Index to Financial Statements

As filed with the Securities and Exchange Commission on April 24, 2012.

Registration No. 333-176548

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 6

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)

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.

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 24, 2012

9,100,000 Shares

Common Stock

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

Index to Financial Statements

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.

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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.

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.

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.

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
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.

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.

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.

•

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

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

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.

Index to Financial Statements

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.

Index to Financial Statements

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

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 24, 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.

Index to Financial Statements

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.

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.

Index to Financial Statements


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

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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.

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.

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

Index to Financial Statements

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:

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the actual prices we receive for oil and natural gas;

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our actual development and production expenditures;

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the amount and timing of actual production; and

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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 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:

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our proved reserves;

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

Index to Financial Statements

•

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

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

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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:

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well blowouts;

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cratering (catastrophic failure);

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explosions;

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uncontrollable flows of oil, natural gas or well fluids;

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fires;

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oil spills;

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pollution;

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

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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

Index to Financial Statements

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

Index to Financial Statements

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:

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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

Index to Financial Statements

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:

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

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our incurrence of additional indebtedness;

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

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

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transactions with affiliates;

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the sale of assets; and

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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:

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

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

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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;

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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;

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

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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

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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

Index to Financial Statements

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:

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

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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

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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:

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

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

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

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speculation in the press or investment community;

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

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general market conditions, including fluctuations in commodity prices; and

Index to Financial Statements

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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:

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institute a more comprehensive compliance function;

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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;

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comply with rules promulgated by the NYSE;

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

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

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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

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

•

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.

Index to Financial Statements

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;

Index to Financial Statements

•

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;

Index to Financial Statements

•

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.

Index to Financial Statements

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.”

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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			Average Price per Share
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.

Index to Financial Statements

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.

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.

Index to Financial Statements


	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)

(3)	Scintilla is a limited liability company with ownership interests represented by units rather than shares.

(4)

Index to Financial Statements


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


	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

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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	%

(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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

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.

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
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)

Index to Financial Statements

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)

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.

•

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

Index to Financial Statements

•

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

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

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an economic high-volume saltwater transportation and disposal system;

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

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

Business Strategy

•

Competitive Strengths

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

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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,

Index to Financial Statements

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.

•

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.”

•

Index to Financial Statements

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

Index to Financial Statements

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.

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. As part of our estimation of our proved reserves as of December 31, 2011, we revised our proved undeveloped reserves associated with our undrilled locations in our Luther field to reflect the performance of three horizontal wells we drilled in this field in 2011 through the end of that year. Due primarily to financial constraints, the length of the horizontal laterals in these wells was approximately 67% shorter than originally proposed. The initial performance of these wells was less than we expected and led us to lower our proved undeveloped reserves relating to our Luther PUD locations as of that date. In the first quarter of 2012, we extended the horizontal laterals of two of these three wells to conform to the original planned lengths and recompleted these wells, and the production from these two wells immediately improved to match our initial performance expectations. We also plan to recomplete the third such well in the second quarter of 2012 with the originally planned lateral lengths. As such, we believe we have adequately identified and addressed the source of the prior performance issues with these three wells and will be able to avoid similar issues going forward.

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 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 operations personnel, land department staff and other human

Index to Financial Statements

resources from 269 employees to approximately 580 employees since January 1, 2011 in order to position themselves to accommodate our contemplated drilling schedule, and our contract operator has informed us that it has access to additional drilling rigs and other capacity necessary to accelerate the rate of drilling in our fields in line with our objectives. The additional drilling rigs we and our contract operator will need to accelerate our drilling program are presently available in our contract operator’s rig fleet or alternatively are readily available from commercial contractors in the areas in which our properties are located.

Under our agreements with our contract operator, we pay our proportionate share of one-time upfront fees for access and connection to the saltwater disposal infrastructure it installs, owns and operates as part of the costs of a new well rather than ongoing saltwater disposal fees. These up-front fees are currently $300,000 for wells in the Golden Lane field and $400,000 for wells in the Luther field, corresponding to approximately $0.11 and $0.14 per Bbl, respectively, based on average saltwater production for our wells in these fields. We also are required by these agreements to reimburse our contract operator for our share of its expenses in operating its saltwater disposal infrastructure, which on average were $0.11 and $0.10 per Bbl of saltwater for the Golden Lane field wells and Luther field wells, respectively, over the year ended December 31, 2011. On a combined basis, this results in saltwater disposal fees of approximately $0.22 and $0.24 per Bbl for wells in the Golden Lane field and wells in the Luther field, respectively, which we believe are favorable to us compared to prevailing market rates. Our contract operator’s existing saltwater disposal infrastructure consists of a network of disposal wells in close proximity to our Golden Lane and Luther fields, and these disposal wells are connected to our oil and gas wells by a pipeline system for saltwater delivery to the disposal wells. Other producers who do not have the capability to transport saltwater to disposal wells via pipeline typically pay between $2.00 and $3.00 per Bbl to commercial trucking companies to pick up, haul and offload their saltwater to disposal wells, with the actual cost depending primarily on the level of competition for trucking services and the radius from the producing well to the nearest available saltwater disposal site. If they do not own the disposal well, these producers then must pay a commercial operator a disposal fee of between $0.50 and $0.65 per barrel, resulting in an all-in disposal cost that can range, on average, from $2.50 to $3.65 per Bbl. Our competitive advantage with respect to our contract operator’s disposal infrastructure is attributable to the availability of pipeline capacity for the delivery of saltwater to these disposal wells in lieu of more expensive transportation options, as well as the negotiated charges that we pay to our contract operator for access to and use of this infrastructure.

Strategic Value

Our contract operator’s investment in infrastructure is of strategic value to us as it presents a barrier to other operators in our target areas. All of our current inventory and identified near-term growth opportunities are supported by infrastructure owned and operated by our contract operator, thus allowing us to solely focus on the development of our reserves.

Specialized Processes

We, through our contract operator, use proven methods, mechanical assistance and other specialized processes to produce still-remaining reserves from conventional oil and liquids-rich resource plays previously deemed not prospective by others. Our success comes from understanding the reservoir characteristics and, in conjunction with our contract operator, using the latest available drilling, completion, and production technology to create natural conductive flow paths that enable access to the hydrocarbons within. This advanced recovery technique makes it highly economic to produce from these reservoirs. Along with horizontal and directional drilling, high-volume, electric submersible pumps are used in our wells to reduce the hydrostatic pressure in the reservoir and pull water, gas and oil from source rock formations in a way that enables those formations to produce oil and liquids-rich natural gas. Specially designed separators installed on production pad sites separate out the water, natural gas and oil. The water is sent to permitted transportation and disposal facilities. The natural gas flows into a gathering system and then to processing plants, while the oil is transported to the nearest pipeline.

With the implementation of our contract operator’s specialized processes, we have the ability to potentially develop a new class of large-scale reservoir systems. Other reservoirs with high water saturation have been

Index to Financial Statements

identified in the regions in which we currently operate, and we believe they exist in many other areas in which hydrocarbons have customarily been produced. Large reservoirs previously thought to be too high in water saturation to produce potentially can be opened up to full-scale development involving the drilling and completion of hundreds of wells in a reservoir that can cover thousands of square miles.

Unlike typical oil and natural gas reservoirs, which show declining oil and gas production rates with time, this type of reservoir increases its oil and natural gas production rate over an initial period, and then, as the reservoir is depressurized, the wells assume a more typical decline curve.

Our conventional resource plays

The type of conventional resource play on which we focus is a high water saturation hydrocarbon reservoir that demonstrates characteristics of both a conventional reservoir and a resource play. The reservoir is typically made of carbonate or deltaic sand deposits. In these reservoirs, the porosity and permeability are not well connected vertically in the formation, which restricts the movement of fluid vertically through the reservoir. However, these reservoirs have good horizontal permeability and porosity that usually extends over a large area. In addition, the permeability in both directions often is enhanced by numerous naturally occurring fracture systems.

These types of reservoirs are composed of hydrocarbon accumulations in strata that have “shows” of oil, but the reservoirs typically have been deemed not prospective by others due primarily to having water saturations of 35 to 99 percent. Although the reservoir is saturated with water, there often are significant hydrocarbons present and suspended within the reservoir by the hydrostatic pressure. Conventional resource reservoirs are located around and below the conventional reservoir, though they can exist independently. This zone is a continuous hydrocarbon system over a contiguous geographical area that can be very large. Conventional resource plays are regional in extent and exhibit low risk with consistent results and predictable EURs.

Development of our conventional resource plays

Our technical staff, in conjunction with our contract operator, has developed geologic and engineering expertise in the areas of production phase identification, well design for horizontal drilling, strategic submersible pump placement, and product separation with disposal processes. We believe this experience helps us to understand the characteristics of, and obtain efficiencies in production from, the conventional resource plays on which we focus.

EURs in conventional resource reservoirs can be calculated within a reasonable degree of certainty. This has been demonstrated through historical success of our contract operator and validated by our and our contract operator’s independent engineering firms. We, along with our contract operator, use mapping and seismic workstation capabilities to manage large volumes of digital data to correlate key reservoir parameters. This allows the technical staff to process large volumes of geological and geophysical data including cores, well tests, log suites on wells, seismic, and surface variables which in turn provides us with an optimal view and analysis of critical data and minimizes misinterpretations of information.

Resource recovery relies upon exploitation of the reservoir through development versus exploration. This allows production utilizing the following steps:

•

understanding the reservoir characteristics through complete geological analysis, extensive log analysis, core sampling where appropriate, geophysical review and economic review;

•

optimally drilling the reservoir by using multiple horizontal legs to maximize exposure to the reservoir and optimize conductive flow paths to the wellbore, and drilling four 640-acre sections from one well pad; and

•

harvesting fluids from the reservoir by pre-installing surface infrastructure, separating the fluids into oil, condensate, natural gas liquids, natural gas, and water, and maximizing recovery through well placement to optimize the effect of wells working in concert.

Index to Financial Statements

The majority of the hydrocarbons remain locked in the reservoir for up to six months after a well is completed and brought online. During this time fluids in the naturally occurring fractures are vacated utilizing electric submersible pumps, allowing the hydrostatic pressure in the reservoir to be lowered, which in turn enables the hydrocarbons to expand and vacate the pores in which they are trapped. It is at this time that peak production rates, which can average over 200 Boe per day, are observed and sustained for periods typically in excess of twelve months. During the latter stages of the well life, the electric submersible pumps are replaced with beam pumps that are less expensive to operate and maintain, resulting in additional cost efficiencies.

As the formation is depressurized, the Btu content of the hydrocarbon production stream increases. Over the life of the well this creates greater volumes of condensate and natural gas liquids per Boe produced.

The decline of saltwater volumes produced is similar to the decline of hydrocarbon production following the peak production period. This reduces operating costs over time, in turn extending the economic life of the well and maximizing the hydrocarbon recovery from the reservoir.

Our method of hydrocarbon production from conventional resource reservoirs is predicated on evaluating the optimal way to create laminar flow from the reservoir. By establishing an appropriate flow rate, the reservoir pressure drops to a point that allows for the maximum release of hydrocarbons in place. Our contract operator historically has been successful with infill drilling based on its evaluation of appropriate wellbore placement in order to create the best flow rates for reservoir drainage. In conjunction with our contract operator, we will continuously evaluate our drilling program to select the types and spacing of wells to be drilled in order to optimize our flow rates and maximize the recovery of hydrocarbons from the Hunton reservoir. Based on our analysis to date, as of December 31, 2011, we have identified 102 gross (34.1 net) PUD locations for prospective development through increased density wells and an additional 56 gross (10.2 net) PUD locations in our Golden Lane Extension for prospective development on 320-acre spacing.

Forced pooling process

Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may commence a “forced pooling” process. In a forced pooling action, which is common in Oklahoma, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.

Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing. The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

The availability of forced pooling means that it normally is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, through the efforts of our contract operator, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.

Our contract operator’s experience has been that very few other interest owners elect to participate in the drilling of new wells in our area of operations. Our contract operator has drilled a total of 78 wells over the three

Index to Financial Statements

years ended December 31, 2011 in the areas of mutual interest respectively defined by the Luther JOA and the Golden Lane Participation Agreement through successful forced pooling efforts. On average, the collective working interest of third party owners of mineral rights in these drilling units who have elected to participate in these wells (excluding participation by the other parties to the Luther JOA and the Golden Lane Participation Agreement, respectively) has been less than 1%. We believe this is attributable primarily to a disinclination on the part of such third party owners to bear their share of the costs of the proposed well. Assuming this trend continues, we expect we will be able to use the forced pooling process to increase our relative working interest in wells in which we elect to participate, which would lead to a proportionate increase in our share of the production and reserves associated with any such well. For this reason and assuming a well in which we participate is successfully drilled and completed on a particular PUD location, we believe our proved developed reserves associated with such well likely will exceed the proved undeveloped reserves previously estimated to relate to our interest in such PUD location.

Proved Undeveloped Reserves

At December 31, 2011, our proved undeveloped reserves were 15.8 MMBoe. All proved undeveloped locations are scheduled to be spud within the next five years and are located in the Hunton formation in the Golden Lane field and the Luther field. Interests we may acquire pursuant to our 25-year right of first refusal are not included in our proved undeveloped reserves. While we are not the operator and thus not in full control of the development and operation of our properties, we believe a reasonable certainty of economic recovery exists for our proved undeveloped reserves based on our strategic partnership with our contract operator and the common ownership and control of Mr. Chernicky over our contract operator and us. We expect that this relationship of common control will provide us with significant influence over the rate of development of our property base, and we expect to closely coordinate with our contract operator regarding the pace of development and production activities, the timing and amount of capital expenditures and operating costs incurred, and the selection of technology and drilling and completion methods to be employed in the development of our properties.

Our eventual net leasehold position and working interests in our proved undeveloped properties will be determined through pooling and spacing procedures. For a discussion regarding additional working interests we may obtain through forced pooling, see “—Specialized Processes—Forced pooling process.”

The following table presents changes applicable to the proved undeveloped reserves on our properties during 2011 (in MBoe):


Proved undeveloped reserves as of December 31, 2010⁽¹⁾	7,178
Revisions	(832	)
Acquisition of reserves⁽²⁾	5,690
Extensions and discoveries	5,718
Conversion to proved developed reserves	(1,936	)

Proved undeveloped reserves as of December 31, 2011	15,818

(1)

Proved undeveloped reserves as of December 31, 2010 reflect the retroactive application of a change in methodology utilized in estimating proved undeveloped reserves, which was applied subsequent to the original estimation of these reserves by our third party reserve engineering firm. 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.

(2)

Includes 4,626 MBoe of proved undeveloped reserves associated with rights to undeveloped acreage in the Golden Lane Extension, which we acquired from New Dominion and Scintilla under an oral agreement effective December 1, 2011. The oral agreement was subsequently confirmed in writing on February 27, 2012.

During 2011, we developed approximately 20% of the proved undeveloped reserves attributable to our properties as of December 31, 2010 through the drilling of 28 gross (11.2 net) development wells at an aggregate capital cost of approximately $30.1 million.

Index to Financial Statements

Independent Reserve Engineers

Our proved reserves estimates for the year ended December 31, 2011 included in this prospectus have been independently prepared by Ralph E. Davis Associates, Inc., which was founded in 1924 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1529. Within Ralph E. Davis Associates, Inc., the technical person primarily responsible for preparing the estimates shown herein was its president, Allen C. Barron. Mr. Barron has been practicing consulting petroleum engineering at Ralph E. Davis Associates, Inc. since 1993. Mr. Barron is a Registered Professional Engineer in the State of Texas (License No. 49284) and has over 40 years of practical experience in petroleum engineering, with over 30 years experience in the estimation and evaluation of reserves. He graduated from the University of Houston in 1968 with a Bachelors of Science in Chemical and Petroleum Engineering. Mr. Barron meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Technology Used to Establish Proved Reserves

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

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserves engineering firm employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, 3-D seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and 3-D seismic data were used to estimate original oil in place in certain areas.

Internal Controls over Reserves Estimation Process

Our management team works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Carol T. Bryant, our senior engineer, is the technical person within our company primarily responsible both for overseeing the preparation of our reserves estimates and for overseeing the reserves audit conducted by our third party petroleum engineer. Ms. Bryant has over 30 years of industry experience and has evaluated numerous properties throughout the United States with an emphasis on light oil and natural gas liquids, heavy oil, conventional and unconventional reservoirs, operations, reservoir development and property evaluation. Ms. Bryant holds a Petroleum Engineering degree from the University of Tulsa, which she received in 1980. For further information regarding Ms. Bryant’s qualifications, please see “Management.”

Our management team plans to meet with representatives of our independent reserve engineers periodically throughout the year to review properties and discuss methods and assumptions used in preparation of the proved

Index to Financial Statements

reserves estimates. Historically, we have had no formal committee specifically designated to review our reserves reporting and our reserves estimation process, and our reserve report was reviewed by our senior geologist and senior engineer with representatives of our independent reserve engineers and internal technical staff.

Operating Data


	Years Ended December 31,
	2009		2010		2011
Oil
Production (MBbls)		75		71		53
Average sales price (per Bbl), excluding derivatives .	$	58.58	$	75.62	$	92.07
Natural Gas
Production (MMcf)		3,272		3,050		3,234
Average sales price (per Mcf), excluding derivatives	$	2.38	$	3.23	$	3.06
Natural Gas Liquids
Production (MBbl)		652		674		767
Average sales price (per Bbl), excluding derivatives	$	28.99	$	39.35	$	45.86
Oil Equivalents
Production (MBoe)⁽¹⁾		1,272		1,253		1,359
Average equivalent price (per Boe)	$	24.41	$	33.30	$	36.76
Average daily production (Boe/d)		3,485		3,433		3,725
Average production costs (per Boe)⁽²⁾	$	6.41	$	6.46	$	6.76
Average production taxes (per Boe)	$	0.96	$	2.37	$	1.69

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

(2)	Includes lease operating expense and workover expense.

Principal Customers

Our principal products are crude oil, natural gas liquids and natural gas, which are marketed and sold primarily to purchasers that have access to nearby pipeline facilities, refineries or other markets. Typically, crude oil is sold at the wellhead at field-posted prices, and natural gas liquids and natural gas are sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, and quality) and (ii) at spot prices.

We rely on our midstream partners for the transportation, marketing, sales and account reporting for all production. The contract operator of our wells is responsible for the marketing and sales of all production to regional purchasers of petroleum products, and we evaluate the creditworthiness of those purchasers periodically. Although historically all of the natural gas, natural gas liquids and crude oil produced from our Golden Lane field and Luther field properties have been sold to a limited number of purchasers, we believe that we would be able to secure replacement purchasers if any of these purchasers were unable to continue to purchase the natural gas and crude oil produced at our properties.

Natural Gas Liquids and Natural Gas Sales/Customers: New Dominion has previously dedicated all natural gas liquids and natural gas produced and sold from wells it operates in the Golden Lane field to Scissortail Energy, LLC, a subsidiary of Copano Energy (“Scissortail”), pursuant to a long-term gas sales contract entered into on May 1, 2005, between our contract operator and Scissortail. As part of the consideration for our long-term gas dedication, Scissortail constructed and owns a gas processing plant in Paden, Oklahoma, where the gas from the Golden Lane field is processed. The natural gas liquids and natural gas produced from the Luther field is sold to DCP Midstream, LP (“DCP”) pursuant to a gas purchase contract dated September 1, 2006, as amended, between our contract operator and DCP. None of these purchasers is affiliated in any way with us or any of the other entities controlled by Mr. Chernicky.

Index to Financial Statements

Crude Oil Sales/Customers: The crude oil produced from our properties is sold to third-party marketing companies, presently United Petroleum Purchasing Company. These contracts are presently for terms of six months or less, which is customary for oil sales contracts. During the year ended December 31, 2011, 100% of total oil production from our properties in the Golden Lane field and 37% of total oil production from our properties in the Luther field was sold to UPP, and 63% of the oil production from our properties in the Luther field was sold to Enterprise Products Company. None of these purchasers is affiliated in any way with us or any of the other entities controlled by Mr. Chernicky.

Productive Wells

The following table sets forth the number of oil and natural gas wells in which we owned a working interest as of December 31, 2011.


	Crude Oil				Natural Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Golden Lane		10.0		4.5		196.0		74.4		206.0		78.9
Luther		3.0		1.5		10.0		5.7		13.0		7.2

Total		13.0		6.0		206.0		80.1		219.0		86.1

Acreage

The following table sets forth certain information with respect to our developed and undeveloped acreage as of March 1, 2012.


	Undeveloped				Developed				Total
	Gross		Net		Gross		Net		Gross		Net
Golden Lane		67,680		10,655		87,680		31,826		155,360		42,481
Luther		37,760		8,798		8,320		4,589		46,080		13,387

Total		105,440		19,453		96,000		36,415		201,440		55,868

The majority of our undeveloped acreage is not subject to material near-term lease expiration risk. As of March 1, 2012, we held approximately 7,542 net acres for which the leases are scheduled to expire (unless a well is drilled and oil or natural gas is produced from the leasehold) on or prior to February 28, 2015, of which 345 net acres are scheduled to expire on or prior to February 28, 2013, 871 net acres are scheduled to expire between March 1, 2013 and February 28, 2014 and 6,326 net acres are scheduled to expire between March 1, 2014 and February 28, 2015.

Drilling Activity

The following table describes the development wells drilled on our acreage by us or our predecessors-in-interest, respectively, during the years ended December 31, 2009, 2010 and 2011.


	Productive Wells				Dry Wells				Total
Year	Gross		Net		Gross		Net		Gross		Net
2009		24		7.9		—		—		24		7.9
2010		27		10.1		—		—		27		10.1
2011		28		11.2		—		—		28		11.2

We and our predecessors drilled no exploratory wells on our acreage during these three years.

Index to Financial Statements

Hedging Activity

We have hedging arrangements in place covering 37% of our estimated production for 2012. The following table summarizes our hedging positions as of March 1, 2012:


Fixed Price Swaps	Settlement		Volumes		Average Price		Range

Natural Gas Liquids		2012		8,643,065 gal		$1.263	$0.399 - $2.381
Natural Gas Liquids		2013		8,173,304 gal		$1.062	$0.376 - $2.300
Natural Gas Liquids		2014		3,148,316 gal		$1.133	$0.410 - $2.300

Collars	Settlement		Volumes		Floor		Ceiling

Oil		2012		110,100 Bbl		$72.00	$112.02
Oil		2013		91,145 Bbl		$72.00	$118.76
Oil		2014		34,645 Bbl		$86.01	$116.97
Natural Gas		2012		1,145,850 MMBtu	$	4.00	$4.72
Natural Gas		2013		950,004 MMBtu	$	4.25	$5.43

Material Definitive Agreements

Contribution Agreements and Related Transactions

On August 12, 2011, we entered into two contribution agreements setting forth the terms by which Scintilla and certain other parties contributed certain oil and natural gas assets and interests located in east-central Oklahoma including (i) certain oil and natural gas leases and a working interest ranging from 21% to 87% (38% weighted average) in certain wells located in the Golden Lane field and producing from the Hunton formation (the “Golden Lane Assets”), and (ii) certain oil and natural gas leases and an average 55% working interest in certain wells located in the Luther field and relating solely to the Hunton formation (the “Luther Assets,” and together with the Golden Lane Assets, the “Acquired Assets”). Scintilla contributed all of the Golden Lane Assets and approximately 84% of the Luther Assets to us, while other parties contributed the remaining approximately 16% of the Luther Assets to us. The contributing parties and the consideration they received from us in exchange for their respective interests in the Acquired Assets are as follows (in thousands):


Contributing Party	Shares of our Common Stock			Cash Consideration
Scintilla, LLC		20,000	⁽¹⁾	$	60,000
Deylau, LLC		360			—
Timothy R. and Robin L. Cargile		180			—
W.K. Chernicky, L.L.C.		240			—
Okeanos, Inc.		120			—
Tony McKaig		180			—
Red Dragon, L.L.C.		120			—

Total		21,200		$	60,000

(1)

Scintilla assigned its right to receive these shares of our common stock to the David J. Chernicky Trust.

Based on an assumed value of our common stock of $9.95 per share, we paid a total of $259 million to Scintilla for the Scintilla Assets, or an average of $13.67 per Bbl of the 18,953 MBoe in proved reserves attributable to the Scintilla Assets as of December 31, 2010. We valued the Golden Lane Assets at approximately $200 million and Scintilla’s contributed portion of the Luther Assets at approximately $60 million, primarily due to the higher level of developed reserves and corresponding higher producing well count within the Golden Lane Assets compared to a much larger relative portion of undeveloped reserves associated with the Luther Assets. We then used our $60 million valuation for Scintilla’s share of the Luther Assets to determine the appropriate number of shares of our common stock to be issued to the other parties that contributed the Luther Assets to us,

Index to Financial Statements

based on the proportionate contributions by Scintilla and such other parties of approximately 50% and 10% working interests in the Luther Assets, respectively. Accordingly, we issued an additional 1.2 million shares of our common stock to the other contributing parties, equal to $11.9 million based upon an assumed value of $9.95 per share. We believe the aggregate consideration we paid for the Acquired Assets compares favorably to the price third parties have paid for proved reserves within the past 12 to 18 months.

Simultaneously with the acquisition of the Acquired Assets, we entered into an agreement with New Dominion and Scintilla whereby we have the exclusive right, for a 25-year period (i.e., until August 12, 2036) to acquire up to 90% of Scintilla and New Dominion’s combined interest in oil and natural gas projects determined to have proved reserves. In the case of any such oil and natural gas projects in which we elect to participate, we will negotiate the price we would pay Scintilla and New Dominion for our proportionate share of those properties, but if we are unable to agree on such price, we will refer the matter to an independent appraiser to determine the fair market value of our proportionate share, whose decision will be binding on Scintilla, New Dominion and us.

This agreement also generally provides us with access to New Dominion’s existing saltwater disposal facilities and related rights in the Golden Lane and Luther fields so long as we pay the costs associated with saltwater disposal specified in the Golden Lane Participation Agreement and the Luther JOA described below, respectively.

As further described herein, New Dominion and Scintilla are wholly owned and controlled by our chairman, David J. Chernicky. New Dominion has served as the operator of the Acquired Assets, and we expect to maintain a strategic relationship with New Dominion with respect to the exploration and operation of various oil and natural gas assets and interests.

Golden Lane Participation Agreement, Luther JOA and Related Agreements

Upon the acquisition of the Golden Lane Assets and the Luther Assets, we became parties to a 2007 participation agreement by which New Dominion operates the Golden Lane field (the “Golden Lane Participation Agreement”) and a new joint operating agreement by which New Dominion operates the Luther field (the “Luther JOA”).

The other parties to the Golden Lane Participation Agreement include New Dominion, as operator, Scintilla, as a continuing working interest owner, and a number of unaffiliated companies that also own working interests in the Golden Lane field. The other parties to the Luther JOA include New Dominion, as operator, and Scintilla, as a continuing working interest owner.

The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, as operator, with authority to control the development and operation of the field. The Golden Lane Participation Agreement requires our contract operator to hold record title to undeveloped leasehold within the Golden Lane area of mutual interest for the benefit of the parties to the Golden Lane Participation Agreement until such time as development of the applicable leasehold commences. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold for a turnkey acreage fee then applicable under the Golden Lane Participation Agreement until development has commenced. Although our contract operator holds record title to this undeveloped leasehold, the Golden Lane Participation Agreement requires the assignment to us of leasehold after it is developed, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage in our reserve reports. Each party to the Golden Lane Participation Agreement has committed to participate in future wells proposed by the operator for its proportionate share of the costs associated with such wells. The operator also is empowered to acquire additional leasehold within the Golden Lane field for the account of the working interest owners in exchange for a turnkey fee per net acre acquired. This turnkey fee is currently $300 per net acre acquired and may be increased by the operator from time to time in the event of an increase in prevailing leasehold acquisition costs. The parties also have agreed to pay New Dominion their proportionate shares of an initial connection

Index to Financial Statements

charge of $300,000 per well in the Golden Lane field, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Golden Lane field and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

Under the Luther JOA, New Dominion will continue as the contract operator of our Luther field. Our contract operator will also hold record title to undeveloped leasehold within the Luther area of mutual interest for our and the other Luther JOA party’s benefit pending development of the applicable leasehold. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold plus a fee of 15% until development has commenced. Although our contract operator holds record title to this undeveloped leasehold, the Luther JOA requires the assignment to us of leasehold after it is developed, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage in our reserve reports. New Dominion is permitted to acquire additional leasehold within the Luther field for our and Scintilla’s account, and in such a circumstance we are required to pay New Dominion for our proportionate share of the actual cost of such acreage plus a fee of 15%. We also are required to advance up to $1 million in acreage acquisition costs from time to time for future acquisitions within the Luther field as often as every six months if requested by the operator. The Luther JOA also contains provisions governing the connection and access to New Dominion’s saltwater disposal infrastructure that are similar to those found in the Golden Lane Participation Agreement, except that the current connection fee is $400,000 per well for the Luther field as compared to $300,000 per well for the Golden Lane field. Additionally, the Luther JOA requires us to pay New Dominion for our proportionate share of the cost of other infrastructure deemed necessary by New Dominion to economically produce oil and natural gas, plus a fee of 15% of such amounts.

Both the Golden Lane Participation Agreement and the Luther JOA require us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. Both of these agreements contain significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements, as is customary in the oil and natural gas industry. We typically must pay our share of drilling and completion expenses no more than 30 days following notice from the operator, and in some circumstances the operator may require us to advance these amounts in the month before the operator expects to incur them. The Golden Lane Participation Agreement, in particular, requires us to contribute our entire share of estimated drilling and completion costs within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs later.

In return for serving as the operator of the Golden Lane and Luther fields, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Golden Lane Participation Agreement and the Luther JOA, including allocable shares of its employees and certain other general and administrative expenses, under joint account procedures common in the oil and natural gas industry. We generally are required to pay our proportionate share of these ongoing costs associated with the operation of our wells on a monthly basis and within 30 days of the date of our contract operator’s invoice.

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. 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. This agreement also provides that, in connection with the development of this acreage, we will enter into one or more joint operating agreements with New Dominion and Scintilla on terms substantially similar to our Luther JOA with these parties.

Credit Agreement

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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$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.” This credit facility financed the cash consideration required for the acquisition of the Acquired Assets.

Registration Rights Agreement

On August 12, 2011, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the contributing parties and the David J. Chernicky Trust as the successor in interest of Scintilla. Subject to certain conditions, the Registration Rights Agreement requires us, at our expense, to use our reasonable efforts to register the resale of the shares of common stock issued to the contributing parties under the Contribution Agreements upon demand of one or more of the contributing parties no earlier than six months from the date of the Registration Rights Agreement, and no more than twice in total. We are also required to register these shares of common stock for resale in any registration statement we file on or after six months from the date of the Registration Rights Agreement. We are not obligated to take any action to register shares pursuant to the Registration Rights Agreement during the period starting with the date 60 days prior to our estimated date of filing, and ending on the date six months immediately following the effective date of, a registration statement relating to our securities as long as we are employing all reasonable efforts in good faith to cause such registration statement to become effective. Certain of the contributing parties and the David J. Chernicky Trust 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.”

Other 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, in which we received gross proceeds of approximately $1.6 million. While our existing cash flow is sufficient to maintain our current rate of development, we determined to complete this private placement to provide us with additional financial flexibility pending the completion of this offering.

Initial Management Stock Grants

In addition to the shares received through his ownership of Deylau, LLC (“Deylau”) pursuant to a contribution agreement, Kristian B. Kos, our president and chief executive officer, received a grant of 2.3 million shares of our common stock as part of his compensation on August 18, 2011. Of those shares, 900,000 shares will vest upon completion of this offering, and the remaining 1.4 million shares will vest in equal installments on the first and second anniversary of the grant date. We also granted 200,000 shares of our common stock to each of David J. Chernicky, our chairman and senior geologist; Richard D. Finley, our chief financial officer; and V. Bruce Thompson, our general counsel and secretary, with half of such shares vesting upon completion of this offering and the other half of such shares vesting on the first anniversary of the grant date. We expect that these executive officers will request that we withhold shares of their common stock to satisfy withholding tax obligations 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 proceeds of this offering will be used to fund such withholding tax payments.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we directly or beneficially have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, neither we nor our contract operator conduct material investigations of title at the time we acquire undeveloped properties. We and our contract operator make title

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investigations and receive title opinions of local counsel, if at all, only before commencing drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with the operation of our business.

Regulation of the Oil and Natural Gas Industry

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

The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the oil and natural gas industry are regularly considered by Congress, state governments, the Federal Energy Regulatory Commission (“FERC”), the EPA, the CFTC and the courts. We believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. We are not currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.

Regulation of transportation of oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the ICA, EPAct 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as “grandfathered rates.” Pursuant to EPAct 1992, FERC also adopted a generally applicable ratemaking methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (“PPI”), plus 1.3%. For the five-year period beginning July 1, 2011, the index will be PPI plus 2.65%.

FERC has also established cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost-of-service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers. Shippers also may challenge rates before FERC.

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

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

Regulation of transportation and sales of natural gas

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affect the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. FERC has now permanently lifted the ceiling on short-term releases and adopted regulations that facilitate the use of asset managers to manage pipeline capacity.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. To the extent that FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material

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difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Oklahoma, where all of our properties are presently located, and other states have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, most states, including Oklahoma, impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Market transparency rules

In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Pursuant to Order No. 704, wholesale buyers and sellers of annual quantities of 2.2 million MMBtu or more of natural gas in the previous calendar year, including intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, by May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. Some of our operations may be required to comply with Order No. 704’s annual reporting requirements.

In 2008, the FERC issued Order No. 720, which increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines that are not natural gas companies under the Natural Gas Act that deliver more than 50 million MMBtu annually and including gathering systems) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties requested modification or reconsideration of this rule. An order on rehearing, Order No. 720-A, was issued on January 21, 2010. In that order FERC reaffirmed its holding that it has jurisdiction over major non-interstate pipelines for the purpose of requiring public disclosure of information to enhance market transparency. Order No. 720-A also granted clarification regarding application of the rule. In October 2011, the Fifth U.S. Circuit Court of Appeals vacated the order with respect to major non-interstate pipelines.

In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the Natural Gas Policy Act of 1978 and “Hinshaw” pipelines operating under Section 1(c) of the Natural Gas Act to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic

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reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. In December 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring Section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans. In January 2012, FERC revised the reporting requirements applicable to storage.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. In December 2011, both Houses passed bipartisan legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules. In addition, the Pipeline and Hazardous Materials Safety Administration announced an intention to strengthen its rules and recently promulgated new regulations extending safety rules to certain low pressure, small diameter pipelines in rural areas.

Air emissions

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects.

Climate change

The United States is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas, or GHGs, concentrations in the atmosphere at a level that would prevent serious damage to the climate system. While neither the treaty itself, nor subsequent related conferences, have established an obligation for the U.S. to reduce its GHGs emissions by a set amount, it has put significant political pressure on the U.S. to take responsive action. Both houses of Congress have previously considered legislation to reduce emissions of GHGs. Any future federal laws, treaties or implementing regulations that may be adopted to address GHGs emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

In addition, the EPA has begun to regulate GHGs emissions. In December 2009, the EPA published its finding that certain emissions of GHGs presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Consequently, the EPA is requiring a reduction in emissions of GHGs from new motor vehicles beginning with the 2012 model year. Furthermore, the EPA published a final rule on June 3, 2010 to address the permitting of GHGs emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHGs emissions, such as power plants and oil refineries, in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHGs 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. Starting in January 2011, stationary sources that are already obtaining a Clean Air Act permit

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for other pollutants must include GHGs in their permits if they emit at least 75,000 tons of these emissions a year. In July 2012, the rule expands to include all new facilities that emit at least 100,000 tons of GHGs per year.

In addition, in October 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources beginning in 2011 for emissions in 2010.

On November 30, 2010, the EPA published a final rule expanding the existing GHGs monitoring and reporting rule to include certain large onshore and offshore oil and gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHGs emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Several of the EPA’s GHGs rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Even if such legislation is not adopted at the national level, almost one-half of the states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of GHGs emission inventories and/or regional GHGs cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHGs emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHGs emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our 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, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Spills and discharges

Our operations are subject to Oklahoma Corporation Commission requirements, including regulations for responding to and remediating spills. Furthermore, our facilities maintain Spill, Prevention, Control and Countermeasure (“SPCC”) Plans that set out measures for oil spill prevention, preparedness, and responses in accordance with the Federal Water Pollution Control Act, as amended, which also is known as the Clean Water Act (“CWA”).

The CWA and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the United States. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose

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administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Other laws

The Oil Pollution Act of 1990, as amended (“OPA”) establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

Employees

As of March 1, 2012, we had 11 full-time employees. None of our employees is represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Legal Proceedings

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.

New Dominion, our contract operator and affiliate, has been named as a defendant in Mattingly v. Equal Energy, which was originally filed in Creek County District Court on August 16, 2010, was subsequently removed to the United States District Court for the Northern District of Oklahoma on September 8, 2010, but was remanded to state court on August 1, 2011. The plaintiffs have asserted claims individually and on behalf of a class of royalty owners alleging that the defendants, including New Dominion, breached certain duties owed to the plaintiffs arising from oil and gas leases between the plaintiffs and the defendants by allegedly deducting post-production costs in calculating the royalties paid to the plaintiffs under those leases and failing to credit the plaintiffs for all revenues, including those attributable to the sale of natural gas, natural gas liquids, condensate and drip. The plaintiffs seek damages in excess of $10,000, punitive damages, interest, costs and attorneys’ fees.

Although we have not been made a party to this litigation, it is possible that we may be joined to the litigation as a defendant due to our acquisition of the Acquired Assets and the future calculation of royalties paid to the plaintiffs in the litigation.

We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.

Insurance Matters

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations or cash flows.

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MANAGEMENT

Set forth below is certain information regarding persons who serve as our executive officers and directors. Prior to completion of this offering, we may appoint additional persons to serve as our executive officers and directors upon completion of this offering.


Name	Age		Position
David J. Chernicky		58	Chairman of the Board and Senior Geologist
Kristian B. Kos		34	Director, President and Chief Executive Officer
Richard D. Finley		61	Chief Financial Officer and Treasurer
V. Bruce Thompson		65	General Counsel and Secretary
Carol T. Bryant		54	Senior Engineer
Kevin A. Easley		50	Director
Terry L. Toole		67	Director

David J. Chernicky – Chairman and Senior Geologist – Our chairman of the board is Mr. David J. Chernicky. Mr. Chernicky was appointed chairman of the board and senior geologist in August 2011 and has more than 31 years of experience in the oil and gas industry. On July 1, 1998, Mr. Chernicky co-founded New Dominion, an oil and gas exploration and production company based in Tulsa, Oklahoma. Mr. Chernicky beneficially owns New Dominion and Scintilla. From April 2002 until his resignation on August 1, 2011, Mr. Chernicky served as the president and manager of Scintilla and New Dominion, overseeing those companies’ operations as a whole. Mr. Chernicky currently serves on the boards of various governmental bodies, including the Grand River Dam Authority (“GRDA”) and the Oklahoma Ordinance Works Authority. Prior to founding New Dominion, Mr. Chernicky was employed in 1979 as a geologist for Marathon Oil in Casper, Wyoming and later, from 1979 until 1983 as a geologist and geophysicist for Amoco Production in Denver, Colorado. Thereafter, Mr. Chernicky worked as an independent consulting geologist until founding New Dominion, LLC. Mr. Chernicky graduated from the University of Oklahoma in 1978 with a Bachelor of Science degree in exploration geophysics. We believe Mr. Chernicky’s extensive experience in the oil and gas industry, his leadership positions at other oil and gas companies, his reservoir engineering skills and his knowledge regarding our business and operations brings important experience and leadership to our company and our board of directors.

Kristian B. Kos – President and Chief Executive Officer – Our president and chief executive officer is Mr. Kristian B. Kos. Mr. Kos was appointed president and chief executive officer and director in July 2011 and has been involved in oil and gas and energy industries since 2005. From May 2010 through July 2011, Mr. Kos provided consulting services to New Dominion. In August 2006, Mr. Kos founded Deylau, LLC, a company focused on identifying, managing and financing oil and gas production companies, and served as its manager from August 2006 to July 2011. From February 2006 to February 2007, Mr. Kos served as a Vice President at Diamondback Energy Services, where he was actively involved in identifying and executing growth strategies for that company, including acquisitions. From September 2005 to February 2006, Mr. Kos worked in a business-development role for Gulfport Energy. Prior to working in the oil and gas and energy sectors, Mr. Kos worked in the financial sector for hedge fund manager Wexford Capital LP. Mr. Kos currently serves as a director and, through Deylau, is the majority stockholder of Encompass Energy Services, Inc. Mr. Kos earned Bachelor of Arts and Master of Arts degrees in Economics and Philosophy from Trinity College, Dublin, Ireland in 1999. He also earned a Master of Philosophy degree in Economics from the University of Aix-Marseille, France in 2000. We believe Mr. Kos’s experience in the financial and oil and gas industries, his leadership positions at other oil and gas companies, and his knowledge regarding our business and operations provides important experience and leadership to our company and our board of directors.

Richard D. Finley – Chief Financial Officer and Treasurer – Our chief financial officer and treasurer is Richard D. Finley, C.P.A. Mr. Finley was named chief financial officer and treasurer in August 2011 and is a partner at Finley & Cook, PLLC, an Oklahoma certified public accounting firm. Promptly following the consummation of this offering, Mr. Finley intends to transition out of his role as a partner at Finley & Cook,

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where he has worked since 1973, overseeing tax and accounting services within various industries and business environments. Mr. Finley has extensive experience with oil and gas exploration and production clients in general matters of accounting and taxation. Mr. Finley earned a Bachelor degree in accounting from Central State University, Edmond, Oklahoma, in 1973. He has been a Certified Public Accountant since 1975 and is a member of both the Oklahoma Society of Certified Public Accountants and the American Institute of Certified Public Accountants. He is also a Certified Valuation Analyst and a member of the National Association of Certified Valuation Analysts.

V. Bruce Thompson – General Counsel and Secretary – Our general counsel and secretary is Mr. V. Bruce Thompson. Mr. Thompson was appointed general counsel and secretary in August 2011. Mr. Thompson also serves as President of The American Exploration & Production Council (AXPC), a Washington, D.C.-based trade association whose membership is composed of 31 of America’s leading independent oil and natural gas exploration and production companies, a position he has held since October 2008. From March 2007 to April 2008, Mr. Thompson served as senior vice president and general counsel of SandRidge Energy, Inc. (NYSE: SD). Additionally, from August 2003 to March 2007, Mr. Thompson served as senior counsel with Brownstein Hyatt Farber Schreck in the firm’s Washington, D.C. and Denver offices. Previously, Mr. Thompson served as senior vice president and general counsel of Forest Oil Corporation (NYSE: FST). Mr. Thompson also served as chief of staff for then Congressman, now U.S. Senator, James Inhofe. Mr. Thompson graduated from the University of Pennsylvania’s Wharton School of Business with a Bachelor of Science degree in Economics with an emphasis on corporate finance in 1969 and received his Juris Doctorate from the University of Tulsa’s College of Law in 1974.

Carol T. Bryant – Senior Engineer – Ms. Carol T. Bryant was appointed senior engineer for New Source Energy Corporation in August 2011. Prior to joining our company, Ms. Bryant was a consulting petroleum engineer for Pinnacle Energy Services from June 2008 to April 2011 where she prepared third party reserve and engineering reports for clients with assets in the Mid-Continent region. From April 2007 to May 2008, Ms. Bryant was the senior reservoir engineer for Windsor Energy Resources, LLC and Gulfport Energy/Grizzly Oil Sands, LLC, responsible for corporate reserve evaluation and database development, facilitating bank engineering reviews and investor reserve reporting. From May 2000 to April 2007, Ms. Bryant held various reservoir engineering positions with Chaparral Energy, LLC in Oklahoma City. She was the corporate reserve manager responsible for quarterly, year-end and special reporting requirements and facilitated third party and bank engineering reviews. She initiated organizational changes to meet the needs of a rapidly growing reserve base and in preparation to meet initial public offering reporting requirements and Sarbanes-Oxley compliance. As a senior reservoir engineer at Chaparral, Ms. Bryant developed geologic and reservoir simulation models to evaluate CO₂reserve potential for several Morrow CO₂ floods in the Oklahoma and Texas panhandles. Prior to that, Ms. Bryant held positions as a production and reservoir engineer with various firms including Amoco Production Company in Denver, Colorado. Ms. Bryant graduated from the University of Tulsa in 1980 with a Bachelor of Science degree in Petroleum Engineering.

Kevin A. Easley – Director – Mr. Kevin A. Easley was appointed as a director for New Source Energy Corporation in August 2011. Mr. Easley is president and chief executive officer of New Dominion, LLC. Before joining New Dominion in June 2011, he served as chief executive officer of the GRDA from March 2004 to June 2011. During that time, he led the development for the authority of power generation, lake management, and environmental policies and successfully turned the authority’s rating from near junk-bond status to an AA credit rating. In August 2005, during his term with GRDA, Mr. Easley was elected to a six-year executive committee term with the American Public Power Association. In 2005, Mr. Easley was also appointed to the corporate governance committee of the Southwest Power Pool. Prior to that, Mr. Easley served in various management roles for Samson Energy from January 1989 to February 2004, Home-Stake Oil and Gas Company from February 1982 to December 1983, and BP Amoco from January 1981 to January 1983. Mr. Easley was elected to the Oklahoma House of Representatives in November 1984, where he served for six years. Later, as an Oklahoma State senator from November 1990 to January 2003, he identified the need for and initiated the commission for electric and energy studies. His knowledge of natural gas, coal, water and wind generation

Index to Financial Statements

systems helped create legislation that ensured optimum energy levels for consumers, businesses, and business development opportunities. He authored legislation to create the Oklahoma Energy Resources Board, a state agency designed to deal with environmental clean-up of abandoned oil wells, among other issues. Mr. Easley currently serves as chairman of the Senate Energy, Environment and Communications committee, is on the board of directors of the American Public Power Association, and is an executive committee member of the United States Energy Council. Mr. Easley is a graduate of the University of Tulsa where he earned a Bachelor of Science in Business Administration with an emphasis on accounting. In 2009, he received a Master of Business Administration with honors at Oklahoma Christian University. We believe Mr. Easley’s extensive experience in the oil and gas industry as well as his experience in the energy and environmental sectors bring substantial leadership and experience to the board of directors.

Terry L. Toole – Director – Terry L. Toole, C.P.A. was appointed a director of New Source Energy Corporation in January 2012. Mr. Toole retired as a partner of Finley & Cook, PLLC, on November 1, 2010, where he had been employed since 1976. He has significant accounting experience with companies in the oil and natural gas industry, including several publicly traded exploration and production companies and drilling funds. At the time of Mr. Toole’s retirement from Finley & Cook, he chaired the firm’s audit and oil and gas accounting departments. Mr. Toole received a Bachelor of Science degree in Business Administration (concentration in Economics) from Fort Hays State University in Hays, Kansas in 1966 and a Master’s degree in Business Administration (concentration in Accounting) in 1968 from West Texas A&M University in Canyon, Texas. He has been a Certified Public Accountant since 1970 and is a member of both the Oklahoma Society of Certified Public Accountants and the American Institute of Certified Public Accountants. We believe Mr. Toole’s expertise as a Certified Public Accountant and his extensive knowledge relating to auditing and accounting matters pertinent to the oil and natural gas industry provide important experience to our board of directors.

Board of Directors

Our board of directors currently consists of four members, including (i) our president and chief executive officer, (ii) our senior geologist, (iii) the president and chief executive officer of New Dominion, our contract operator, and (iv) one independent director. Each of our current directors has prior industry experience. Only one of our current directors qualifies as independent under the standards of the NYSE.

We expect that our board will review the independence of our directors using the independence standards of the NYSE, and we expect that our board of directors will consist of seven directors within one year after the completion of this offering, four of whom will be independent.

Because of the expected continued beneficial ownership of Mr. Chernicky after this offering, we will be a “controlled company” as that term is defined in Section 303A of the NYSE Listed Company Manual. Under the NYSE’s rules, a “controlled company” may elect not to comply with certain NYSE corporate governance requirements, including (i) the requirement that a majority of our board of directors consist of independent directors, (ii) the requirement that our nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing that committee’s purpose and responsibilities, and (iii) the requirement that our compensation committee be composed entirely of independent directors with a written charter addressing that committee’s purpose and responsibilities. While these requirements will not apply to us as long as we remain a “controlled company,” we expect that our board of directors will consist of a majority of independent directors and that our nominating and corporate governance and compensation committees will consist entirely of independent directors within one year following the completion of this offering. Our nominating and corporate governance and compensations committees each will have a written charter addressing such committee’s purpose and responsibilities.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance our board’s ability to manage and direct the affairs and business of the company, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Index to Financial Statements

Committees of the Board of Directors

We expect that our board of directors will appoint an audit committee, a compensation committee, and a nominating and corporate governance committee prior to the consummation of this offering and that our board of directors additionally will appoint such other committees as it determines to be necessary from time to time. The standing committees of the board of directors will have the responsibilities described below.

Audit Committee

The audit committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements.

Our audit committee currently consists of Mr. Toole, whom our board of directors has determined satisfies the independence requirements under the NYSE listing standards and Rule 10A-3(b)(1) of the Exchange Act. Our board of directors has determined that Mr. Toole is financially literate under the applicable rules and regulations of the SEC and NYSE and qualifies as our audit committee financial expert within the meaning of SEC regulations. Within 90 days following the completion of this offering, we expect that we will have appointed two additional directors to our audit committee and that all of the members of our audit committee will be independent under the NYSE listing standards and SEC regulations. Prior to the consummation of this offering, we will adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE and market standards.

Compensation Committee

The compensation committee will establish salaries, incentives and other forms of compensation for our officers and other employees. Our compensation committee also will administer our incentive compensation and benefit plans. We will adopt a compensation committee charter defining this committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Nominating and Corporate Governance Committee

The nominating and corporate governance committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. We will adopt a nominating and corporate governance committee charter defining this committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Compensation Committee Interlocks and Insider Participation

Because we are a newly formed entity, we have not yet established our compensation committee. We expect that our board of directors and compensation committee will consist only of directors who have never been an employee of our company and are not executive officers of another company for which any of our executive officers serves on the board of directors or compensation committee, except that Mr. Chernicky, our senior geologist, may be deemed to serve in a capacity similar to that of the compensation committee of New Dominion, of which Mr. Easley is an executive officer. For a description of transactions between us and New Dominion, see “Certain Relationships and Related Party Transactions.”

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors intends to adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. We expect that any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors intends to adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

Index to Financial Statements

EXECUTIVE COMPENSATION AND OTHER INFORMATION

Compensation Discussion and Analysis

The following contains a description of the executive compensation programs and objectives that we plan to put into place, based upon the review and determinations made by our board of directors and subject to the further review and approval of the compensation committee of our board of directors.

Compensation of Named Executive Officers

Our named executive officers at present are Kristian B. Kos, our president and chief executive officer (and principal executive officer), Richard D. Finley, our chief financial officer and treasurer (and principal financial and accounting officer), David J. Chernicky, our senior geologist and chairman, V. Bruce Thompson, our general counsel and secretary, and Carol T. Bryant, our senior engineer. We have entered into employment agreements with Messrs. Kos, Finley, Chernicky and Thompson, and we anticipate that we may enter into employment agreements with Ms. Bryant and other key executives from time to time.

Under Mr. Kos’ employment agreement, Mr. Kos’ annual base salary is $360,000, and he also is eligible for cash bonuses, equity compensation and other compensation as determined by the compensation committee of our board of directors from time to time. Mr. Kos also received a grant of 2,300,000 shares of our common stock, of which 700,000 shares are scheduled to vest on the first anniversary of the date of Mr. Kos’ employment, 700,000 shares are scheduled to vest on the second anniversary of the date of Mr. Kos’ employment, and the remaining 900,000 shares will vest upon the consummation of this offering.

At the option of Mr. Kos, we may withhold shares of his common stock to satisfy withholding tax obligations 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 $3.0 million of the proceeds of this offering may be used to fund such withholding tax payments.

Under Mr. Chernicky’s employment agreement, Mr. Chernicky’s annual base salary is $360,000, and he also is eligible for cash bonuses, equity compensation and other compensation as determined by the compensation committee of our board of directors from time to time. Mr. Chernicky received a grant of 200,000 shares of our common stock, of which 100,000 shares will vest upon the consummation of this offering, and the remaining 100,000 shares are scheduled to vest on the first anniversary of the date of Mr. Chernicky’s employment.

At the option of Mr. Chernicky, we may withhold shares of his common stock to satisfy withholding tax obligations 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 $0.3 million of the proceeds of this offering may be used to fund such withholding tax payments.

The employment terms of Messrs. Finley and Thompson are identical in all material respects. Their respective annual base salaries are $192,000, and they are eligible for cash bonuses, equity compensation and other compensation determined from time to time by our compensation committee. Each of Messrs. Finley and Thompson received a grant of 200,000 shares of our common stock, of which 100,000 shares will vest upon the consummation of this offering, and the remaining 100,000 shares are scheduled to vest on the first anniversary of the respective date of their employment.

At the option of Messrs. Finley and Thompson, we may withhold shares of their common stock to satisfy withholding tax obligations 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 $0.7 million of the proceeds of this offering may be used to fund such withholding tax payments.

Index to Financial Statements

Ms. Bryant’s annual base salary is $180,000. The other terms of Ms. Bryant’s employment have not been established definitively.

We established the initial base salaries for our named executive officers based on our subjective evaluations of the services to be provided by them and their expertise and abilities as they relate to our overall corporate strategy. The compensation of Messrs. Kos and Chernicky, in particular, reflects their substantial actual and expected efforts and expertise on behalf of our company in structuring the acquisition of our properties and in developing and operating those properties moving forward. We anticipate that the compensation committee of our board of directors will determine the compensation for other key employees and the ongoing compensation of our named executive officers as appropriate and pursuant to our overall compensation goals and objectives described below.

Compensation Program Objectives

We anticipate that our compensation program will have the following long-term goals and objectives:

•

aligning the interests of our executive officers with the short- and long-term interests of our stockholders;

•

linking executive compensation to individual performance and overall business performance;

•

leveraging individual performance through an emphasis on incentive compensation; and

•

compensating our executive officers at a level and in a manner such that we can continue to attract and retain capable and experienced individuals.

Because we are a new company and have recently commenced operations, we are in the process of developing our compensation policies and anticipate that this will be an ongoing process as our company develops.

As an independent energy company engaged in the development and production of hydrocarbons from conventional resource plays, we have established our initial compensation packages based on our review of current compensation practices among similar oil and natural gas exploration and production companies. In general, our review focused on a mix of smaller to medium-sized public oil and natural gas exploration and production companies, although some of these companies are larger, and all of them are more established, than we are. We focused on the following companies as our “peer group” for purposes of comparing executive compensation:

Callon Petroleum Company

Crimson Exploration Inc.

Double Eagle Petroleum Co.

GeoResources, Inc.

Rex Energy Corporation

Warren Resources, Inc.

Each company’s publicly disclosed information was compiled to provide data on executive compensation, including base pay, other cash compensation and equity-based compensation. With the exception of the initial equity grant to Mr. Kos, which is very high relative to our peers owing to his critical role in positioning our company for this offering, we believe that our initial executive compensation packages are approximately in the middle range of the compensation of this group. This reflects our intent to formulate executive compensation packages that are both representative of industry practices and are sufficient to attract and retain capable and experienced people.

We believe the companies included in our peer group as noted above are a representative list of comparison companies currently, but we expect this list to change as our company matures and as the oil and natural gas industry changes. As our business develops, we will select comparison companies that are comparable to us in terms of size and growth profile and that potentially compete with us for executive talent at the time of the

Index to Financial Statements

comparison. In addition, the comparable companies will also develop over time, which also will necessitate changes in the composition of the comparison group. Future comparison groups may include some, none or all of the companies in the current group, in addition to new companies that may be added. We anticipate that we may engage external compensation consultants in the future to help us determine appropriate compensation packages for our executives, although no such consultants have been engaged to date.

We intend to design our compensation policies and programs to make us competitive with similarly-sized oil and natural gas exploration and production companies, to recognize and reward executive performance consistent with the success of our business, and to attract and retain capable and experienced people. Our compensation committee’s role and philosophy will be to ensure that our compensation goals and objectives, as applied to the actual compensation paid to our executive officers, are aligned with our overall business objectives and with stockholder interests.

In addition to industry comparables, our compensation committee may consider a variety of factors when determining compensation policies and programs and individual compensation levels, including our stockholders’ interests, our overall financial and operating performance, and the compensation committee’s assessment of each executive’s individual performance and contribution toward meeting our corporate objectives. As we grow, we will place increasing importance on the incentive-based component of compensation because we believe that a significant portion of an executive’s compensation should depend upon our overall corporate performance, including common stock share price performance.

Anticipated Elements of Our Compensation Program

The total compensation plan for executive officers likely will be comprised of three components: base salary, annual performance bonuses and equity-based compensation, including grants of restricted stock under our long-term incentive plan. There is currently no policy or target regarding a percentage allocation between cash and non-cash elements of our proposed compensation program or, within cash compensation, between the relative weight of base salary and targeted performance bonuses. Any such allocations will be determined by the compensation committee on an individual basis and may be influenced by such factors as level of responsibility, peer group analysis and individual executive performance.

Base Salary. We believe base salary is an important tool for attracting and retaining qualified personnel. As a general rule for establishing base salaries, our compensation committee will review competitive market data for each executive position and determine placement at an appropriate level in a range. See “—Compensation Program Objectives” above, for a discussion of our recent determinations concerning comparison companies. The compensation range for executives will likely be reviewed on an annual basis by our compensation committee to reflect external factors, such as inflation. Additionally, our compensation committee’s ability to decrease the base salary of any of our executive officers may be restricted by the terms of a written employment agreement between us and such executive officer.

Performance Bonuses. We believe annual performance bonuses are valuable as a method to reward our management team when they are successful in reaching our previously established goals and to incentivize our management team to achieve these goals. Our executive officers may earn annual incentive bonuses based on achievement of individual and corporate performance goals. Our compensation committee will determine the elements of individual executive performance goals, and the weight to be given to each, for our president and chief executive officer and our chairman and senior geologist. For all other executive officers, our president and chief executive officer will determine the elements of individual executive performance goals and the weight to be given to each, subject to the review and approval of our compensation committee.

Applicable performance goals will be based upon such factors as our financial, production and other operational targets, our share price performance, and changes in our financial position.

Index to Financial Statements

Equity-Based Compensation. The third element in our total compensation plan will be equity-based compensation, which we expect primarily will be comprised of grants of restricted common stock. This element is intended to emphasize our commitment to our growth and the enhancement of stockholder value through, for example, improvements in operating results, resource base and share price increments, by linking the interests of our stockholders with the economic interests of our management. Since we are a newly public company, we do not currently maintain a formal policy regarding the timing of equity grants in connection with the release of material, non-public information. We may develop such a policy in the future.

Our board of directors has approved a Long Term Incentive Plan, or LTIP, to take effect upon or shortly after consummation of this offering. The purpose of our LTIP will be to attract and retain the best available personnel for positions of substantial responsibility, to provide additional incentives to our employees, directors and consultants, and to align economically the interests of our stockholders with the interests of our management team. Our LTIP provides for grants of incentive stock options qualified as such under U.S. federal income tax laws, stock options that do not qualify as incentive stock options, stock appreciation rights (“SARs”), restricted stock awards, restricted stock units, performance awards and other awards, including common stock awarded as a bonus.

We believe long-term incentive-based equity compensation is an important component of our overall compensation program because it:

•

rewards the achievement of our long-term goals;

•

aligns our executives’ interests with the long-term interests of our stockholders;

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encourages executive retention; and

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conserves our cash resources.

Our compensation committee will have the authority to award incentive compensation under our LTIP to our named executive officers and others in such amounts and on such terms as our compensation committee determines appropriate in its discretion. In determining such awards, our compensation committee may review analysis provided by compensation consultants it determines to engage to determine the appropriate amount of equity to grant to our executive officers based on market data, while also taking into consideration our performance, individual performance and retention concerns. Our named executive officers and other employees will be entitled to participate in our LTIP subject to certain restrictions.

We do not expect that our LTIP will be subject to the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). For a limited period of time following this offering, we anticipate that grants of options, SARs and restricted stock made pursuant to our LTIP will qualify for an exception to the deductibility limitations imposed by Section 162(m) of the Internal Revenue Code of 1986, as amended, assuming that certain requirements are met. We expect that during that limited period of time, awards under our LTIP will be exempt from the limitations on the deductibility of compensation that exceeds $1.0 million. See “—Accounting and Tax Considerations” below.

Our LTIP has the following general features:

•

eligibility for any individual who provides services to us, including non-employee directors and consultants, subject to any limitations provided for by our compensation committee;

•

administration by our compensation committee, except as otherwise provided for by the terms of our LTIP;

•

stock option grants to be issued with an exercise price not less than the fair market value per share as of the date of grant;

•

SARs, each representing the right to receive an amount, which may be settled in cash or shares of our common stock, equal to the excess of the fair market value of one share of our common stock on the

Index to Financial Statements

date of exercise over the grant price of the SAR (which grant price will not be less than the fair market value per share as of the date of grant);

•

restricted stock awards granting shares of common stock subject to a risk of forfeiture, restrictions on transferability and any other restrictions imposed by the compensation committee in its discretion;

•

restricted stock units consisting of rights to receive common stock, cash or a combination of both at the end of a specified period;

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authority granted to the compensation committee to designate certain awards under our LTIP as “performance awards,” the grant, exercise or settlement of which is subject to the attainment of one or more performance goals; and

•

other awards related to common stock, subject to applicable legal limitations and the terms of our LTIP and its purposes.

Other Employee Benefits. We expect that our named executive officers will be eligible for the same health, welfare and other employee benefits available to our employees generally, including medical and dental insurance, short and long-term disability insurance and our qualified retirement plans. We also plan to sponsor a tax-qualified retirement plan in accordance with the provisions of Section 401(a) and 401(k) of the Code.

Perquisites and Other Personal Benefits

We do not expect that our executives will be entitled to significant perquisites or other personal benefits not generally offered to our other employees.

Stock Ownership Guidelines

Stock ownership guidelines have not been implemented for our named executive officers or directors. We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines in the future.

Advisory Stockholder Votes on Executive Compensation

Because we are a new company, we have not yet submitted our executive compensation practices to our stockholders for an advisory vote. We will do so at our first annual meeting of stockholders, and we expect the compensation committee of our board of directors will consider the results of any such advisory vote by our stockholders on our executive compensation programs and practices in making future decisions regarding our compensation and compensation philosophies.

Accounting and Tax Considerations

Section 162(m) of the Code. Generally, Section 162(m) of the Code disallows a tax deduction to any publicly-held corporation for individual compensation in excess of $1.0 million paid in any taxable year to any of its chief executive officer or three other highest paid named executive officers, other than its chief financial officer, unless the compensation meets the requirements for the performance-based compensation exception or the compensation qualifies for the limited transitional exception for new public companies described below. As we are not currently publicly traded, we have not previously taken the deductibility limit imposed by Section 162(m) of the Code into consideration in setting compensation.

Certain exceptions to the deductibility limitation apply for a limited period of time in the case of companies that become publicly-traded through an initial public offering, assuming certain conditions are satisfied. We expect that our employment agreements and options, SARs and restricted stock granted pursuant to the LTIP will fit within that exception; however, we reserve the right to use our judgment to authorize compensation payments that are not exempt from the deduction limitation in Section 162(m) of the Code when we believe that such payments are appropriate and in the best interest of our stockholders, after taking into consideration changing business conditions or the executive’s individual performance and/or changes in specific job duties and responsibilities.

Index to Financial Statements

Section 409A of the Code. Section 409A of the Code imposes restrictions on non qualified deferred compensation plan. Failure to satisfy these requirements of Section 409A of the Code can expose employees and other service providers to immediate taxation, a 20% penalty tax and interest on their vested compensation under such plans. Accordingly, as a general matter, it is our intention to design and administer our compensation and benefits plans and arrangements for all of our employees and other service providers, including our named executive officers, so that they either are exempt from, or satisfy the requirements of, Section 409A of the Code.

Section 280G of the Code. Section 280G of the Code disallows a tax deduction with respect to excess parachute payments to certain officers, stockholders or other highly compensated individuals providing personal services to a company that undergoes a change in control. In addition, Section 4999 of the Code imposes a 20% excise tax on the individual with respect to the excess parachute payment. In approving the compensation arrangements for our named executive officers in the future, our compensation committee will consider all elements of the cost to us of providing such compensation, including the potential impact of Section 280G of the Code. However, our compensation committee may, in its judgment, authorize compensation arrangements that could give rise to loss of deductibility under Section 280G of the Code and the imposition of excise taxes under Section 4999 of the Code when it believes that such arrangements are appropriate to attract and retain executive talent.

Our employment agreements with our officers, including our named executive officers, do not provide a “gross-up” or other reimbursement payment for any tax liability that such officer might owe as a result of the application of Sections 280G, 4999, or 409A of the Code or other applicable tax provision, and we have not agreed and are not otherwise obligated to provide any named executive officers with such a “gross-up” or other reimbursement.

Accounting Standards. Financial Accounting Standards Board (FASB) Accounting Standards Codification, Topic 718, “Compensation – Stock Compensation” (ASC Topic 718) requires us to recognize an expense for the fair value of equity-based compensation awards. Grants of restricted stock, stock options and other equity-based awards are accounted for under ASC Topic 718. Our compensation committee will consider the accounting implications of significant compensation decisions, especially in connection with decisions that relate to our equity incentive award plans and programs. As accounting standards change, we may revise certain programs to appropriately align accounting expenses of our equity awards with our overall executive compensation philosophy and objectives.

Compensation of Named Executive Officers During 2011 from Inception

Summary Compensation Table


Name and Principal Position	Year		Salary ($)				Bonus ($)⁽¹⁾		Stock Awards ($)⁽²⁾		Total ($)
Name and Principal Position	Year		Inception through December 31, 2011		Annualized Rate		Bonus ($)⁽¹⁾		Stock Awards ($)⁽²⁾		Total ($)
Kristian B. Kos Chief Executive Officer and President		2011		165,000		360,000		—		22,885,000		23,050,000
Richard D. Finley Chief Financial Officer		2011		88,000		192,000		—		1,990,000		2,078,000
David J. Chernicky Senior Geologist		2011		165,000		360,000		—		1,990,000		2,155,000
V. Bruce Thompson General Counsel		2011		88,000		192,000		—		1,990,000		2,078,000
Carol T. Bryant Senior Engineer		2011		60,000		180,000		9,000		—		69,000

(1)	The amount of bonus earned for 2011 is not yet calculable, except as set forth for Ms. Bryant. We expect to determine the amounts of bonuses for our other named executive officers, if any, subsequent to the first quarter of 2012.

(2)	The amount set forth for each stock award is the aggregate grant date fair value of such award, computed in accordance with FASB ASC Topic 718.

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Index to Financial Statements

Equity Compensation Plan Information

The following table represents the securities authorized for issuance under our equity compensation plans as of December 31, 2011.


Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders		—		—		3,600,000	⁽¹⁾
Equity compensation plans not approved by security holders		—		—		—

(1)	Represents the number of shares of our common stock available for issuance under our LTIP as of the date of this prospectus.

Grants of Plan-Based Awards


Name	Grant Date		All Other Stock Awards: Number of Shares of Stock (#)⁽¹⁾		Grant Date Fair Value of Stock Awards ($)⁽²⁾
Kristian B. Kos		August 18, 2011		2,300,000	$	22,885,000
Richard D. Finley		August 18, 2011		200,000	$	1,990,000
David J. Chernicky		August 18, 2011		200,000	$	1,990,000
V. Bruce Thompson		August 18, 2011		200,000	$	1,990,000

(1)

Of the 2,300,000 shares of restricted common stock granted to Mr. Kos, 900,000 shares will vest upon completion of this offering, and the remaining 1,400,000 shares will vest in equal installments of 700,000 shares upon the first and second anniversary of the date of grant provided that Mr. Kos remains employed by us on the applicable vesting dates, subject to limited exceptions. Of the 200,000 shares of restricted common stock granted to each of Messrs. Finley, Chernicky and Thompson, 100,000 shares will vest upon completion of this offering, and the remaining 100,000 shares will vest upon the first anniversary of the date of grant provided that each executive remains employed on each of the applicable vesting dates, subject to limited exceptions.

(2)	Amounts reflect the full grant date fair value of restricted stock awards granted during 2011, computed in accordance with ASC Topic 718.

Narrative Explanation of Summary Compensation and Grants of Plan-Based Awards Tables

Because we did not yet exist as a company in 2010, we paid no compensation to our named executive officers during the years ended December 31, 2009 and 2010. We have elected to set forth the compensation actually paid to our named executive officers from the inception of our company on July 12, 2011 through December 31, 2011, as well as the annual rate of compensation payable pursuant to the current terms of employment of each of our named executive officers. See “Summary Compensation Table,” above. We expect to implement additional executive compensation programs for our named executive officers as described above under “Compensation Discussion and Analysis,” possibly including additional programs with respect to calendar year 2012.

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Index to Financial Statements

Outstanding Equity Awards as of December 31, 2011


Name	Stock Awards
Name	Number of Shares of Stock That Have Not Vested (#)⁽¹⁾		Market Value of Shares of Stock That Have Not Vested ($)⁽²⁾
Kristian B. Kos		2,300,000	$	22,885,000
Richard D. Finley		200,000	$	1,990,000
David J. Chernicky		200,000	$	1,990,000
V. Bruce Thompson		200,000	$	1,990,000

(1)

The 2,300,000 shares of unvested restricted stock held by Mr. Kos will vest in installments of 700,000 shares on August 18, 2012, and August 18, 2013, and an installment of 900,000 shares on the date of completion of this offering, provided that Mr. Kos remains employed by us on the applicable vesting dates subject to limited exceptions. The 200,000 shares of unvested restricted common stock held by each of Messrs. Finley, Chernicky and Thompson will vest in installments of 100,000 shares on August 18, 2012, and installments of 100,000 shares on the date of completion of this offering, provided that each executive remains employed on each of the applicable vesting dates subject to limited exceptions.

(2)	Represents the market value of our restricted common stock as of December 31, 2011, based on an assumed value of $9.95 per share, equivalent to the grant date fair value of such shares on August 18, 2011 computed in accordance with FASB ASC Topic 718.

Potential Payments upon Termination or Change in Control

The table below discloses a hypothetical amount of compensation and/or benefits due to the named executive officers in the event of their termination of employment. None of the named executive officers is entitled to any cash severance payment following termination for any reason at this time. The amounts disclosed reflect the cash value of shares of restricted stock vested at the time of termination and assume such termination was effective as of December 31, 2011. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated. Therefore, such amounts and disclosures should be considered “forward looking statements.” We do not presently have in place any arrangements that would require payments to our named executive officers upon a change in control, although the compensation committee of our board of directors may elect to implement such arrangements in the future.

Name

Payment

Reason for Termination

For Cause or Resignation

Without Cause or upon
Death or Disability

Kristian B. Kos

Stock Award

⁽¹⁾

—

22,885,000

Richard D. Finley

Stock Award

⁽¹⁾

—

1,990,000

David J. Chernicky

Stock Award

⁽¹⁾

—

1,990,000

V. Bruce Thompson

Stock Award

⁽¹⁾

—

1,990,000

(1)

Upon termination of employment for cause or upon the named executive officer’s resignation, all unvested shares of restricted stock are forfeited. Upon termination by us without cause, death or permanent disability, all unvested shares of restricted stock are automatically vested. The value of such unvested shares that would vest upon such event has been computed using the market value of our restricted common stock as of December 31, 2011, based on an assumed value of $9.95 per share, equivalent to the grant date fair value of such shares on August 18, 2011 computed in accordance with FASB ASC Topic 718.

Pension Benefits

We do not yet have any plan that provides for retirement benefits. We expect to sponsor a qualified tax-deferred savings plan in accordance with the provisions of Section 401(k) of the Internal Revenue Code of 1986, as amended.

Non-Qualified Deferred Compensation

We do not presently have any plan that provides for the deferral of compensation on a basis that is not tax qualified.

102

Index to Financial Statements

Transactions with Affiliates of Our Named Executive Officers

In connection with the transactions pursuant to which we acquired our initial assets, we paid to Scintilla, an entity controlled by David J. Chernicky, our chairman and senior geologist, a total of $60.0 million in cash and issued an aggregate of 20.0 million shares of our common stock (which shares Scintilla promptly transferred to the David J. Chernicky Trust) in exchange for the Scintilla Assets. In addition, as a part of such transactions, we also issued 360,000 shares of our common stock to Deylau, LLC an entity owned and managed by Kristian B. Kos, our president and chief executive officer and one of our directors, in exchange for the portion of the Other Contributed Assets contributed to us by that entity. 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 also acquired rights to 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, in exchange for reimbursing New Dominion for our proportionate share of the costs of this leasehold, plus a fee equal to 15% of such costs, although we have not yet been billed for or paid any of these expenses. These transactions were not intended to compensate Messrs. Chernicky or Kos for their services as named executive officers but rather were part of the broader transactions pursuant to which we acquired the Acquired Assets and our rights to the Golden Lane Extension. In addition, on July 15, 2011, we received an unsecured loan in the amount of $0.4 million, bearing no interest and due on demand from Mr. Chernicky, which was repaid in full on August 18, 2011. See “Certain Relationships and Related Party Transactions” in this prospectus.

Compensation of Non-Employee Directors

We do not presently pay cash compensation to our non-employee directors for their services as directors or members of committees of the board of directors. Following the consummation of this offering, we expect to implement an annual compensation package for our initial non-employee directors valued at approximately $100,000, of which approximately 25% would be paid in the form of an annual cash retainer and the remaining 75% would be paid in a grant of restricted common stock. Of the grant of restricted stock, we currently expect that 40% of the shares made subject to such grant would vest immediately, with the remaining 60% of such shares vesting in three equal installments on the first, second and third anniversaries of the date of grant.

We have reimbursed and will continue to reimburse our non-employee directors for their travel, lodging and other reasonable expenses incurred in attending meetings of our board of directors and committees of the board of directors.

Executive Compensation Risk

We have determined that risks arising from our compensation policies and practices are not reasonably likely to have a material adverse effect on us. We do not believe that our current or proposed compensation policies and practices encourage excessive or unnecessary risk-taking.

Indemnification

Our bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. After completion of this offering, we will evaluate our existing director and officer liability insurance coverage and make such adjustments as we deem appropriate. We believe that the limitation of liability provision in our certificate of incorporation and our indemnity obligations will facilitate our ability to continue to attract and retain qualified individuals to serve as our directors and officers.

103

Index to Financial Statements

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Related Party Transactions

Our acquisition of the Acquired Assets and interests in the Golden Lane Extension involved various related parties. In negotiating the agreements entered into in connection with these transactions, we did not have any independent directors acting for us; our directors at the time were directly or indirectly related to one or more of the contributing parties. As such, we did not have an audit committee comprised solely of independent directors available to review all of the material terms of these transactions and approve them pursuant to the related party transactions policy that we expect to adopt in connection with the completion of this offering, as described below in “—Procedures for Review and Approval of Related Party Transactions.” However, based upon due diligence conducted by us and our advisors and the information provided to us (including financial information, historical production information, and various projections), our board of directors has concluded that the terms by which we acquired the Acquired Assets and interests in the Golden Lane Extension were fair to us and our stockholders, were in our best interests and were no less favorable than those we would have received from unaffiliated third parties in similar circumstances. The following describes our transactions and relationships with related parties:

Scintilla, LLC – Scintilla, LLC is an Oklahoma limited liability company that contributed the Golden Lane Assets and approximately 83% of the Luther Assets, which collectively comprise a significant majority of the Acquired Assets. Scintilla is owned and controlled by the David J. Chernicky Trust, of which Mr. Chernicky, our chairman, is trustee and current beneficiary. Scintilla owned a portion of the Acquired Assets from 2002 until they were conveyed to us in exchange for 20.0 million shares of our common stock and $60.0 million in cash. For a discussion regarding how we determined the value of the consideration we delivered to Scintilla for these assets, see “Business—Material Definitive Agreements—Contribution Agreements and Related Transactions.” As part of our growth strategy, and pursuant to our right of first refusal with Scintilla, we will likely attempt to acquire further oil and natural gas assets and properties from Scintilla. In connection with the interests we acquired in the Golden Lane Extension, we expect that we will enter into joint operating agreements on terms substantially similar to the Luther JOA to which Scintilla and New Dominion will be parties.

Scintilla, its affiliates, and certain employees of its affiliates retained various interests in oil and natural gas properties in the Hunton formation. Additionally, Scintilla retained its interests in formations above and below the Hunton formation, including but not limited to the Cleveland, Red Fork, Caney, Mississipian, and Arbuckle formations.

New Dominion, LLC – New Dominion, LLC is an Oklahoma limited liability company that serves as the operator for various oil and natural gas interests in east-central Oklahoma, including the Acquired Assets. New Dominion is owned and controlled by our chairman David J. Chernicky. Kristian B. Kos (our president, chief executive officer and a director) served as a consultant for New Dominion from May 2010 through July 2011 and received compensation of $20,000 per month from New Dominion for his services rendered.

New Dominion is expected to continue to operate the Acquired Assets, and as our contract operator, we expect it and its principals will further explore and identify oil and natural gas projects in which we may exercise our right to participate and/or seek to acquire. We have entered into an agreement with New Dominion and Scintilla giving us a 25-year right of first refusal to acquire up to 90% of New Dominion and Scintilla’s combined ownership interest in oil and gas projects determined to have proved reserves. Under this agreement, we will negotiate the price we will pay to New Dominion and Scintilla for any such interest we elect to acquire. If we are unable to agree on a price, the matter will be referred to an independent appraiser, whose determination of the fair value of the subject properties will be binding on New Dominion, Scintilla and us.

104

Index to Financial Statements

Agreement. We will reimburse New Dominion for our proportionate share of the costs of this leasehold, plus a fee equal to 15% of such costs, as and when billed for it by New Dominion, which we expect to occur as part of the funding of drilling and development costs on these individual properties. We have not yet been billed for or paid any of these expenses, but our estimated obligation with respect to acreage currently held by New Dominion in the Golden Lane Extension is approximately $0.7 million, which is reflected in the $3.4 million acreage cost liability we have recorded as of December 31, 2011. 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.

Pursuant to both the Golden Lane Participation Agreement and the Luther JOA, our ownership of the Acquired Assets entitles us to access our contract operator’s facilities used in connection with operating the assets, including all related infrastructure. We will have access to this infrastructure on the same terms and conditions as the other working interest holders; however, we believe that these terms and conditions are favorable to us when compared to general market conditions and are an integral part of our business plan, since this relationship will help us keep our operating costs low. The Golden Lane Participation Agreement and the Luther JOA require us to contribute capital for drilling and to pay additional expenses. We expect that we will enter into joint operating agreements with Scintilla and New Dominion relating to the development of the properties within the Golden Lane Extension on terms substantially similar to our Luther JOA. For information relating to New Dominion’s compensation as our contract operator, our obligations to pay our share of expenses associated with the operation of the Acquired Assets and the Golden Lane Extension and other terms of our agreements with New Dominion, see “Business—Material Definitive Agreements—Golden Lane Participation Agreement and Luther JOA.”

Deylau, LLC – Deylau, LLC is owned by our president, chief executive officer and one of our directors, Kristian B. Kos. Deylau was a party to a contribution agreement and with us, by which it contributed a 3% working interest in the Luther field, corresponding to approximately 5% of the Luther Assets, to us in exchange for 360,000 shares of our common stock. For a discussion regarding how we determined the number of shares of our common stock to issue to Deylau for these assets, see “Business—Material Definitive Agreements—Contribution Agreements and Related Transactions.” Deylau acquired this working interest in 2010 for approximately $0.6 million, representing Deylau’s proportionate share of the costs incurred under the joint operating agreement then in effect for the Luther field.

Other Related Parties – In performing its obligations, our contract operator utilizes certain service providers to perform work associated with the operation and maintenance of oil and natural gas wells and related infrastructure that we access. Certain affiliates of our contract operator may have interests in certain of these service providers. However, none of these service providers provide services to our contract operator on an exclusive basis, and our contract operator believes that it obtains services from these vendors at commercially reasonable rates. Furthermore, the Golden Lane Participation Agreement and the Luther JOA both require our contract operator to obtain services from any related or affiliated service providers only if they are provided on competitive terms.

Registration Rights Agreement – On August 12, 2011, we entered into a Registration Rights Agreement with the contributing parties and the David J. Chernicky Trust, as the successor in interest of Scintilla. Subject to certain conditions, the Registration Rights Agreement requires us, at our expense, to use our reasonable efforts to register the resale of the shares of common stock issued to the contributing parties under the Contribution Agreements upon demand of one or more of the contributing parties no earlier than six months from the date of the Registration Rights Agreement, and no more than twice in total. We are also required to register these shares of common stock for resale in any registration statement we file on or after six months from the date of the Registration Rights Agreement. However, we are not obligated to take any action to register shares pursuant to the Registration Rights Agreement during the period starting with the date 60 days prior to our estimated date of filing, and ending on the date six months immediately following the effective date of, a registration statement relating to our securities as long as we are employing all reasonable efforts in good faith to cause such

105

Index to Financial Statements

registration statement to become effective. Certain of the contributing parties and the David J. Chernicky Trust 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.”

Finley & Cook, PLLC – We engaged Finley & Cook, PLLC to provide various accounting services to us during the year ended December 31, 2011. Although he intends to transition out of his position as a member of Finley & Cook promptly following the consummation of this offering, Richard Finley, our Chief Financial Officer, is currently an equity member of Finley & Cook, holding a 31.5% ownership interest. We paid Finley & Cook approximately $126,000 in fees for accounting services during the year ended December 31, 2011, of which Mr. Finley’s share based on his ownership interest is approximately $40,000.

Private Placement – 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, in which we received proceeds of approximately $1.6 million. Certain of our officers, directors and other related parties purchased securities in this private placement.

Promoters – Because of their positions and involvement in our business organization and development, David J. Chernicky, our chairman and senior geologist, and Kristian B. Kos, our president, chief executive officer and a director, may be considered “promoters,” as defined in Rule 405 of the rules and regulations of the SEC. In connection with their employment with the company, Mr. Chernicky and Mr. Kos received grants of restricted stock and will receive additional compensation from the company. See “Executive Compensation and Other Information—Compensation Discussion and Analysis.” In addition, see above under “—Scintilla, LLC,” “—New Dominion, LLC” and “—Deylau, LLC,” for a discussion of the consideration received by such entities in exchange for the Acquired Assets. Such consideration may be attributable to Mr. Chernicky or Mr. Kos due to their respective ownership of these entities. On July 15, 2011, we also received an unsecured, non interest bearing loan in the amount of $0.4 million from Mr. Chernicky, which was paid by us on August 18, 2011.

Procedures for Review and Approval of Related Party Transactions

We use the term “related party transaction” to refer to a transaction, arrangement or relationship in which we were, are or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. We use the term “related person” to refer to:

•

any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or director nominees;

•

any person who is known by us to be the beneficial owner of more than 5.0% of our common stock;

•

any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, director nominee, executive officer or a beneficial owner of more than 5.0% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, director nominee, executive officer or beneficial owner of more than 5.0% of our common stock; and

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