or remove our current management by our stockholders, even if such replacement or removal may be in our stockholders’ best interests.

Our certificate of incorporation and bylaws contain, and Delaware law contains, provisions that could enable our management to resist a takeover attempt. Such provisions:

 

   

classify our board into three classes of directors, each of which is elected for staggered three-year terms, meaning only one-third of our directors are elected at any particular annual meeting of stockholders. Further, because of our classified board, our directors generally may be removed only for cause;

 

   

permit us to issue, without any further vote or action by the stockholders, shares of preferred stock in one or more series and, with respect to each such series, to fix the number of shares constituting the series and the designation of the series, the voting powers (if any) of the shares of the series, and the preferences and relative, participating, optional, and other special rights, if any, and any qualification, limitations or restrictions of the shares of such series;

 

   

require special meetings of the stockholders to be called by the chairman of the board, the chief executive officer, or by resolution of a majority of the board of directors;

 

   

require business at special meetings to be limited to the stated purpose or purposes of that meeting;

 

   

require that stockholders follow certain procedures, including advance notice procedures, to bring certain matters before an annual meeting or to nominate a director for election; and

 

   

permit directors to fill vacancies in our board of directors.

These provisions could:

 

   

discourage, delay or prevent a change in the control of our company or a change in our management, even if the change would be in the best interests of our stockholders;

 

   

adversely affect the voting power of holders of common stock; and

 

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limit the price that investors might be willing to pay in the future for shares of our common stock.

The lack of a broker or dealer to create or maintain a market in our stock could adversely impact the price and liquidity of our securities.

We currently have no agreement with any broker or dealer to act as a market maker for our securities and there is no assurance that we will be successful in obtaining any market makers. Thus, no broker or dealer will have an incentive to make a market for our stock. The lack of a market maker for our securities could adversely influence the market for and price of our securities, as well as your ability to dispose of, or to obtain accurate information about, and/or quotations as to the price of, our securities.

We currently do not have active corporate governance policies or procedures and we do not have a majority of independent directors on our board.

We do not currently have a separately designated nominating committee, a separately designated compensation committee, or any other corporate governance committee. In addition, only one of our current four directors qualifies as independent under applicable NYSE guidelines. This independent director, Terry L. Toole, will chair our separately designated audit committee, but this committee will not initially be comprised of a majority of independent directors. Thus, our stockholders do not have the benefits or protections associated with corporate governance controls and other corporate oversight mechanisms overseen by independent directors.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this prospectus includes “forward-looking statements.” These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

 

   

our ability to replace oil and natural gas reserves;

 

   

declines or volatility in the prices we receive for our oil and natural gas;

 

   

our financial position;

 

   

our ability to generate sufficient cash flow and liquidity from operations, borrowings or other sources to enable us to pay our obligations and maintain our non-operated acreage positions;

 

   

future capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

 

   

there are significant interlocking relationships between us, Scintilla, and New Dominion, and there can be no assurance that these interlocking relationships may not result in conflicts of interest and other risks to decision-making actions by our officers and directors in the future;

 

   

although we believe that we paid a fair price for the Acquired Assets, we did not obtain any independent valuation of those properties other than a reserve report as of December 31, 2010, issued by Ralph E. Davis Associates, Inc., which provided information about reserves and discounted cash flow, but not valuation;

 

   

our ability to continue our working relationship with our contract operator and other related entities;

 

   

the ultimate form of the contractual arrangements to be entered into between us and our contract operator with respect to the Golden Lane Extension;

 

   

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

 

   

economic downturns may adversely affect consumption of oil and natural gas by businesses and consumers;

 

   

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

 

   

uncertainties associated with estimates of proved oil and natural gas reserves and various assumptions underlying such estimates;

 

   

our ability to successfully acquire additional working interests through the efforts of our contract operator in forced pooling processes;

 

   

the requirement applicable to us upon becoming a public company to implement and assess periodically the effectiveness of our internal control over financial reporting and the substantial costs associated with doing so;

 

   

the impact of environmental, health and safety, and other governmental regulations and of current or pending legislation;

 

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environmental risks;

 

   

geographical concentration of our operations;

 

   

constraints imposed on our business and operations by our credit agreements and our ability to generate sufficient cash flows to repay our debt obligations;

 

   

availability of borrowings under our credit agreements;

 

   

drilling and operating risks;

 

   

exploration and development risks;

 

   

competition in the oil and natural gas industry;

 

   

increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

 

   

the inability of our contract operator to successfully drill wells on our properties that produce oil or natural gas in commercially viable quantities;

 

   

failure to meet the proposed drilling schedule on our properties;

 

   

adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

 

   

drilling operations and adverse weather and environmental conditions;

 

   

limited control over non-operated properties;

 

   

reliance on a limited number of customers;

 

   

management’s ability to execute our plans to meet our goals;

 

   

our ability to retain key members of our senior management and key technical employees;

 

   

conflicts of interest with regard to our directors and executive officers;

 

   

access to adequate gathering systems and pipeline take-away capacity to execute our drilling program;

 

   

marketing and transportation constraints in the Hunton formation in east-central Oklahoma;

 

   

our ability to sell the oil and natural gas we produce at market prices;

 

   

costs associated with perfecting title for mineral rights in some of our properties;

 

   

title defects to our properties and inability to retain our leases;

 

   

federal, state, and tribal regulations and laws;

 

   

our current level of indebtedness and the effect of any increase in our level of indebtedness;

 

   

risks relating to potential acquisitions and the integration of significant acquisitions;

 

   

price volatility of oil and natural gas prices and the effect that lower prices may have on our net income and stockholders’ equity;

 

   

a decline in oil or natural gas production or oil or natural gas prices and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;

 

   

the effect of seasonal factors;

 

   

lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oilfield services;

 

   

further sales or issuances of common stock;

 

   

our common stock’s lack of any trading history;

 

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costs of purchasing electricity and disposing of saltwater;

 

   

continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

 

   

other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in “Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this prospectus and speak only as of the date of this prospectus. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

 

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USE OF PROCEEDS

We estimate that our net proceeds from the sale of common stock in this offering will be approximately $90.3 million, assuming an initial public offering price of $11.00 per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses and underwriting discounts and commissions of approximately $9.8 million. If the underwriters’ over-allotment option is exercised in full, we estimate that our net proceeds will be approximately $104.3 million.

An increase or decrease in the initial public offering price of $1.00 per share of common stock would cause the net proceeds that we will receive from the offering, assuming the number of shares offered by us, as indicated on the cover page of this prospectus, remains the same and after deducting estimated expenses and underwriting discounts and commissions, to increase or decrease, as applicable, by approximately $8.5 million. Similarly, each increase or decrease of one million shares in the number of shares of common stock offered by us would increase or decrease the net proceeds to us from this offering by approximately $10.2 million, assuming the assumed initial public offering price remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering first to repay outstanding indebtedness under our credit facility, which as of March 1, 2012 was approximately $68.5 million. We do not currently have plans to borrow additional amounts under our credit facility. However, we may borrow from time to time to fund acquisitions or other capital needs. We expect that certain of our executive officers will request that we withhold shares of their common stock to satisfy the withholding tax obligations of the executives incurred upon the vesting of such stock upon the consummation of this offering. Assuming an offering price of $11.00 per share and an assumed combined state and federal tax rate of 30.5%, we estimate that up to approximately $4.0 million of the remaining net proceeds of this offering will be used to fund such withholding tax payments. For purposes of the number of shares outstanding following this offering disclosed in this prospectus, we have assumed that each of our executive officers will elect to surrender shares to satisfy their withholding tax obligations.

The following table summarizes in order of priority these and other planned uses for the net proceeds of this offering:

Purpose

   Amount of Proceeds  
     (in millions)  

Repayment of credit facility

   $ 68.5   

Withholding tax obligations(1)

     4.0   

Drilling, completion, and infrastructure

     15.6   

Leasehold acquisition

     2.0   

Miscellaneous (office equipment, IT infrastructure, personnel)

     0.2   
  

 

 

 

Total

     90.3   
  

 

 

 

 

(1) An increase or decrease in the initial public offering price of $1.00 per share of common stock would increase or decrease the amount of our estimated withholding tax obligation by approximately $0.4 million.

Our credit facility matures on August 12, 2015 and bears interest at a variable rate, which was approximately 3.76% per annum as of March 1, 2012. Our outstanding borrowings under our credit facility were incurred to fund the acquisition of the Acquired Assets and for general corporate purposes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facility.” Affiliates of certain of the underwriters are lenders under our credit facility and will receive a portion of the proceeds from this offering. Accordingly, this offering is being made in compliance with Rule 5121 of FINRA. See “Underwriting; Conflicts of Interest.”

 

 

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DIVIDEND POLICY

We do not expect to declare or pay any cash dividends in the foreseeable future on our common stock. Our credit facility currently prohibits us from paying cash dividends on our common stock, and we may enter into debt arrangements in the future that also prohibit or restrict our ability to declare or pay cash dividends on our common stock.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and as described in “Use of Proceeds” capitalization:

(a) as of December 31, 2011; and

(b) pro forma for the effect of (i) the offering of 9.1 million shares of common stock pursuant to this offering, assuming an initial public offering price of $11.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), (ii) the repayment of amounts borrowed under our credit facility as described in “Use of Proceeds” and (iii) the vesting of 1.2 million shares of restricted common stock held by members of our management and payment of related estimated withholding taxes as a result of their assumed surrender of 366,000 of such shares.

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

 

      December 31, 2011  
      Historical     Pro Forma(1)  
     (in thousands)  

Cash and cash equivalents:(2)

   $ 738      $ 19,779   
  

 

 

   

 

 

 

Long-term debt:

    

Credit facility(3)

   $ 68,500      $ —     
  

 

 

   

 

 

 

Total long-term debt

     68,500        —     
  

 

 

   

 

 

 

Stockholders’ equity:

    

Preferred stock—$0.001 par value; 20,000,000 shares authorized, no shares issued and outstanding

     —          —     

Common stock—$0.001 par value; 180,000,000 shares authorized, 24,257,500 shares issued and 21,357,500 outstanding,(4) and 32,991,500 shares issued and 31,291,500 shares outstanding(5) pro forma

     21        31   

Additional paid-in capital

     59,398        158,093   

Accumulated deficit(6)

     (10,791     (18,086
  

 

 

   

 

 

 

Total stockholders’ equity

     48,628        140,038   
  

 

 

   

 

 

 

Total capitalization:

   $ 117,128      $ 140,038   
  

 

 

   

 

 

 

 

(1) Each $1.00 increase (decrease) in the assumed initial public offering price of $11.00 per share would increase (decrease) the amount of pro forma cash and cash equivalents, additional paid-in capital, total stockholders’ equity and total capitalization by approximately $8.1 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. Similarly, each increase (decrease) of one million shares in the number of shares of common stock offered by us would increase (decrease) cash and cash equivalents, common stock and additional paid-in capital, total stockholders’ equity and total capitalization by approximately $10.2 million, assuming the assumed initial public offering price remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(2) As of March 1, 2012, our cash and cash equivalents were $0.5 million.
(3) As of March 1, 2012, there was $68.5 million of indebtedness outstanding under our credit facility, which we plan to repay using the net proceeds of this offering.
(4) Outstanding shares of common stock at December 31, 2011 exclude 2.9 million shares of restricted common stock that are issued and outstanding for corporate law purposes, but which are deemed to be issued but not outstanding under GAAP.
(5) Pro forma outstanding shares of common stock at December 31, 2011 exclude 1.7 million shares of restricted common stock that are issued and outstanding for corporate law purposes, but which are deemed to be issued but not outstanding under GAAP.
(6) Pro forma amount includes $11.9 million of compensation expense associated with 1.2 million shares of restricted stock that vest upon the completion of this offering. This amount, less the related income tax benefit, will be reflected as a charge to earnings in the period in which the offering is completed.

 

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DILUTION

Purchasers of our 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 was approximately $41.1 million, or $1.69 per share of common stock. Net tangible book value per share is determined by dividing our tangible net worth (tangible assets less total liabilities) by the total number of shares of common stock outstanding as of December 31, 2011 (treating as outstanding for this purpose all shares issued and outstanding for corporate law purposes, including unvested shares of restricted common stock, since such shares would participate in liquidation rights on a pro rata basis with other shares). After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting underwriting discounts and anticipated expenses of this offering), our pro forma net tangible book value as of December 31, 2011 would have been approximately $133.8 million, or $4.05 per share. This represents an immediate increase in the net tangible book value of $2.36 per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $6.95 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

      $ 11.00   

Net tangible book value per share as of December 31, 2011

   $ 1.69      

Increase per share attributable to new investors in this offering

   $ 2.36      
  

 

 

    

Pro forma net tangible book value per share after giving effect to this offering

      $ 4.05   
     

 

 

 

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

      $ 6.95   
     

 

 

 

A $1.00 increase (decrease) in the assumed initial public offering price of $11.00 per share, which is the midpoint of the range set forth on the cover page of this prospectus, would increase (decrease) our pro forma net tangible book value per share by $0.26, assuming the number of shares offered by us remains the same as set forth on the cover page of this prospectus and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.

If the underwriters exercise their option to purchase additional shares of our common stock in full, the pro forma net tangible book value per share would be $4.30 per share, the increase in pro forma net tangible book value per share to existing stockholders would be $2.61 per share and the dilution per share to new investors purchasing shares in this offering would be $6.70 per share.

The following table summarizes, on a 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 $11.00, calculated before deduction of estimated underwriting discounts and commissions:

 

     Shares Acquired     Total Consideration     Average Price
per Share
 
     Number      Percent     Amount
(in thousands)
     Percent    

Existing stockholders(1)

     22,191,500         71   $ 67,333         40   $ 3.03   

New investors

     9,100,000         29     100,100         60     11.00   
  

 

 

    

 

 

   

 

 

    

 

 

   

Total

     31,291,500         100   $ 167,433         100   $ 5.35   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

(1) Excludes 1.7 million shares of unvested restricted stock held by our executive officers.

 

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A $1.00 increase (decrease) in the assumed initial public offering price of $11.00 per share, which is the midpoint of the range set forth on the cover page of this prospectus, would increase (decrease) total consideration paid by new investors by $9.1 million, total consideration paid by all stockholders by $9.1 million and the average price per share paid by all stockholders by $0.28, in each case assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, and without deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

If the underwriters’ over-allotment option is exercised in full, the number of shares held by the existing stockholders after this offering would be 22.2 million, or 68% of the total number of shares of our common stock outstanding after this offering, and the number of shares held by new investors would increase to 10.5 million, or 32% of the total number of shares of our common stock outstanding after this offering.

 

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Index to Financial Statements

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth the selected historical financial and other data relating to our operations and financial condition as of and for each of the years in the five-year period ended December 31, 2011. Because Scintilla is under common control with us, we recognized the Scintilla Assets and related liabilities acquired from Scintilla at their historical carrying values, and we have presented the historical operations of the Scintilla Assets on a retrospective basis for all applicable periods presented in this prospectus. Since the Other Contributed Assets were acquired from parties not under common control with us, they have been accounted for as purchases at fair value, with the results of operations attributable to such properties included in our financial statements only from the acquisition date. As such, the Other Contributed Assets are not included in our historical financial statements prior to August 12, 2011. For further discussion of the accounting treatment of the Acquired Assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview and Basis of Presentation.” In addition to the Acquired Assets, our financial, reserve and historical operations data for periods after December 1, 2011 also reflect our interest in the Golden Lane Extension.

The selected historical financial data as of December 31, 2010 and 2011 and for each of the years ended December 31, 2009, 2010 and 2011 are derived from our audited historical financial statements included elsewhere in this prospectus. The selected historical financial data as of December 31, 2009 and for the year ended December 31, 2008, are derived from our audited historical financial statements, which are not included in this prospectus. The selected historical financial data as of and for the year ended December 31, 2007, and as of December 31, 2008 are derived from our unaudited historical financial statements, which are not included in this prospectus. In management’s opinion, these financial statements include all adjustments necessary for the fair presentation of financial condition as of such dates and the results of operations for such periods.

Our historical financial statements included in this prospectus may not necessarily reflect our financial position, results of operations, and cash flows as if we had operated as a stand-alone public company during all periods presented. The historical financial data reflect historical accounts attributable to the Scintilla Assets on a “carve-out” basis, including allocated overhead from our predecessor in interest, for periods prior to our acquisition of the Scintilla Assets on August 12, 2011 and do not reflect any estimate of additional overhead that we may incur as a separate company. Following the completion of this offering, we expect to incur additional annual costs associated with our compliance and disclosure obligations as a public company and to incur significant non-cash compensation expense in the financial quarter in which this offering occurs upon the vesting of restricted common stock granted to management as part of our formation, and our overhead costs could be materially different. Accordingly, for this and other reasons, the historical results should not be relied upon as an indicator of our future performance.

For a detailed discussion of the selected historical financial information contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following tables should also be read in conjunction with our historical financial statements and the accompanying notes thereto contained elsewhere in this prospectus.

 

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     Year Ended December 31,  
    2007     2008     2009     2010     2011  
    (unaudited)                          
    (in thousands, except per share amounts)  

Statement of Operations Data:

         

Revenues:

         

Oil sales

  $ 2,610      $ 5,753      $ 4,388      $ 5,336      $ 4,912   

Natural gas sales(1)

    45,820        18,776        7,773        9,866        9,886   

Natural gas liquids sales(1)

    —          34,375        18,895        26,522        35,179   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    48,430        58,904        31,056        41,724        49,977   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

         

Oil and natural gas production expenses

    9,269        10,618        8,153        8,101        9,186   

Oil and natural gas production taxes

    2,288        3,093        1,215        2,968        2,304   

General and administrative

    415        460        578        670        7,660   

Depreciation, depletion, and amortization

    12,986        15,427        13,942        15,404        16,159   

Accretion expense

    29        34        44        51        59   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

    24,987        29,632        23,932        27,194        35,368   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    23,443        29,272        7,124        14,530        14,609   

Other income (expense):

         

Interest expense

    (743     (2,536     (1,943     (2,648     (3,735

Realized and unrealized gains (losses) from derivatives

    —          (353     —          (573     (1,504
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

    22,700        26,383        5,181        11,309        9,370   

Income tax expense(2)

    —          —          —          —          10,015   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 22,700      $ 26,383      $ 5,181      $ 11,309      $ (645)   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

ALLOCATION OF 2011 NET LOSS

         

Net loss

          $ (645)   

Net income prior to purchase of properties from Scintilla in exchange for common stock on August 12, 2011

            10,146   
         

 

 

 

Net loss subsequent to purchase of properties from Scintilla in exchange for common stock on August 12, 2011

          $ (10,791)   
         

 

 

 

Net loss per common share from August 12, 2011 to December 31, 2011 - basic and diluted(3)

          $ (0.51
         

 

 

 

Weighted average shares outstanding used in computing net loss per share - basic and diluted(3)

            21,358   
         

 

 

 

Pro forma net income reflecting change of tax status

         

(unaudited)(4)

         

Income before income taxes

      $ 5,181      $ 11,309      $ 9,370   

Pro forma income tax expense

        1,259        3,733        3,028   
     

 

 

   

 

 

   

 

 

 

Pro forma net income

      $ 3,922      $ 7,576      $ 6,342   
     

 

 

   

 

 

   

 

 

 

Pro forma earnings per share - basic and diluted

         

(unaudited)(4)

         

Pro forma net income per common share

      $ 0.20      $ 0.38      $ 0.31   
     

 

 

   

 

 

   

 

 

 

Shares used in computing earnings per share

        20,000        20,000        20,524   
     

 

 

   

 

 

   

 

 

 

 

(1) Natural gas sales for the year ended December 31, 2007 include natural gas liquids sales for the period.
(2) Scintilla, which owned the Scintilla Assets before they were acquired by us on August 12, 2011, is treated as a partnership for income tax purposes and, as such, Scintilla paid no income taxes. The Scintilla Assets were contributed to us for stock and cash. Under Section 351 of the Internal Revenue Code of 1986, as amended (the “Code”), we inherited the historical tax basis of the assets transferred plus a step-up in basis attributable to the cash received by Scintilla. Since we are a taxable entity, we were required to accrue non-recurring deferred income taxes attributable to the acquisition of the Scintilla Assets of $10.9 million. We also acquired the Other Contributed Assets from other parties as part of the same plan under Section 351 of the Code purely for stock. As a result, we inherited the historical tax basis of the Other Contributed Assets and recorded a deferred tax liability of $4.2 million and a corresponding amount of goodwill.
(3) Scintilla is a limited liability company with ownership interests represented by units rather than shares.
(4) Pro forma net income and earnings per share reflect income tax expense resulting from income before taxes, as if the Scintilla Assets had been held by a taxable corporation beginning as of January 1, 2009. For further explanation, see Note 1 to our financial statements included elsewhere in this prospectus.

 

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     As of December 31,      Pro Forma
As of
December 31,
2011 (1)(2)
 
     2007      2008      2009      2010      2011     
     (unaudited)      (unaudited)                              
     (in thousands)  

Balance Sheet Data:

                 

Cash and cash equivalents

   $ —         $ —         $ —         $ —         $ 738       $ 19,779   

Oil and natural gas sales receivables

     8,228         4,401         6,536         6,445         7,108         7,108   

Other current assets

     —           —           —           994         1,485         1,485   

Total property and equipment, net

     65,991         74,151         82,620         94,885         125,346         125,346   

Other assets(3)

     162         49         —           1,453         8,227         6,961   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 74,381       $ 78,601       $ 89,156       $ 103,777       $ 142,904       $ 160,679   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 4,858       $ 3,441       $ 2,871       $ 6,009       $ 6,467       $ 6,467   

Long-term debt

     43,000         60,000         60,000         60,000         68,500         —     

Deferred tax liability(4)

     —           —           —           —           14,145         9,010   

Other long-term liabilities

     576         685         837         2,175         5,164        
5,164
  

Total parent net investment/stockholders’ equity

     25,947         14,475         25,448         35,593         48,628      

 

140,038

  

  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and parent net investment/stockholders’ equity

   $ 74,381       $ 78,601       $ 89,156       $ 103,777       $ 142,904       $ 160,679   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) On August 12, 2011, we acquired the Other Contributed Assets, which are included from the date of acquisition forward.
(2) Reflects (i) the proceeds from this offering at an assumed initial public offering price of $11.00 per share, which is 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 and (ii) the application of proceeds as described in “Use of Proceeds.” Each $1.00 increase (decrease) in the assumed initial public offering price of $11.00 per share would increase (decrease) the amount of as adjusted cash and cash equivalents, total assets and total liabilities and parent net investment/stockholders’ equity by approximately $8.1 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. Similarly, each increase (decrease) of one million shares in the number of shares of common stock offered by us would increase (decrease) cash and cash equivalents, total assets and total liabilities and parent net investment/stockholders’ equity by approximately $10.2 million, assuming the assumed initial public offering price remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(3) Pro forma amount reflects the exclusion of approximately $1.3 million associated with deferred offering costs of this offering, which will be offset against the proceeds of this offering.
(4) On August 12, 2011, in connection with the acquisition of the Scintilla Assets, we became a taxable entity. At the time of becoming a taxable entity, the aggregate net book basis of the oil and natural gas properties exceeded the aggregate net tax basis resulting in us recording a deferred tax liability of approximately $10.9 million. Prior to that time, the Scintilla Assets were owned by a limited liability company that is treated as a partnership for federal and state income tax purposes.

 

    Year Ended December 31,  
    2007     2008     2009     2010     2011  
    (unaudited)                          
    (in thousands)        

Cash Flow Information:

         

Net cash provided by operating activities

  $ 35,670      $ 45,949      $ 17,042      $ 28,674      $ 26,498   

Net cash used in investing activities

  $ (25,371   $ (25,094   $ (22,834   $ (26,074   $ (32,234

Net cash provided by (used in) financing activities

  $ (10,299   $ (20,855   $ 5,792      $ (2,600   $ 6,474   

 

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Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of the results of our operations and financial condition should be read in conjunction with the “Selected Historical Financial Data,” our financial statements, and the notes to those financial statements that are included elsewhere in this prospectus. Our discussion includes forward-looking statements based upon current expectations that involve risks and uncertainties, such as our plans, objectives, expectations and intentions. Actual results and the timing of events could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under this section, “Risk Factors,” “Business” and other sections in this prospectus. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview and Basis of Presentation

Until the closing of our acquisition of the Acquired Assets, we were a newly formed corporation with only nominal assets and no active business operations. We purchased the Acquired Assets on August 12, 2011. Since Scintilla is under common control with us, we recorded the Scintilla Assets retrospectively at their historical carrying values, and no goodwill or other intangible assets were recognized. We acquired the Other Contributed Assets on August 12, 2011, amounting to approximately 7% of the Acquired Assets (based on PV-10 reserve value as of December 31, 2010), from parties other than Scintilla not under common control with us, and accordingly, the Other Contributed Assets have not been included in our historical financial statements as of dates and for periods ended prior to August 12, 2011 but are included in our financial statements prospectively from that date. Likewise, our reserve and historical operations data for periods prior to August 12, 2011 provided in this prospectus reflect only the Scintilla Assets but reflect and will reflect reserve and historical operations data of the Other Contributed Assets for periods after that date. In addition to the Acquired Assets, our financial, reserve and historical operations data for periods after December 1, 2011 also reflect our interest in the Golden Lane Extension.

Because the Scintilla Assets were acquired from an “entity under common control” with us for accounting purposes, our historical financial statements as of and for periods prior to this date were prepared on a “carve out” basis. As such, they reflect historical accounts attributable to the Scintilla Assets for such periods, including allocation of expenses of Scintilla. They also include substantial deferred income taxes attributable to the differences between the book and tax bases of the Scintilla Assets and the Other Contributed Assets. These book and tax basis differences result from prior income tax deductions taken with respect to the Acquired Assets by Scintilla and the parties from which the Other Contributed Assets were acquired. The deferred income taxes relate to the acquisition of the Acquired Assets, and are non-recurring in nature.

The financial statements may not be indicative of our future performance and may not reflect what our results of operations, financial position and cash flows would have been if we had operated as an independent company during all of the periods presented.

As a result of outstanding stock-based compensation awards that vest upon consummation of this offering, we will report substantial non-cash compensation expense, which we estimate to be approximately $11.9 million, in the quarter in which this offering is consummated. We expect to incur additional annual costs associated with the outstanding stock-based compensation awards that vest in the future as well as our compliance and disclosure obligations as a public company, which will require us to implement additional financial and management controls, reporting systems, and procedures and hire additional accounting, financial and legal staff. For this reason, we estimate that our general and administrative expenses (excluding non-cash compensation expense) will be approximately $6.4 million in the twelve months following consummation of this offering. Our general and administrative expenses are subject to change as our operations change over time.

 

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Background and Plan of Operations

We were incorporated in Delaware on July 12, 2011, and on August 12, 2011, we completed our acquisition of the Acquired Assets. Effective as of December 1, 2011, based on a confirming agreement executed on February 27, 2012, we acquired our interests in the Golden Lane Extension. Our producing properties are solely in the Hunton formation in east-central Oklahoma.

We have attempted to structure our organization around essential activities—asset acquisition and management—as well as tight fiscal controls and planning. Therefore, we intend to initially rely on the strategic relationships we have with our contract operator for drilling and production operations, as well as its other experience and expertise to help us execute our business plan. We believe that our model will allow us to dedicate capital and other resources towards continuing to identify and develop our oil and natural gas interests.

We expect that future financial results primarily will depend on (i) our ability to source and screen potential projects; (ii) our ability to develop commercial quantities of natural gas, oil and natural gas liquids; (iii) the market price for oil and natural gas; and (iv) our ability to fully implement our development program, which is in turn dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these efforts, that the prices of hydrocarbons prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding to increase our current resources.

Implementing our strategy will involve the following:

 

   

raising the necessary capital required to acquire and develop oil and natural gas properties and leaseholds;

 

   

pursuing additional acquisitions of leaseholds within our existing core areas of operation and in other fields we identify for future growth;

 

   

focusing on refining our business model as a low cost, non-operator; and

 

   

utilizing our strategic relationships to mitigate risk, benefitting from our contract operator’s historical success in identifying and developing conventional resource reservoirs, and leveraging relationships, infrastructure and expertise to develop our asset base.

 

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Results of Operations

The following table presents selected financial and operating information. Comparative results of operations for the period indicated are discussed below:

Year ended December 31, 2011 compared to the year ended December 31, 2010

 

     Year Ended December 31,              
     2010     2011     Change     Percent
Change
 

Statement of Operations (in thousands, except percent change):

        

Oil sales

   $ 5,336      $ 4,912      $ (424     (8 )% 

Natural gas sales

     9,866        9,886        20        0

Natural gas liquids

     26,522        35,179        8,657        33
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     41,724        49,977        8,253        20
  

 

 

   

 

 

   

 

 

   

 

 

 

Lease operating expenses

     5,555        6,378        823        15

Workover expenses

     2,546        2,808        262        10

Production taxes

     2,968        2,304        (664     (22 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total production expenses

     11,069        11,490        421        4

General and administrative

     670        7,660        6,990        1,043

Depreciation, depletion, and amortization

     15,404        16,159        755        5

Accretion expense

     51        59        8        16
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     27,194        35,368        8,174        30
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     14,530        14,609        79        1

Other income (expense):

        

Interest expense

     (2,648     (3,735     (1,087     41

Realized and unrealized loss from derivatives

     (573     (1,504     (931     162
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     11,309        9,370        (1,939     (17 )% 

Income tax expense

     —          10,015        10,015        N/A   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 11,309      $ (645   $ (11,954     (106 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Sales Volumes:

        

Crude oil (Bbls)

     70,561        53,349        (17,212     (24 )% 

Natural gas (Mcf)

     3,050,086        3,234,173        184,087        6

Natural gas liquids (Bbls)

     673,969        767,076        93,107        14
  

 

 

   

 

 

   

 

 

   

 

 

 

Total crude oil equivalent (Boe)(1)

     1,252,878        1,359,454        106,576        9
  

 

 

   

 

 

   

 

 

   

 

 

 

Average Sales Price (Excluding Derivatives):

        

Crude oil (per Bbl)

   $ 75.62      $ 92.07      $ 16.45        22

Natural gas (per Mcf)

   $ 3.23      $ 3.06      $ (0.17     (5 )% 

Natural gas liquids (per Bbl)

   $ 39.35      $ 45.86      $ 6.51        17

Average Sales Price (per Boe)

   $ 33.30      $ 36.76      $ 3.46        10

Average Production Costs (per Boe)(2)

   $ 6.47      $ 6.76      $ 0.29        4

 

(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(2) Includes lease operating expense and workover expense.

Oil & Natural Gas Revenues

Revenues from oil and natural gas operations were approximately $50.0 million for the year ended December 31, 2011, an increase of $8.3 million, or 20%, compared to the year ended December 31, 2010. Of the

 

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total revenues generated during 2011, approximately 70% were generated through natural gas liquids sales, approximately 20% were generated through natural gas sales and approximately 10% were generated through oil sales. The increase in revenues during 2011 was largely the result of significantly higher average prices of oil and natural gas liquids, which were 22% and 17% higher, respectively, than those of 2010. Average natural gas prices were 5% lower than 2010. Crude oil production was lower by 24% while natural gas and natural gas liquids production volumes were higher by 6% and 14%, respectively.

The following were specifically related to the impact of production and price levels on revenues recorded during the periods:

 

   

the average realized oil price was $92.07 per Bbl during the year ended December 31, 2011, an increase of 22% from $75.62 per Bbl during the year ended December 31, 2010;

 

   

total oil production was 53,349 Bbls during the year ended December 31, 2011, a decrease of 24% from 70,561 Bbls during the year ended December 31, 2010 primarily because we were developing and producing from a portion of the Hunton reservoir containing a higher concentration of natural gas liquids and a lower concentration of oil;

 

   

the average realized natural gas price was $3.06 per Mcf during the year ended December 31, 2011, a decrease of 5% from $3.23 per Mcf during the year ended December 31, 2010;

 

   

total natural gas production was 3,234,173 Mcf for the year ended December 31, 2011, an increase of 6% from 3,050,086 Mcf for the year ended December 31, 2010 primarily related to an increase in the number of wells producing;

 

   

the average realized natural gas liquids price was $45.86 per Bbl during the year ended December 31, 2011, an increase of 17% from $39.35 per Bbl during the year ended December 31, 2010; and

 

   

total natural gas liquids production was 767,076 Bbls for the year ended December 31, 2011, an increase of 14% from 673,969 Bbls for the year ended December 31, 2010 primarily because we were developing and producing from a portion of the Hunton reservoir containing a higher concentration of natural gas liquids and a lower concentration of oil.

Operating Expenses

Lease operating expenses. Lease operating expenses increased $0.8 million, or 15%, to $6.4 million in 2011 from $5.6 million in 2010, and production costs (including workover expenses) increased on an equivalent basis from $6.47 per Boe to $6.76 per Boe. The increase in production expenses was related to an increased number of wells drilled and completed in 2011 compared to 2010 as well as general price increases throughout our industry.

Workover expenses. Workover expenses increased $0.3 million, or 10%, to $2.8 million in 2011 from $2.5 million in 2010. The increase was primarily related to a higher service cost environment in 2011 compared to 2010.

Production taxes. Production taxes decreased $0.7 million, or 22%, to $2.3 million in 2011 from $3.0 million in 2010. The decrease was primarily related to increased tax incentives for production from new horizontal wells.

General and administrative. General and administrative expense increased $7.0 million, or 1,043%, to $7.7 million in 2011 from $0.7 million in 2010. The increase in general and administrative expense was primarily attributable to stock-based compensation expenses of $4.9 million and otherwise related to an increase in staffing costs and accounting and legal fees in 2011 as compared to 2010.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $0.8 million, or 5%, to $16.2 million in 2011 from $15.4 million in 2010. The increase was less than the overall increase in production due to a 26% increase in proved reserves and only an 8% increase in the full cost amortization base.

 

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Other Income/Expense

Interest expense. Interest expense increased $1.1 million, or 41%, to $3.7 million in 2011 from $2.6 million in 2010. The increase was primarily due to the write off of loan fees of $0.8 million related to the refinancing of our credit facility and higher amortized loan fees in 2011 than in 2010.

Realized and unrealized losses from derivatives. Realized and unrealized losses from derivatives were $1.5 million in 2011 compared to $0.6 million in 2010. The increase in realized and unrealized derivative losses is the result of higher oil and natural gas liquids settlement and futures in 2011 compared with 2010.

Income taxes

Income taxes were $10.0 million in 2011 compared to none in 2010. The Company became a taxable entity in 2011 and recognized significant deferred taxes primarily related to the differences in book and tax basis of oil and gas properties. The Company anticipates future income taxes to be recognized at the applicable income tax rates then in effect.

Net Income (Loss)

We recorded a net loss of $0.6 million in 2011 compared to net income of $11.3 million in 2010 primarily due to the recognition of deferred taxes incurred in connection with our acquisition of the Scintilla Assets.

 

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Year ended December 31, 2010 compared to the year ended December 31, 2009

 

     Year Ended December 31,              
     2009     2010     Change     Percent
Change
 

Statement of Operations (in thousands, except percent change):

        

Oil sales

   $ 4,388      $ 5,336      $ 948        22 

Natural gas sales

     7,773        9,866        2,093        27 

Natural gas liquids sales

     18,895        26,522        7,627        40 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     31,056        41,724        10,668        34 
  

 

 

   

 

 

   

 

 

   

 

 

 

Lease operating expenses

     5,062        5,555        493        10 

Workover expenses

     3,091        2,546        (545     (18 )% 

Production taxes

     1,215        2,968        1,753        144 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total production expenses

     9,368        11,069        1,701        18 

General and administrative

     578        670        92        16 

Depreciation, depletion, and amortization

     13,942        15,404        1,462        10 

Accretion expense

     44        51        7        16 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     23,932        27,194        3,262        14 
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     7,124        14,530        7,406        104 

Other income (expense):

        

Interest expense

     (1,943     (2,648     (705     36 

Realized and unrealized losses from derivatives

     —         (573     (573     N/A   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 5,181      $ 11,309      $ 6,128        118 
  

 

 

   

 

 

   

 

 

   

 

 

 

Sales Volumes:

        

Crude oil (Bbls)

     74,908        70,561        (4,347     (6 )% 

Natural gas (Mcf)

     3,272,490        3,050,086        (222,404     (7 )% 

Natural gas liquids (Bbls)

     651,749        673,969        22,220        3
  

 

 

   

 

 

   

 

 

   

 

 

 

Total crude oil equivalent (Boe)(1)

     1,272,072        1,252,878        (19,194     (2 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Average Sales Price (Excluding Derivatives):

        

Crude oil (per Bbl)

   $ 58.58      $ 75.62      $ 17.04        29 

Natural gas (per Mcf)

   $ 2.38      $ 3.23      $ 0.85        36 

Natural gas liquids (per Bbl)

   $ 28.99      $ 39.35      $ 10.36        36 

Average Sales Price (per Boe)

   $ 24.41      $ 33.30      $ 8.89        36 

Average Production Costs (per Boe)(2)

   $ 6.41      $ 6.47      $ 0.06       

 

(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(2) Includes lease operating expense and workover expense.

Oil & Natural Gas Revenues

Revenues from oil and natural gas operations were approximately $41.7 million for the year ended December 31, 2010, an increase of $10.7 million, or 34%, compared to the year ended December 31, 2009. Of the total revenues generated during 2010, approximately 64% were generated through natural gas liquids sales, approximately 23% were generated through natural gas sales and approximately 13% were generated through oil sales. The increase in revenues during fiscal 2010 was largely the result of significantly higher average prices of oil, natural gas liquids and natural gas during 2010, which were typically 20-40% higher than those of 2009 for oil, natural gas liquids and natural gas prices, offset by a 2% decrease in production.

 

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The following were specifically related to the impact of production and price levels on revenues recorded during the periods:

 

   

the average realized oil price was $75.62 per Bbl during the year ended December 31, 2010, an increase of 29% from $58.58 per Bbl during the year ended December 31, 2009;

 

   

total oil production was 70,561 Bbls during the year ended December 31, 2010, a decrease of 6% from 74,908 Bbls during the year ended December 31, 2009 primarily related to the pace of development of our properties;

 

   

the average realized natural gas price was $3.23 per Mcf during the year ended December 31, 2010, an increase of 36% from $2.38 per Mcf during the year ended December 31, 2009;

 

   

total natural gas production was 3,050,086 Mcf for the year ended December 31, 2010, a decrease of 7% from 3,272,490 Mcf for the year ended December 31, 2009 primarily related to the pace of development of our properties;

 

   

the average realized natural gas liquids price was $39.35 per Bbl during the year ended December 31, 2010, an increase of 36% from $28.99 per Bbl during the year ended December 31, 2009; and

 

   

total natural gas liquids production was 673,969 Bbls for the year ended December 31, 2010, an increase of 3% from 651,749 Bbls for the year ended December 31, 2009.

Operating Expenses

Lease operating expenses. Lease operating expenses increased $0.5 million, or 10%, to $5.6 million in 2010 from $5.1 million in 2009, and production costs (including workover expenses) increased on an equivalent basis from $6.41 per Boe to $6.47 per Boe. The increase in production expenses was related to an increased number of wells drilled and completed in 2010 compared to 2009.

Workover expenses. Workover expenses decreased $0.6 million, or 18%, to $2.5 million in 2010 from $3.1 million in 2009. The decrease was primarily related to a high service cost environment that resulted in fewer workovers in 2010 compared to 2009.

Production taxes. Production taxes increased $1.8 million, or 144%, to $3.0 million in 2010 from $1.2 million in 2009. The increase was primarily related to tax refunds for incentive drilling that were received in 2009.

General and administrative. General and administrative expense increased $0.1 million, or 16%, to $0.7 million in 2010 from $0.6 million in 2009. The increase in general and administrative expense was related to an increase in staffing costs in 2010 from 2009.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $1.5 million, or 10%, to $15.4 million in 2010 from $13.9 million in 2009. This increase was the result of higher capital costs spent in 2010 that resulted in higher depreciation, depletion and amortization in 2010 over 2009.

Other Income/Expense

Interest expense. Interest expense increased $0.7 million, or 36%, to $2.6 million in 2010 from $1.9 million in 2009. The increase was primarily due to increased amortized loan fees of $0.4 million related to the refinancing of the credit agreement.

Realized and unrealized losses from derivatives. Realized and unrealized losses from derivatives were $0.6 million in 2010 compared to none in 2009. We had no derivative instruments during 2009. We resumed entering into derivative instruments in the first quarter of 2010.

Net Income

Net income increased by 118% in 2010 when compared to 2009. This increase was primarily the result of significantly higher oil, natural gas liquids and natural gas prices in 2010 over 2009.

 

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Capital Commitments, Capital Resources and Liquidity

Our primary needs for cash are to fund (i) our share of development costs associated with well development within our leasehold properties, (ii) the further acquisition of and payment for additional leasehold assets, and (iii) the payment of contractual obligations and working capital obligations. We believe that funding for these cash needs will likely be provided by a combination of internally-generated cash flows from operations, additional capital raised through this offering and future equity financings, and supplemented by additional borrowings under our credit facility.

On August 12, 2011, in conjunction with closing on the Acquired Assets, we:

 

   

closed a private placement of our common stock and raised approximately $1.6 million; and

 

   

borrowed $62.5 million under a new credit facility, of which $60.0 million was paid to acquire the Scintilla Assets and approximately $2.5 million was used to pay certain fees incurred to enter into the credit facility (including professional costs and financing fees). As of March 1, 2012, approximately $4.0 million remained available to us under our credit facility to use for general working capital purposes.

We are subject to restrictive covenants under our credit facility. The ability to maintain this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. For more information regarding the terms of our credit facility, see “—Credit Facility.”

We expect our capital expenditures budget for 2012 to be approximately $54 million. We expect to be able to fund our 2012 capital budget with our operating cash flows, in conjunction with the proceeds from this offering and potential additional draws from our credit facility. Our capital budget is partially discretionary, and if we experience sustained oil and natural gas prices significantly below the current levels or substantial increases in our drilling and completion costs, we may reduce our capital spending program to remain substantially within our operating cash flows or budgetary constraints.

Other than the development of existing leasehold acreage and other miscellaneous property interests, our 2012 capital budget is exclusive of acquisitions as the timing and size of acquisitions are difficult to forecast. However, we expect to actively seek to acquire oil and natural gas properties in conventional resource reservoirs that we believe are not subject to significant risk and that provide opportunities for the addition of new reserves and production in Oklahoma and, possibly, elsewhere.

We are also required by our agreements with our contract operator to pay for leasehold held or acquired by our contract operator for our benefit pursuant to such agreements when invoiced by our contract operator, which typically occurs when development of this leasehold commences but may occur prior to that time in the discretion of our contract operator. We estimate that this obligation as of December 31, 2011 was $3.4 million and have recorded a liability in this amount. Although the exact amount we will be required to pay for leasehold in the future is difficult to predict with certainty due to the unknown timing and quantity of acquisitions of leasehold by our contract operator, based on current trends we expect that we will be required to pay approximately $2.8 million during 2012 and between approximately $1.8 and $1.6 million each in 2013 and 2014, respectively, in respect of these leasehold acquisition costs.

While we believe that our available cash and cash flows will partially fund our 2012 capital expenditures, as adjusted from time to time, we cannot provide any assurances that we will be successful in securing additional funding for all of our planned expenditures. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by our contract operator or third parties for leasehold acquisition or relating to projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, we would consider increasing, decreasing, or reallocating our 2012 capital budget under certain circumstances.

 

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As noted above, the primary sources of liquidity for our anticipated day-to-day operations are expected to be cash flows generated from operating activities. We believe that funds from our anticipated cash flows and any financing under a credit facility combined with proceeds from this offering should be sufficient to meet both our short-term working capital requirements and our 2012 capital expenditure plans. However, our growth plan will require that we raise a substantial amount of additional capital. There can be no assurance that we will be able to raise the additional capital that will be necessary to fund our anticipated growth strategy. Capital may not be available to us on reasonable terms, if at all, in the public or private markets.

 

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

Financial Measures:

      

Net cash provided by operating activities

   $ 17,042      $ 28,674      $ 26,498   

Net cash used by investing activities

   $ (22,834   $ (26,074   $ (32,234

Net cash provided by (used in) financing activities

   $ 5,792      $ (2,600   $ 6,474   

Net cash provided by operating activities for all periods primarily consisted of cash receipts from oil and natural gas sales, payments to vendors for operating costs and payments of production taxes. Net cash used by investing activities primarily consisted of payments made for drilling and equipping wells. Net cash provided by (used in) financing activities primarily consisted of equity investment by, or distributions to, the owner, credit facility borrowings and loan payments.

Off-Balance Sheet Arrangements

As of December 31, 2011, we had no material off-balance sheet arrangements. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Credit Facility

On August 12, 2011, we entered into a $150.0 million four-year credit facility with Bank of Montreal as administrative agent and KeyBank as syndication agent. Although the credit facility has a $150.0 million borrowing limit, we are only entitled to borrow an amount equal to our borrowing base, which will be redetermined on a semiannual basis and at other times as directed by us or the administrative agent. The initial borrowing base was $72.5 million. The borrowing base will be redetermined based on reserve reports prepared by engineers acceptable to the administrative agent, which we must deliver to the administrative agent on April 1 and October 1 of each year. At December 31, 2011, the borrowing base was $72.5 million.

We intend to use the net proceeds of this offering to repay all outstanding indebtedness under our credit facility, leaving us the full borrowing base of $72.5 million available for future borrowings. As of March 1, 2012, we had approximately $68.5 million outstanding under our credit facility and, as a result, we had $4.0 million of available borrowing capacity under the credit facility. Of the amount drawn under the credit facility, $60.0 million was used to purchase the Acquired Assets and $2.5 million was used to pay certain fees incurred to enter into the credit facility. The credit facility matures on August 12, 2015. Amounts borrowed and repaid under the credit facility may be reborrowed. The credit facility is available for general corporate purposes, including working capital for our operations.

The obligations of the lenders under our credit facility are several, not joint, meaning that if one lender fails to meet its lending obligations, the other lenders do not have to make us whole. As a result, the total amount that we may borrow might be substantially less than the borrowing base.

Our obligations under the credit facility are secured at all times by substantially all of our assets. We may prepay all advances at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of LIBOR borrowings.

 

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Indebtedness under the credit facility bears interest, at our option, at either:

 

   

the higher of the administrative agent’s prime rate or the federal funds rate plus 0.50%, plus an applicable margin that ranges from 1.50% to 2.25%, depending on the percentage of the borrowing base being utilized; or

 

   

LIBOR plus an applicable margin that ranges from 2.50% to 3.25%, depending on the percentage of borrowing base being utilized.

In addition, the credit facility contains various covenants that limit, among other things, our ability to:

 

   

grant liens on our assets;

 

   

incur additional indebtedness;

 

   

engage in a merger, consolidation or dissolution;

 

   

sell or otherwise dispose of our assets, businesses and operations;

 

   

materially alter the character of our business;

 

   

make acquisitions, investments and capital expenditures;

 

   

enter into any transactions with affiliated parties except as specifically contemplated in the credit facility; and

 

   

pay cash dividends or make certain other distributions to stockholders.

The credit facility also contains covenants requiring us to maintain:

 

   

a current ratio (the ratio of our consolidated current assets to our consolidated current liabilities) of not less than 1.0 to 1.0;

 

   

a leverage ratio (the ratio of our consolidated funded indebtedness under the credit facility and all other sources to our consolidated adjusted EBITDAX, as defined in the credit agreement) of not more than 3.5 to 1.0; and

 

   

an interest coverage ratio (the ratio of our consolidated EBITDAX to our consolidated interest expense, as defined in the credit agreement) of not less than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination.

As of December 31, 2011, we were in compliance with these covenants. If an event of default exists under the credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other rights and remedies. Each of the following could be an event of default under the credit facility:

 

   

failure to pay any principal when due or any interest or fees within three business days of the due date;

 

   

failure to perform or otherwise comply with the covenants in the credit facility;

 

   

failure of any representation or warranty to be true and correct in any material respect;

 

   

failure to pay debt;

 

   

a change of control of us; and

 

   

other customary defaults, including specified bankruptcy or insolvency events, violations of the Employee Retirement Income Security Act of 1974, and material judgment defaults.

Contractual Obligations

In addition to our contractual obligations to service our credit facility and to pay our proportionate shares of acreage and other costs in existing and new wells in the Golden Lane field and the Luther field, we currently

 

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lease 6,595 square feet as our principal executive offices at the rate of $7,100 per month (which we believe reflects current market rates). This lease is for a one-year term with two one-year options on the same terms and conditions. We have also entered into employment agreements with four of our executive officers, Messrs. Kos, Chernicky, Finley and Thompson, providing for the payment of their salaries and certain initial grants of restricted stock described elsewhere in this prospectus. We generally may terminate the employment of these individuals at any time without liability to us under these agreements, except that if we terminate one of these officers without cause, all of such terminated officer’s remaining unvested shares of restricted stock will immediately vest. See “Executive Compensation and Other Information—Potential Payments upon Termination or Change in Control.

The following table summarizes our contractual obligations and commitments as of December 31, 2011:

 

     Payments due by period
(in thousands)
 

Contractual Obligations

   Total      Less than
1 year
     1-3
years
     3-5
years
     More than
5 years
 

Long-Term Debt Obligations(1)

   $ 68,500         —           —         $ 68,500         —     

Operating Lease Obligations(2)

     48         48         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 68,548       $
48
  
     —         $ 68,500         —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) As of March 1, 2012, there was $68.5 million outstanding under our credit facility, which we intend to repay using the net proceeds of this offering.
(2) Represents amounts owed in rent for our principal executive offices as described above.

Quantitative and Qualitative Disclosure about Market Risk

As we expand, we will be exposed to a variety of market risks including commodity price risk, credit risk and interest rate risk. We will address these risks through a program of risk management which will likely include the use of derivative instruments including hedging contracts. Such contracts may involve incurring future gains or losses from changes in commodity prices or fluctuations in market interest rates.

Commodity Price Risk. We are exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. Factors that may impact the price of oil and natural gas include:

 

   

developments generally impacting significant oil-producing countries and regions, such as Iraq, Iran, Syria, and Libya, the gulf coast and offshore South and Central America, Alaska and onshore U.S.;

 

   

the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas;

 

   

the overall demand for oil and natural gas in the United States and abroad;

 

   

volatility in the U.S. and global economies;

 

   

weather conditions; and

 

   

new and changing legislation and regulatory philosophy in the U.S.

Any improvements in oil and natural gas prices may have a favorable impact on our financial condition, results of operations and capital resources. If oil prices decline by $10.00 per Bbl, then our Standardized Measure as of December 31, 2011 would have been lower by approximately $4.7 million. If natural gas liquids prices decline by $5.00 per Bbl, then our Standardized Measure as of December 31, 2011 would decrease by approximately $20.9 million. If natural gas prices decline by $1.00 per Mcf, then our Standardized Measure as of December 31, 2011 would decrease by approximately $18.4 million.

 

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Our primary commodity risk management objective is to reduce volatility in our cash flow. We enter into hedges for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform according to the hedging arrangement. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.

Presently, all of our hedging arrangements are with one counterparty, which is a lender under our credit facility. If this counterparty fails to perform its obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.

The result of natural gas market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

Counterparty and Customer Credit Risk. We will monitor our risk of loss due to non-performance by counterparties of their contractual obligations. We have exposure to financial institutions in the form of derivative transactions in connection with our hedging activity. A lender under our credit facility is the counterparty on our derivative instruments currently in place and has investment grade credit ratings. If this counterparty were to default on any of our derivative instruments while there is an outstanding balance under our credit facility, we believe we would have the ability to offset the amount of any payment owing from this counterparty against the portion of the outstanding balance under our credit facility then owed to such counterparty. We expect that any future derivative transactions we enter into will be with this or other lenders under our credit facility that carry an investment grade credit rating.

We also have exposure to credit risk through our operating partners and their management of the sale of our oil and natural gas production, which they market to energy marketing companies and refineries. We anticipate that we will monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements, production, sales, marketing, engineering and reserve reports. See “Business—Principal Customers” for further detail about our significant customers.

Interest Rate Risk. We intend to use the net proceeds from this offering to repay all outstanding indebtedness under our credit facility. As of March 1, 2012, we had $68.5 million outstanding under our credit facility, which is subject to floating market rates of interest. Borrowings under our credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.

Critical Accounting Policies and Practices

Investors in our company should be aware of how certain events may impact our financial results based on the accounting policies in place. In our management’s opinion, the more significant reporting areas impacted by our management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets and valuation of stock-based compensation. Our management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

 

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The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business. The three policies we consider to be the most significant are discussed below.

Oil and Natural Gas Properties. The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full-cost method. We utilize the full-cost method of accounting, under which all costs associated with property acquisition, exploration and development activities are capitalized. We also have the ability to capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a well by well or lease or field basis. Additionally, gain or loss may generally be recognized on sales of oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method, since we will generally reflect a higher level of capitalized costs, as well as a higher oil and natural gas depreciation, depletion and amortization rate, and we will not have exploration expenses that successful efforts companies frequently have.

Under the full-cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred.

We review the carrying value of our oil and natural gas properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges), less estimated future expenditures to be incurred in developing and producing the proved reserves and less any related income tax effects. Commencing with the quarter ended on December 31, 2009, in calculating estimated future net revenues, current prices have been calculated as the unweighted arithmetic average of oil and natural gas prices on the first day of each month within each applicable twelve-month period. Costs used were those as of the end of the appropriate quarterly period. For quarters prior to the fourth quarter of 2009, current prices and costs used were those as of the end of the appropriate quarterly period.

Two primary factors impacting this test are reserve levels and oil and natural gas prices and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense.

Oil, Natural Gas Liquids and Natural Gas Reserve Quantities. Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and

 

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operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. We rely upon various assumptions in our estimation of proved reserves, including in the case of proved undeveloped reserves that we will participate fully in the development of our undeveloped properties pursuant to the terms of the applicable operating agreement. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of additional assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

Derivative Instruments. We use commodity price and financial risk management instruments to mitigate our exposure to fluctuations in oil and natural gas prices. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of oil and natural gas derivative contract settlements and the changes in the fair value of derivative instruments that occur prior to maturity are reflected in other income in the statement of operations. Accounting guidance for derivatives and hedging establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as oil and natural gas cash flow hedges, changes in fair value, to the extent the hedge is effective, are to be recognized in other comprehensive income until the hedged item is recognized in earnings as oil and natural gas sales. Any change in the fair value resulting from ineffectiveness is recognized immediately as gains or losses in the statement of operations. All derivative instruments are recognized as either assets or liabilities in the balance sheet at fair value. None of such instruments have been designated as cash flow hedges. Accordingly, changes in the fair value of all derivative instruments have been recorded in the statements of operations.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

Due to the volatility of oil and natural gas prices, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2011 and 2010, the fair value of our derivatives was a net liability of $1.3 million and $1.4 million, respectively.

Valuation of Stock for Purposes of Asset Acquisition and Stock Based Compensation. The stock issued in connection with the acquisition of the Acquired Assets and for purposes of stock based compensation was valued pursuant to our current policy of employing market attributes of what the Board of Directors consider to be

 

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comparable companies. There have been no options granted. On August 12, 2011, we acquired the Other Contributed Assets in exchange for 1.2 million shares of our stock. During August of 2011, we entered into employment agreements with our (a) president and chief executive officer, (b) chief financial officer and treasurer, (c) senior geologist and executive chairman, and (d) general counsel and secretary. In connection with the employment agreements, we granted 2.9 million shares of restricted common stock, with 1.0 million shares vesting upon the first anniversary of the date of grant, 0.7 million shares vesting on the second anniversary of the date of grant and the remaining 1.2 million shares vesting on the completion of our initial public offering of common stock pursuant to this prospectus, provided that the employees remain employed by us on the applicable vesting dates subject to limited exceptions. 

In connection with the issuance of 1.2 million shares of our stock, our management estimated the value of our stock as of the date of the transaction. Because we are privately held and there is no public market for our common stock, the fair market value of our common stock was determined by our management at the time the transaction occurred. In determining the fair value of our common stock, our management considered such factors as our actual and projected financial results, the principal amount of our indebtedness, valuations based on financial and reserve report multiples of comparable companies, control premium, marketability considerations, valuations of us performed by third parties and other factors it believed were material to the valuation process.

In connection with the issuance of 2.9 million shares of our common stock for employment agreements, our board of directors estimated the value of our stock as of the date of each grant. Because we are privately held and there is no public market for our common stock, the fair market value of our common stock was determined by our board of directors at the time the grants were made. In determining the fair value of our common stock, our board of directors considered such factors as our actual and projected financial results, the principal amount of our indebtedness, valuations based on financial and reserve report multiples of comparable companies, control premium, marketability considerations, valuations of us performed by third parties and other factors it believed were material to the valuation process.

We have valued the shares awarded at $9.95 per share and amortize to expense over the vesting periods for which there are fixed vested terms of the awards. Accordingly, we recorded $4.9 million of stock-based compensation for the year ended December 31, 2011. Future minimum stock-based compensation expense for these awards is as follows:

 

2012

   $ 9.8 million   

2013

   $ 2.2 million   

An additional $11.9 million is expected to be charged to expense in the period in which the offering covered by this prospectus is completed.

 

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BUSINESS

Overview

We are an independent energy company engaged in the development and production of onshore oil and liquids-rich natural gas projects in the United States. Our primary business strategy is to utilize specialized processes and low cost access to existing infrastructure to consistently and economically develop and produce hydrocarbons from known reservoirs previously deemed not prospective by others. See “Business—Specialized Processes” and “—Our Principal Business Relationships-Low Cost Access.” Our current properties consist of non-operated working interests in the Hunton formation, a conventional resource reservoir in east-central Oklahoma. This formation has a 90-year history of exploration and development and thousands of wellbore penetrations that have led to more accurate geologic mapping. We believe our position as non-operator and our strategic relationship as an affiliate of our contract operator allow us to maintain low fixed operating expenses by utilizing a limited in-house employee base aside from our management team. We are committed to pursuing conventional resource plays in proximity to our existing asset base that are similar in profile and that carry what we believe is minimal exploration risk. As of December 31, 2011, the estimated proved reserves on our properties were approximately 23.8 MMBoe, of which approximately 34% were classified as proved developed reserves and of which approximately 63% were comprised of oil and natural gas liquids. Average net daily production from our properties during the year ended December 31, 2011 was 3,725 Boe/d. Based on net production from our properties for the year ended December 31, 2011, the total proved reserves associated with our properties had a reserve to production ratio of 17.5 years.

We were formed on July 12, 2011, to acquire and develop oil and natural gas properties. On August 12, 2011, we acquired the Acquired Assets in exchange for 21.2 million shares of our common stock and $60.0 million in cash. At the time of our acquisition of the Acquired Assets, we became a party to agreements by which New Dominion will continue as the contract operator of those properties. In addition to the Acquired Assets, effective as of December 1, 2011, we entered into an agreement to acquire from New Dominion certain undeveloped leasehold in the Hunton formation located in the Golden Lane field, which we refer to as the “Golden Lane Extension.” Both Scintilla and New Dominion are owned and controlled by our principal stockholder, chairman and senior geologist, David J. Chernicky. Scintilla has served as Mr. Chernicky’s holding company for his working interests, while New Dominion has acted as the operator of those assets and related infrastructure. New Dominion has operated the Acquired Assets for 12 years, completing and economically producing from more than 98% of all wells it has drilled in the Hunton formation using the same specialized processes that will be utilized in the operation and development of our properties. As a result of our relationship as an affiliate of Scintilla and New Dominion, we will benefit from the operational efficiencies in these specialized processes to maintain our low average finding, developing and operating costs.

We have a right of first refusal to acquire up to 90% of Scintilla and New Dominion’s combined interest in all future oil and natural gas projects they pursue for 25 years (i.e., until August 12, 2036). As of March 1, 2012, Scintilla and New Dominion collectively held approximately 74,713 net acres in other formations above and below the Hunton formation that we believe have reservoir profiles similar to our properties. If we exercise our right of first refusal in full with respect to these interests as or after they are developed, we could acquire as much as 67,241 net acres in these formations. Pursuant to our right of first refusal agreement, we have the right to acquire oil and natural gas projects from New Dominion and Scintilla at and after the point in time such properties are determined to have proved reserves of oil and natural gas. We believe our strategic partnership with New Dominion and Scintilla and the common ownership of Mr. Chernicky in New Dominion, Scintilla and our company enhance our ability to grow our production and expand our proved reserve base over time. In addition, this relationship provides us with significant influence over the rate of development of our long-lived, low cost asset base as compared to other traditional non-operators. It also provides us access to personnel with extensive technical expertise and industry relationships and perpetual access to existing infrastructure at what we believe are favorable rates. See “Business—Material Definitive Agreements” and “Certain Relationships and Related Party Transactions.”

 

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Our properties are located in east-central Oklahoma and consist of mature, legacy oil and natural gas reservoirs. We believe that, through application of specialized processes, our properties are low risk due to predictable production profiles, low decline rates, long reserve lives and modest capital requirements. Our properties consist of non-operated working interests in producing and undeveloped leasehold acreage and in identified producing wells with an average working interest of 55% in our wells within the Luther field and a working interest ranging from 21% to 87% (38% weighted average) in our wells within the Golden Lane field. As of March 1, 2012, we had 46,080 gross (13,387 net) acres in the Luther field and 155,360 gross (42,481 net) acres in the Golden Lane field.

Ralph E. Davis Associates, Inc., our independent reserve engineers, estimated the net proved reserves on our properties to be approximately 23.8 MMBoe as of December 31, 2011, 63% of which were classified as oil and natural gas liquids and 37% of which were classified as natural gas. The average net daily production rate from our properties during the year ended December 31, 2011 was 3,725 Boe/d.

 

    Estimated Proved Reserves at
December 31, 2011 (1)
    Production for the
Year Ended
December 31, 2011
    Projected
2012
Capital
Expenditures
(MM)
    Proved
Undeveloped
Drilling
Locations as
of
December 31,
2011
 

Field

  Total
Proved
(MBoe)
    Percent
of
Total
    Percent
Proved
Developed
    Percentage
of
Depletion (2)
    Percent
Oil and
Liquids
    PV-10
(MM)(3)
    Average
Net
Daily
Production
(Boe/d)
    Percent
of
Total
     
                    Gross     Net  

Golden Lane

    18,284        76.9     40.8     53.8     71.3   $ 275.3        3,450        92.6   $ 28.9        231        54.7   

Luther

    5,507        23.1     9.4     7.4     35.0   $ 52.8        275        7.4   $ 24.9        59       
16.2
  
 

 

 

   

 

 

         

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    23,791        100.0     33.5     47.7     62.9   $ 328.1        3,725        100.0   $ 53.8        290        70.9   

 

(1) Proved reserves were calculated using prices equal to the twelve month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months, which were $96.19 per Bbl of crude oil, $50.02 per Bbl of natural gas liquids and $4.12 per Mcf of natural gas. Adjustments were made for location and the grade of the underlying resource, which resulted in an average decrease of $3.24 per Bbl of crude oil, an average decrease of $1.69 per Bbl of natural gas liquids and a decrease of between $0.12 and $0.28 per Mcf of natural gas.
(2) Percentage of depletion was calculated by dividing cumulative production from our properties in these fields by the sum of proved reserves attributable to such properties and cumulative production from such properties.
(3) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 typically differs from the Standardized Measure because it does not include the effects of income tax. However, the Scintilla Assets’ PV-10 and Standardized Measure as of December 31, 2009 and 2010 are equivalent because as of these dates the Scintilla Assets were held by a limited liability company not subject to entity-level taxation. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.

The following table provides an illustration of our PV-10 and our Standardized Measure reflecting the effect of income taxes:

 

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

PV-10

   $ 142,018       $ 178,471       $ 328,137   

Estimated income taxes(a)

     55,245         69,425         118,139   
  

 

 

    

 

 

    

 

 

 

Standardized Measure

   $ 86,773       $ 109,046       $ 209,998   
  

 

 

    

 

 

    

 

 

 

 

  (a)

Scintilla, which owned the Scintilla Assets before they were contributed to us, is a partnership for federal income tax purposes and, therefore, is not subject to entity-level taxation. Historically, federal or state income taxes have been passed through to the member

 

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  owners of Scintilla. However, as a corporation, we are subject to U.S. federal and state income taxes. The estimated taxes shown above illustrate the effect of estimated income taxes on net revenues as of December 31, 2009 and 2010, assuming we had been subject to corporate-level income tax and further assuming an estimated statutory combined 38.9% federal and state income tax rate.
  (b) Our PV-10 and Standardized Measure as of December 31, 2009 and 2010, respectively, are derived from revised estimates of our proved reserves after the retroactive application of a change in methodology utilized in estimating proved undeveloped reserves. The related effects of this change in methodology on our results of operations and financial condition were immaterial and therefore have not been reflected in our historical financial statements included in this prospectus. For further information regarding this change in methodology, see the discussion in the unaudited supplementary information to our financial statements beginning on page F-25.

We use the term “conventional resource play” to refer to high water saturation (35 – 99%) hydrocarbon reservoirs that typically have been deemed not prospective by others. Conventional resource plays are usually located around and below conventional reservoirs, although they can exist independently. These reservoirs tend to be continuous hydrocarbon zones existing over a contiguous and potentially large geographical area. Conventional resource plays exhibit low exploration risk with consistent results and predictable EUR. With the implementation of specialized processes, we believe we have the ability to economically develop these large-scale reservoirs.

Our contract operator and senior geologist have developed conventional resource plays for 25 years, which has provided them with insights on the physical processes at work and a significant amount of practical operating experience in how to economically produce from these reservoirs. As a result of this experience, they have developed and refined processes that they will utilize in developing our conventional resource plays. Prior conventional resource plays in which our contract operator and senior geologist have used these specialized processes to successfully and economically produce oil and natural gas include the Red Fork formation in the Mount Vernon field in central Oklahoma, which they developed in the late 1980s, and the Hunton formation in the Carney and Golden Lane fields in central Oklahoma, which they commenced developing in 1999. Each of these projects had been passed over by other industry operators because of its high saltwater content. The cumulative production from these fields from January 1, 1989 through December 31, 2011 following application of their specialized processes is 33.4 MMBoe.

The Hunton formation is our primary conventional resource play in east-central Oklahoma. We intend to continue to develop our Golden Lane and Luther fields in this formation where we maintained interests in approximately 219 gross (86.1 net) producing wells as of December 31, 2011. Our acreage position had 290 gross (70.9 net) proved undeveloped (PUD) locations as of December 31, 2011. Our contract operator is currently using four rigs to drill on our properties, which may be increased to up to eight over the next twelve months. Our contract operator has completed an average of 25 gross wells per year on our acquired properties over the past six years.

Our 25-year right of first refusal agreement includes, among other potential opportunities, existing rights to produce in areas covering approximately 74,713 net acres of prospective conventional resource reservoir formations located above and below the Hunton formation, such as the Cleveland, Red Fork, Caney, Mississippian and Arbuckle. If we exercise our right of first refusal in full with respect to these interests as or after they are developed, we could acquire as much as 67,241 net acres in these formations. These reservoirs have current production, and our contract operator is in the process of estimating the proved reserves associated with the properties currently held by it and Scintilla in these reservoirs, pending third-party evaluation. We also have identified similar conventional resource play leaseholds held by third parties in and around our primary acreage in east-central Oklahoma that we will attempt to acquire to increase our proved reserves and drilling inventory.

Our method of hydrocarbon recovery relies upon exploiting the reservoir through development, rather than exploration. Our technical team, in conjunction with our contract operator, has geologic and engineering expertise in horizontal well design, submersible pump placement, fluid and hydrocarbon separation and saltwater disposal. We believe this experience helps us realize production efficiencies utilizing methodologies that provide a predictable ultimate recovery of hydrocarbons. In developing new reserves in conventional resource plays, we employ, in conjunction with our contract operator, the following six essential components:

 

   

proper geologic assessment of the reservoir, which is facilitated by data from numerous existing well penetrations;

 

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a well-trained and knowledgeable technical team to maintain efficient production;

 

   

strategic placement of wells to maximize the benefit of wells working in concert to create the appropriate draw down in reservoir pressure;

 

   

an economic high-volume saltwater transportation and disposal system;

 

   

abundant and economic high-current three-phase electrical power; and

 

   

a high-volume, liquids-rich gas gathering and processing system.

Business Strategy

Our objective is to increase stockholder value by increasing reserves, production and cash flows at an attractive return on capital. We intend to accomplish these objectives by executing on the following key strategies:

 

   

Focus on Conventional Oil and Liquids-Rich Resource Plays. We are focused on developing and converting conventional oil and liquids-rich resource plays into cost-efficient development projects. This strategy enables us to leverage our expertise in economically producing reserves that previously have been deemed not prospective by others.

 

   

Accelerate Development of Existing Low Cost Proved Inventory. In the near term, we and our contract operator intend to accelerate the drilling of our low risk, long lived PUD inventory to maximize the value of our resource potential using existing infrastructure. We and our contract operator will continuously evaluate our drilling program and expect to select the types and spacing of wells we will drill in a manner aimed at optimizing flow and maximizing the recovery of hydrocarbons from the reservoir. We have identified 102 gross (34.1 net) PUD locations as of December 31, 2011 for prospective development through increased density wells.

 

   

Maintain Our Low Cost Operating Structure. We are focused on continuous improvement of our operating measures through our contract operator. We believe that the size and concentration of our acreage within our project areas provide us with the opportunity to continue to capture economies of scale, including the ability to use our contract operator’s existing infrastructure at what we believe to be attractive rates. In addition, we, along with our contract operator, attempt to reduce the drilling, completion and infrastructure costs associated with the development of our properties by drilling multiple wells from a single pad site.

 

   

Leverage Strategic Relationships with New Dominion and Scintilla. We intend to maximize the benefits of our relationships as an affiliate of New Dominion and Scintilla to help control our costs, access existing infrastructure at what we believe are favorable rates, reduce exploration risk, and maintain flexibility to determine where and when to deploy our capital. Additionally, under our agreements with New Dominion as our contract operator, New Dominion acquires and holds title to undeveloped leasehold for our benefit. New Dominion may allow us to defer paying for our interest until such time as development of this acreage commences, which allows us to focus our capital expenditures on properties with near-term drilling and completion activities.

 

   

Pursue Accretive Acquisitions. We intend to pursue bolt-on acquisitions of properties complementary to our core acreage, including properties subject to our right of first refusal agreement, when we determine such properties carry minimal or no exploration risk. We will pursue additional acquisition opportunities when we believe we possess a strategic or technical advantage due to our existing liquidity, operational experience and access to infrastructure.

Competitive Strengths

We will rely upon the following combination of strengths to implement our strategies:

 

   

Management Team with Proven Ability to Develop Conventional Resource Plays. Our senior management team averages over 25 years of industry experience, including our senior geologist,

 

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David J. Chernicky, who has over 28 years of experience in producing oil and natural gas from conventional resource plays in the area of our core assets. Our management team has developed specialized processes that allow us to develop assets that historically have been deemed not prospective by others.

 

   

Strategic Relationship with Related Parties. Our relationships with Scintilla and New Dominion provide us with access to saltwater disposal and other key infrastructure, drilling rigs, completion services, oilfield equipment and oilfield services at what we believe are favorable rates. In addition, the right of first refusal we hold from Scintilla and New Dominion provides us with an exclusive option to acquire additional assets meeting our reservoir criteria at and after the point in time they are determined to have proved reserves of oil and natural gas through the efforts of Scintilla and our contract operator. Our contract operator has a strong track record, completing and economically producing from more than 98% of all wells it has drilled in the Hunton formation since beginning to develop the play in 1999. The extensive knowledge and experience of our contract operator relating to the Hunton formation also permits it to more easily identify additional opportunities for the acquisition of prospective Hunton formation interests. Our arrangements with our contract operator grant us rights in these additional interests in our areas of mutual interest when acquired, and our contract operator may defer our obligation to pay for them until development commences.

 

   

Large, Multi-Year Drilling Inventory with Predictable Results. As of December 31, 2011, there were 290 gross (70.9 net) PUD locations targeting the Hunton formation on our properties. With a large portion of our leasehold held by production, and because of our relationship as an affiliate of our contract operator, we have the ability to influence the timing of our drilling projects. Our reserves have significant production history and predictable decline rates.

 

   

Long-Lived Reserves with High and Increasing Liquids Yield. The average productive life of our wells producing from the Hunton formation (on 640-acre spacing) is 18.5 years. The initial average Btu content of natural gas produced from this formation is approximately 1100 Btu, increases at an average of 5% per year and, based on past experience, can ultimately reach approximately 2100 Btu.

 

   

Competitive Cost Structure. Our position as non-operator and our ability to leverage our relationship as an affiliate of our contract operator allow us to mitigate significant fixed operating expenses by maintaining a limited in-house employee base apart from our management team. Our focus on conventional resource plays utilizing our contract operator’s specialized processes has resulted in average all-in finding and development costs, including revisions, on our properties of $5.68 per Boe over the three-year period ended December 31, 2011, excluding the estimated future development costs associated with PUD reserves. Production costs on our properties averaged $6.76 per Boe during the year ended December 31, 2011.

 

   

Forced Pooling. We expect to acquire additional working interests through “forced pooling” pursuant to Oklahoma law. A forced pooling action, which is very common in Oklahoma, allows a working interest owner to compel the pooling of acreage in a subject spacing unit for the purposes of causing a well or wells to be drilled. Assuming a successful application for a forced pooling order, in our contract operator’s experience this process would allow us to proceed to develop our properties with little risk of another interest owner preventing such development. During the three-year period ended December 31, 2011, our contract operator has successfully utilized forced pooling procedures to drill 78 wells in the Golden Lane and Luther fields. For a discussion regarding additional working interests we may obtain through forced pooling, see “—Specialized Processes—Forced pooling process.”

 

   

Accessible Centralized Core Geographic Area. All of our existing acreage, as well as many potential opportunities we have identified for future growth, are within a 150-mile radius of our corporate headquarters in Oklahoma City, Oklahoma. This allows us to utilize and extend existing infrastructure at a reduced cost.

 

   

Financial Flexibility. Existing internal cash flow generation allows us to continue the current rate of development of our properties. As of December 31, 2011, pro forma for this offering, we would have

 

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had minimal indebtedness and $92.3 million of total liquidity, including availability under our credit facility and cash on hand, that would allow us to accelerate growth, make strategic acquisitions and develop additional reservoirs.

Our Operations

Our operations are focused in east-central Oklahoma, including the Golden Lane field located in Pottawatomie, Seminole and Okfuskee Counties and the Luther field located in Lincoln and Oklahoma Counties. Our developmental focus is on the Hunton formation, a liquids-rich subterranean limestone reservoir. The Hunton formation is a conventional resource reservoir extending thousands of square miles across the State of Oklahoma. Though our current production is only from the Hunton formation, we believe our contract operator’s specialized processes could have potential application in several other reservoirs above and below the Hunton formation in which we may have an opportunity to acquire interests in the future, including the Cleveland, Red Fork, Caney, Mississippian and Arbuckle.

Conventional Resource Reservoirs—Hunton Formation

The Hunton formation was deposited in a shelf carbonate environment and exhibits many of the characteristics associated with this type of environment, including but not limited to, coral reefs, major dolomitization, and hundreds of major and minor disconformities caused by sea level changes and Karst topography. The Hunton formation is of Silurian-Devonian geological age and consists primarily of the Chimney Hill and Henryhouse subgroup. It varies in thickness from 0 to over 200 feet and can be mapped accurately from the thousands of subsurface penetrations over the last 90 years. It typically exhibits porosity that varies both vertically and laterally. Vertical permeability is generally poor owing to the many disconformities, but horizontal permeability and porosity is much greater and permeability in both directions is greatly enhanced due to many sets of naturally occurring fracture systems.

Area of operations

As of December 31, 2011, our properties consisted of approximately 201,440 gross (55,868 net) acres leased or held by production with 219 gross (86.1 net) wells in production. Additionally, as of December 31, 2011, there were 290 gross (70.9 net) PUD locations that target the Hunton formation. The average cost per horizontal well drilled by our contract operator in the Hunton formation for the twelve months ended December 31, 2011 was $2.7 million (based upon 640-acre spacing), including acreage, drilling, completion, gathering, and infrastructure connection expenses.

Within our area of operations, we are focused on two fields: the Golden Lane field and the Luther field.

Golden Lane Field

Our contract operator began development of the Golden Lane field in 1999 and has drilled and completed 206 economic wells since the initial development. At March 1, 2012, we held direct or indirect rights in leases on a gross area of 155,360 (42,481 net) acres in the Golden Lane field targeting the Hunton formation.

Average net daily production from our properties in the Golden Lane field was 3,450 Boe/d in the year ended December 31, 2011, all of which was produced from the Hunton formation. At December 31, 2011, we held a working interest ranging from 21% to 87% (38% weighted average) in 206 gross (78.9 net) wells in the Golden Lane field. Additionally, as of December 31, 2011, we had identified 231 gross (54.7 net) PUD drilling locations on our Golden Lane acreage. These PUD locations include 102 gross (34.1 net) PUD infill drilling locations based on 320-acre spacing, while the remaining number of such PUD locations are based on 320- to 640-acre spacing.

During the twelve months ended December 31, 2011, the average cost to drill and complete these wells for our contract operator was $2.7 million. Excluding infill locations, our PUD locations in our Golden Lane field

 

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have an average EUR of 428.8 MBoe, comprised of 10.2 MBoe of crude oil, 279.2 MBoe of natural gas liquids and 836.2 MMcf of natural gas. Our contract operator is currently running two rigs in our Golden Lane field and expects to add one drilling rig in the second quarter and two additional drilling rigs in the third quarter and drill a total of 21 gross (5.4 net) horizontal and 30 gross (10.3 net) vertical wells in this field in 2012.

Luther Field

Our contract operator began development of the Luther field in 2008 and has drilled and completed 13 economic wells since the initial development. At March 1, 2012, we held direct or indirect rights in leases on a gross area of 46,080 (13,387 net) acres in the Luther field targeting the Hunton formation.

Average net daily production from our properties in the Luther field was 275 Boe/d in the year ended December 31, 2011, all of which was produced from the Hunton formation. At December 31, 2011, we held an average working interest of 55% in 13 gross (7.2 net) producing wells in the Luther field. Additionally, as of December 31, 2011, we had identified 59 gross (16.2 net) PUD drilling locations on our Luther acreage based on 640-acre spacing.

During the twelve months ended December 31, 2011, the average cost to drill and complete these wells for our contract operator was $2.9 million. Our PUD locations in our Luther field have an average EUR of 404.4 MBoe, comprised of 5.8 MBoe of crude oil, 131.3 MBoe of natural gas liquids and 1,603.5 MMcf of natural gas. Our contract operator is currently running two rigs in our Luther field and expects to add one additional drilling rig in the third quarter and drill 27 gross (9.4 net) horizontal wells in this field in 2012.

Our Principal Business Relationships

We view our relationships with Scintilla and New Dominion, each of which is wholly owned and controlled by our chairman David J. Chernicky, as significant competitive strengths. As a result of Mr. Chernicky’s significant ownership of our common stock, we believe New Dominion and Scintilla will be motivated to support the successful execution of our business strategy and will provide us with opportunities to pursue acquisitions that fit our criteria. These relationships will provide us access to personnel with extensive technical expertise and historical success with our contract operator’s specialized processes.

Low Cost Access

Through our agreements with Scintilla and New Dominion, we have access to saltwater disposal and other low cost access to key infrastructure, drilling rigs, completion services, oilfield equipment and oilfield services. Our contract operator has invested significant capital in this infrastructure, and we are not required to pay upfront costs for infrastructure until a well is drilled. Additionally, our access to services controlled by our contract operator allows us to avoid competing for these services with other operators. Our contract operator and its affiliated service companies have increased their operatio