Index to Financial Statements


Delaware	1311	26-2508194
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

1875 Lawrence Street, Suite 200

Denver, Colorado 80202

(720) 420-3200

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

Joseph N. Jaggers

President and Chief Executive Officer

1875 Lawrence Street, Suite 200

Denver, Colorado 80202

(720) 420-3200

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

Copies to:

Jeffery K. Malonson

T. Mark Kelly

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002

(713) 758-2222

J. Michael Chambers

Keith Benson

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

Approximate date of commencement of proposed sale to the public: As soon as practicable after 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):

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.

The information in this prospectus is not complete and may be changed. We and the selling stockholders 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 and the selling stockholders are not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED JUNE 15, 2012

LOGO

Ute Energy Corporation

Common Stock

We are selling shares of common stock and the selling stockholders are selling shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is expected to be between $ and $ per share. We have been approved to list our common stock on the New York Stock Exchange under the symbol “UTE.”

We have granted the underwriters an option to purchase a maximum of additional shares of our common stock.

Investing in our common stock involves risks. See “Risk Factors” beginning on page 19.


	Price to Public	Underwriting Discounts and Commissions	Proceeds to Ute Energy	Proceeds to Selling Stockholders
Per Share	$	$	$	$
Total	$	$	$	$

Delivery of the shares of common stock will be made on or about , 2012.

We are an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended.

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.

Credit Suisse

Goldman, Sachs & Co.

RBC Capital Markets

Wells Fargo Securities


Deutsche Bank Securities		KeyBanc Capital Markets		Macquarie Capital		Tudor, Pickering, Holt & Co.

Mitsubishi UFJ Securities

The date of this prospectus is , 2012.

LOGO

TABLE OF CONTENTS


	Page
PROSPECTUS SUMMARY		1
RISK FACTORS		19
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		43
USE OF PROCEEDS		45
DIVIDEND POLICY		46
CAPITALIZATION		47
DILUTION		48
SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA		49
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		52
BUSINESS		76
MANAGEMENT		107
EXECUTIVE COMPENSATION AND OTHER INFORMATION		113


	Page
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		121
PRINCIPAL AND SELLING STOCKHOLDERS		124
DESCRIPTION OF CAPITAL STOCK		126
SHARES ELIGIBLE FOR FUTURE SALE		130
MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS TO NON-U.S. HOLDERS		132
UNDERWRITING (CONFLICTS OF INTEREST)		136
LEGAL MATTERS		142
EXPERTS		142
WHERE YOU CAN FIND MORE INFORMATION		142
INDEX TO FINANCIAL STATEMENTS		F-1
GLOSSARY OF OIL AND NATURAL GAS TERMS		A-1

You should rely only on the information contained in this document or to which we have referred you. We have not authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities. The information in this document may only be accurate as of the date of this document.

Dealer Prospectus Delivery Obligation

Until , all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Industry and Market Data

The industry and market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

PROSPECTUS SUMMARY

This summary highlights 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 unaudited condensed pro forma financial information 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.

Information related to our operated acreage position in Horseshoe Bend includes certain acreage in Ouray Valley that is subject to a vote of the working interest owners to determine the operator. Please read “—Horseshoe Bend Acquisition” beginning on page 7 of this prospectus. For a detailed explanation of the basis for our estimated net proved reserves and average net daily production, please read “—Summary Historical and Pro Forma Operating and Reserve Data” beginning on page 17 of this prospectus.

Prior to completion of this offering, Ute Energy Upstream Holdings LLC will convert from a Delaware limited liability company to a Delaware corporation and change its name to Ute Energy Corporation. Unless the context otherwise requires, references to “we,” “us,” “our,” the “company” and “Ute Energy” refer to Ute Energy Upstream Holdings LLC before the completion of our corporate reorganization and Ute Energy Corporation as of the completion of our corporate reorganization and thereafter. References to “our parent” refer to our parent company, Ute Energy LLC, before the completion of our corporate reorganization. We have included a glossary of certain oil and natural gas terms used in this prospectus in Appendix A.

UTE ENERGY CORPORATION

Overview

We are an independent oil and natural gas company engaged in the exploration, development, production and acquisition of oil and natural gas reserves with a primary focus on acquiring and developing oil reserves. We have accumulated approximately 165,608 net leasehold acres in the established and highly prospective Uinta Basin, approximately 94% of which are undeveloped. We are currently focused on exploration and development in the Green River and Wasatch formations, which we believe have significant resource potential and are characterized by multiple oil producing horizons with long-life reserves. As of December 31, 2011, our estimated net proved reserves were 38.3 MMBoe, approximately 24% of which were classified as proved developed and approximately 88% of which were comprised of oil. For the three months ended March 31, 2012, our average net daily production from our properties was 5,820 Boe/d. For the month ended March 31, 2012, our average net daily production was 6,310 Boe/d.

The Ute Indian Tribe of the Uintah and Ouray Reservation (the “Tribe”) formed our parent company, Ute Energy LLC, in 2005 to participate in the exploration and development of the Tribe’s mineral estate in the Uinta Basin. The Tribe partnered with leading oil and gas operators in the Uinta Basin to develop its oil and natural gas properties. In 2007, Quantum Energy Partners and Quantum Resources Management made their initial investment in our parent company, which provided our parent with the capital to accelerate operations and fund the cost of developing its properties. We were formed by our parent in 2008 to manage our oil and natural gas operations distinctly from our parent’s other energy investments.

As a part of this strategy, we hired a dedicated management team and technical personnel with significant industry and operational experience. Our management team is led by Joseph N. Jaggers, an industry veteran with over 30 years of experience managing oil and gas operations. Most recently, Mr. Jaggers served as President and Chief Operating Officer of Bill Barrett Corporation (“Bill Barrett”), where he achieved significant production and reserve growth. Mr. Jaggers has operational experience in many basins in North America, including the Uinta Basin, and leads an experienced team with extensive engineering, geosciences, land, environmental and financial capabilities.

Since our strategic shift, we have increased our operated acreage position in the Uinta Basin through an active leasing and acquisition program and we have balanced our portfolio of Tribal acreage with the addition of significant interests in fee, state, federal and allotted lands. As of December 31, 2011, we have 78,170 net operated acres, which represents 47% of our total net acreage position, and we have 68,041 net acres on fee, state, federal and allotted lands, which represents 41% of our total net acreage position. We had drilled 34 gross (34 net) operated wells as of December 31, 2011, and we operated 43% of our average net daily production for the month ended December 31, 2011. We operated approximately 50% of our average net daily production for the month ended March 31, 2012.

In addition to expanding our operated acreage position, we continue to derive substantial benefits from our non-operated properties throughout the Uinta Basin. As of December 31, 2011, we have participated in 339 gross (101.6 net) non-operated wells. These wells are operated by other leading operators in the basin, including Berry Petroleum Company (“Berry Petroleum”), Bill Barrett and Newfield Exploration Company (“Newfield”). We believe our participation in non-operated project areas offers attractive return opportunities and enables us to gain additional exposure to emerging resource plays without committing all of the capital required to drill the wells during the early-stage testing and refinement of drilling and completion techniques. For example, our operating partners are leading the development of an emerging horizontal play targeting the Uteland Butte producing zone of the lower Green River formation. Through December 31, 2011, we have participated in eight gross (2.25 net) horizontal Uteland Butte wells drilled by our operating partners.

Our oil and natural gas properties are divided among multiple project areas within the Uinta Basin. These project areas are described in more detail under the heading “— Our Core Project Areas” beginning on page 5 of this prospectus. The following table presents a summary of acreage, identified potential drilling locations, reserves and production for each of our project areas as of the dates, and for the periods, indicated.


	Net Acreage as of December 31, 2011		Identified Potential Drilling Locations as of December 31, 2011(1)				Estimated Net Proved Reserves as of December 31, 2011						Average Net Daily Production (Boe/d) for the Three Months Ended March 31, 2012
	Net Acreage as of December 31, 2011		Gross		Net		MMBoe(2)		% of Total Proved Reserves		% Oil
Randlett		41,478		1,008		917.0		14.1		37%		93%		2,407
Horseshoe Bend		29,281		820		567.7		9.2		24%		100%		329
Rocky Point		11,071		507		213.3		—		—		—		—
Blacktail Ridge		28,603		647		312.9		8.6		22%		75%		1,496
North Monument Butte		11,724		1,050		262.5		5.4		14%		79%		721
Bridgeland		10,124		573		200.5		0.6		2%		52%		472
Lake Canyon		30,066		1,462		365.5		0.3		1%		67%		330
Other		3,261		17		8.2		0.1		0%		0%		65

Total		165,608		6,084		2,847.6		38.3		100%		88%		5,820

(1)

To identify our potential drilling locations, we analyze both our own proprietary information as well as industry data available in the public domain. Specifically, petrophysical data derived from open hole logs and cores and production data from operated and non-operated wells provide the technical basis from which we identified the potential locations. We also adjust locations for topographical issues as well as environmental and cultural concerns. Our identified potential drilling locations are scheduled out over many years, and there is no guarantee that all or even a substantial portion of these potential drilling locations will be drilled. Based on our currently projected capital expenditure budget, we estimate that we will have drilled approximately 174 gross wells on these potential locations by the end of 2012 and approximately 2,298 gross wells by the end of 2016. However, we are not the operator of 67% of our gross (44% net) identified potential drilling locations, and therefore have limited control over the timing of drilling of those wells or whether wells on these properties will be drilled at all.

(2)	One Boe is equal to one Bbl of oil or six Mcf of natural gas based on an approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

We have a multi-year inventory of development drilling and exploration projects in the Uinta Basin. We believe that the size and concentration of our acreage will allow us to efficiently grow our reserves, production and cash flow over time. As of December 31, 2011, we have identified 6,084 gross (2,847.6 net) potential drilling locations (615 gross (355.4 net) of which are proved undeveloped) targeting multiple zones in the Green River and Wasatch formations. To accelerate our drilling program, we deployed a second operated drilling rig to the basin in November 2011, and we expect to deploy a third drilling rig by late third quarter 2012. We may deploy additional operated drilling rigs to the basin should drilling results, market conditions and drilling permit availability allow us to further accelerate our drilling program in the near term. As of December 31, 2011, our partners were operating four drilling rigs in our non-operated project areas.

We plan to develop our identified potential drilling locations primarily through vertical drilling and utilization of multi-stage fracture stimulation techniques. We continue to evaluate the potential for horizontal drilling to target zones such as the Uteland Butte, the Mahogany Oil Shale and the Black Shale/G-1 Lime as well as the potential for enhanced recovery techniques, such as waterfloods, to improve results and increase oil and gas recoveries.

Our total 2012 capital expenditure budget is expected to be approximately $296 million, consisting of approximately $281 million for drilling and completion costs, of which 68% is for operated wells. Additional capital expenditures are budgeted for strategic infrastructure, maintaining leasehold positions and for general corporate purposes. Our 2012 capital budget has not allocated any expenditures for operated horizontal wells. The amount and allocation of capital we spend may fluctuate materially based on drilling results, market conditions and drilling permit availability. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our Competitive Strengths

We believe the following competitive strengths will allow us to successfully execute our business strategies:

•

Large, regionally focused acreage position in an established and highly prospective oil resource area. We have a substantial and concentrated acreage position of approximately 165,608 net acres in the Uinta Basin, approximately 94% of which is undeveloped. We believe our acreage position is highly prospective, primarily for crude oil within multiple target zones of the Green River and Wasatch formations, including the Uteland Butte. The Uinta Basin has a long history of exploration and development activity with substantial remaining resource potential. According to IHS, Inc., the Uinta Basin has produced 1.4 billion Boe of crude oil and natural gas since the 1940s, and, according to Wood Mackenzie, the Uinta Basin has remaining recoverable reserves, defined as proved plus probable reserves, of 3.1 billion Boe.

•

Multi-year inventory of identified potential drilling locations targeting crude oil zones. We have an inventory of 6,084 gross (2,847.6 net) identified potential drilling locations in the Uinta Basin. Our drilling activity focuses on producing crude oil, with all of our identified potential drilling locations targeting crude oil zones. For the year ended December 31, 2011, we drilled or participated in 133 gross (68.0 net) wells with a 99% success rate. We currently plan to drill or participate in 174 gross (120.0 net) wells within our existing project areas by the end of 2012.

•

Management and technical team with extensive public company experience in resource play development. Our senior management and technical team has a successful record of identifying, acquiring and developing resource plays and has an average of over 25 years of oil and gas industry experience. Joseph N. Jaggers, our President and Chief Executive Officer, previously served as President and Chief Operating Officer of Bill Barrett and has a long track record of achieving production and reserve growth in many basins, including the Uinta Basin. Our technical team includes engineers, geoscientists, landmen and regulatory specialists. Our team has enabled us to expand our asset base and successfully execute our strategic shift to growing our operated production and acreage position. In addition, our team has significant public company experience as a result of prior work for companies such as Barrett Resources Corporation, The Williams Companies, Inc., Bill Barrett and Rosetta Resources Inc.

•

Significant liquidity and financial flexibility to fund our drilling program. Following this offering, we expect to have no debt outstanding under our new $500.0 million revolving credit facility, with approximately $150.0 million available for borrowing and $ million of cash on hand. We expect that the cash proceeds from this offering and funds available under our new credit facility, together with the cash flows from our operations, will be sufficient to fund our anticipated capital expenditures. Moreover, as the operator on a significant portion of our acreage position, we expect to gain additional control over the level and pace of our capital expenditures, as we expect to spend the majority of our future capital expenditures drilling operated wells to develop our properties. To allow for more predictable cash flows in the near term, we maintain an active hedging program with an average of 3,843 bbl/d of crude oil production hedged in 2012 at a weighted average minimum price of $94.02 per bbl as of March 31, 2012.

•

Strong relationship with the Tribe. Approximately 59% of our net acreage and 59% of our net identified potential drilling locations are located on Tribal lands or are leased from the Tribe. Our relationship with the Tribe has been instrumental in building an asset base that includes both high growth development properties and properties with exposure to emerging Uinta Basin resource plays. Following this offering, the Tribe will own approximately % of our outstanding common stock, which we believe may give us a competitive advantage in acquiring additional mineral interests on Tribal lands. Moreover, we believe that our relationship with the Tribe provides us with a significant competitive advantage in securing drilling and operating permits on Tribal lands and otherwise working with government entities with oversight authority for oil and natural gas exploration and production on Tribal lands.

Our Business Strategy

Our goal is to increase stockholder value by growing our reserves and increasing our production and cash flows by executing the following strategies:

•

Focus on aggressive expansion of operated drilling activities. We intend to aggressively drill our current operated acreage to maximize the value of our resource potential. We have 78,170 net operated acres, which are 96% undeveloped with approximately 1,991 gross identified potential drilling locations. We believe that the concentration and growth of our operated properties will enable us to achieve economies of scale on drilling service costs and leasehold operating expenses. Our 2012 drilling program contemplates the drilling of approximately 106 gross (101.6 net) operated vertical wells utilizing two operated drilling rigs for the full year, but we may convert some of our vertical wells into horizontal wells in the future. We expect to deploy a third drilling rig by late third quarter 2012 to support the

development of our Rocky Point and Horseshoe Bend properties. We may deploy additional drilling rigs to the basin should drilling results, market conditions and drilling permit availability allow us to accelerate our drilling program in the near term.

•

Apply operating experience to enhance returns. We are focused on the continuous improvement of our operating practices and have significant experience in converting resource opportunities into cost-effective development projects. We intend to draw on our technical team’s significant experience in utilizing modern drilling and completion techniques to optimize our resource recovery in a cost efficient manner. For example, our average drilling cost for a Randlett well was approximately $575,000 per well as of March 31, 2012 as compared to approximately $885,000 per well during 2011. We expect to realize approximately $75,000 in additional cost savings per well in the near term. In the near term, our primary focus will be the use of vertical drilling and multi-stage fracturing techniques to potentially enhance resource recovery, and we will continue to evaluate the effectiveness of horizontal drilling, down-spacing and waterflooding as a means to further increase resource recovery.

•

Continue to participate in drilling on non-operated leasehold acreage. We believe our participation in non-operated project areas offers attractive return opportunities and enables us to gain additional exposure to emerging resource plays without committing all of the capital required to drill the wells during the early-stage testing and refinement of drilling and completion techniques. For example, our operating partners are leading the development of an emerging horizontal play targeting the Uteland Butte producing zone of the lower Green River formation. Through December 31, 2011, we have participated in eight gross (2.25 net) horizontal Uteland Butte wells drilled by our operating partners. We plan to apply the knowledge and expertise gained from participating in the drilling and completion of these wells to target prospective horizontal Uteland Butte or other prospective horizontal zones in our operated portfolio of oil and natural gas properties in the future. In addition, we believe that the knowledge and expertise gained through our non-operated positions will enhance our ability to continue efficiently growing our operated acreage positions throughout the Uinta Basin.

•

Allocate capital to strategic infrastructure to support our upstream operations. We will continue to identify and fund strategic infrastructure projects to reduce risks, increase marketing flexibility and enhance the value of our business. We intend to operate these infrastructure assets to ensure that we maintain control and flexibility over takeaway capacity as we develop our properties. For example, we are installing a high pressure gas gathering system within our Randlett project area, which will connect to a pipeline system that flows to the Chipeta natural gas processing plant. We have contracted capacity on this pipeline system and have secured 25,000 Mcf/d of processing capacity at the Chipeta plant. Our Randlett gathering system will provide an outlet for associated natural gas from our oil wells, which will minimize the risk of a curtailment of oil production due to lack of takeaway capacity for produced natural gas. In addition, our access to capacity on this gathering system will enable us to realize additional value on our future natural gas production, as this production will be gathered and transported to the Chipeta plant where it will be processed to recover marketable natural gas liquids.

•

Pursue acquisitions in areas that leverage our operating strengths. In the near term, we intend to identify and acquire additional acreage and producing properties in the Uinta Basin, with an emphasis on increasing our operated asset base. Over time, we may selectively target additional basins in the Rocky Mountain region or other resource opportunities with characteristics similar to our existing areas of operations to leverage our operating strengths in areas outside the Uinta Basin.

Our Core Project Areas

Randlett

We operate all of our properties in our Randlett project area and have approximately 41,478 net leasehold acres with a 100% working interest in our producing wells. We acquired our initial acreage in Randlett in

December 2010 and commenced drilling activities in April 2011. As of December 31, 2011, we had drilled a total of 34 wells, with 28 wells completed and producing, five wells awaiting completion and one exploratory dry hole due to a mechanical issue encountered drilling the well, not a reservoir performance issue. All of our wells in Randlett have been drilled vertically and have primarily targeted the Green River and upper Wasatch formations.

We have completed a majority of our Randlett wells in the Uteland Butte zone of the Green River formation, which is one of several zones we currently complete in our vertical drilling program. We believe this area may also be prospective for a horizontal drilling program targeting the Uteland Butte zone. In addition, we anticipate implementing a pilot waterflood program as part of our 2012 drilling program. Other operators are currently utilizing this secondary recovery technique in nearby fields.

Horseshoe Bend

We acquired our Horseshoe Bend properties in November 2011, substantially all of which we operate. Our Horseshoe Bend properties include approximately 29,281 net leasehold acres with an average working interest of 68% in our producing wells. Operatorship with respect to approximately 3,993 net leasehold acres in Ouray Valley remains subject to a vote of the working interest owners. The Horseshoe Bend project area abuts the northeast corner of Randlett and represents a substantial expansion of our operated leasehold and drilling inventory. We plan to commence operated drilling activities in this area during the second half of 2012, primarily targeting the Green River and Wasatch formations with vertically drilled wells. We believe this area may also be prospective for a horizontal drilling program targeting the Black Shale/G-1 Lime and Uteland Butte zones of the Green River formation and provide additional opportunities for future waterflooding.

Rocky Point

We operate 49% of our approximately 11,071 net leasehold acres in the Rocky Point project area, and Newfield operates the remaining 51%. Our operated leasehold acres are adjacent to the western boundary of Randlett. We hold a 75% working interest in our operated leasehold acres and a 30% working interest in our non-operated leasehold acres. Our partner commenced drilling in Rocky Point in our non-operated acreage area in 2012 with an initial drilling program primarily targeting the lower Green River and Wasatch formations.

Blacktail Ridge

We have a non-operated interest in approximately 28,603 net leasehold acres in our Blacktail Ridge project area. Our working interests in our Blacktail Ridge wells are typically either 25% or 50%, depending on participation in prior wells and elections on proposed wells. Bill Barrett operates our Blacktail Ridge acreage position and has historically drilled vertical wells primarily targeting the Wasatch formation. We believe this area may also be prospective for a horizontal drilling program targeting the Uteland Butte and Black Shale zones. We participated in Bill Barrett’s first horizontal well in Blacktail Ridge targeting the Uteland Butte zone, which was completed in November 2011.

North Monument Butte

We have approximately 11,724 net leasehold acres in the North Monument Butte project area with a working interest of 25% in our producing wells. Newfield operates North Monument Butte, and the wells in this project area primarily target the Green River and upper Wasatch formations. We believe North Monument Butte provides additional opportunities for both horizontal drilling of multiple zones and waterflooding of the Green River formation to increase recovery of reserves.

Bridgeland

We have approximately 10,124 net leasehold acres in the Bridgeland project area with a working interest of 35% in our producing wells. Newfield operates Bridgeland, and the wells in this project area primarily target the Green River formation.

Lake Canyon

We have approximately 30,066 net leasehold acres in the Lake Canyon project area with an average working interest of 26% in our producing wells. Bill Barrett and Berry Petroleum operate Lake Canyon, and the wells in this project area primarily target the Green River and Wasatch formations. The operators are evaluating the emerging horizontal Uteland Butte play in Lake Canyon. Through December 31, 2011, we have participated in five gross (1.25 net) horizontal Uteland Butte wells drilled by Bill Barrett and two gross (0.50 net) horizontal Uteland Butte wells drilled by Berry Petroleum.

Horseshoe Bend Acquisition

On November 30, 2011, we acquired approximately 29,281 net fee, state and federal acres with 820 gross identified potential drilling locations in Horseshoe Bend and approximately 6,062 net fee and allotted acres in Randlett with 239 gross identified potential drilling locations, for approximately $99.9 million in cash, subject to customary post-closing purchase price adjustments. As of December 31, 2011, this acquisition significantly increased our operated leasehold acreage position from 33% to 47% of our total acreage, increased our gross identified potential drilling locations by 21%, and increased our net fee, state, federal and allotted acres by 108%. We operate all of the approximately 6,062 net acres acquired in Randlett and substantially all of the approximately 29,281 net acres acquired in Horseshoe Bend. However, operatorship with respect to approximately 3,993 net acres in Ouray Valley remains subject to a vote of the working interest owners.

In addition to significantly increasing our operated acreage position and our inventory of undeveloped acreage, the acquisition included 50 producing wells in our Horseshoe Bend project area with 9.2 MMBoe of proved reserves as of December 31, 2011. The average net daily production from these wells was 341 Boe/d for the year ended December 31, 2011 and 369 Boe/d for the three months ended December 31, 2011.

Our Relationship with Quantum Energy Partners

Quantum Energy Partners is a leading private equity firm founded in 1998 to make investments in the energy sector. Quantum Energy Partners currently has approximately $6.4 billion in assets under management. The employees of Quantum Energy Partners are experienced energy professionals with expertise in finance and operations and broad technical skills in the oil and natural gas business.

In 2007, Quantum Energy Partners and one of its affiliates, Quantum Resources Management (together with Quantum Energy Partners, “Quantum”), made an initial investment in our parent to provide a portion of the capital necessary for our parent to enhance its operations and fund the development of its oil and gas properties. Since then, Quantum has continued to provide support and resources to us, which has allowed us to further enhance our operations and increase our capabilities. Following this offering, Quantum Energy Partners and Quantum Resources Management will continue to be two of our largest stockholders.

Quantum and the Tribe will have certain rights to designate nominees for election to our board of directors upon completion of this offering. For more information regarding the rights of Quantum and the Tribe to designate nominees for election to our board of directors, please read “Certain Relationships and Related Party Transactions—Director Designation Agreement.”

Risk Factors

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

•

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

•

Our exploration, development and production projects require substantial capital expenditures. We may be unable to obtain sufficient capital or financing on satisfactory terms to fund our operations or drilling program, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.

•

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

•

The identified potential drilling locations that we decide to drill may not yield oil or natural gas in commercial quantities.

•

Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

•

If we fail to drill wells or establish production sufficient to maintain our acreage, we may lose future rights to drill on our current acreage.

•

There is limited transportation and refining capacity for our yellow and black wax crude oil, which may limit our ability to sell our current production or to increase our production.

•

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.

•

Currently, a majority of our oil producing properties are located on the Uintah and Ouray Reservation, making us vulnerable to risks associated with tribal sovereignty laws and regulations pertaining to the operation of oil and gas properties on Native American tribal lands.

•

All of our producing properties and operations are located in the Uinta Basin region, making us vulnerable to risks associated with a lack of geographic diversification.

•

We have a limited history of operating our drilling locations and may be unable to realize our target returns on the drilling locations that we operate.

•

The concentration of our capital stock ownership among our largest stockholders and their affiliates and the rights of the Tribe and Quantum under the Director Designation Agreement will limit your ability to influence corporate matters.

For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, please read “Risk Factors” beginning on page 19 of this prospectus and “Cautionary Note Regarding Forward-Looking Statements” beginning on page 43 of this prospectus.

Corporate Reorganization

In connection with this offering, our parent, Ute Energy LLC, will cause Ute Energy Upstream Holdings LLC to convert into a Delaware corporation and change its name to Ute Energy Corporation. In connection with the conversion, membership interests in our company will be converted into shares of common stock in our corporation. Immediately prior to the closing of this offering, Ute Energy LLC will distribute all of its shares of our common stock to its existing members in accordance with their respective membership interests, and we and the selling stockholders will sell shares of our common stock to the public. Following this conversion, we will be subject to taxation at the company level.

The following diagram illustrates our ownership structure based on total shares of common stock outstanding after giving effect to this offering and our related corporate reorganization and assuming no exercise of the underwriters’ option to purchase additional shares of our common stock.

LOGO

(1)	Includes shares of common stock held by an affiliate of Quantum Energy Partners and shares of common stock held by an affiliate of Quantum Resources Management.

(2)	Includes shares of common stock held by Ute Energy Holdings LLC, an entity wholly-owned and controlled by the Tribe.

Corporate Information

Our principal executive offices are located at 1875 Lawrence Street, Suite 200, Denver, Colorado 80202, and our telephone number at that address is (720) 420-3200. We maintain a website at www.uteenergy.com. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or “JOBS Act.” We anticipate that we will remain an emerging growth company until the earlier of the end of the fiscal year during which we have total annual gross revenues of $1.0 billion or more and the end of the fiscal year following the fifth anniversary of the completion of this public offering. For as long as we are an emerging growth company, unlike other public companies, we will not be required to:

•

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002;

•

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

•

comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the Securities and Exchange Commission determines otherwise;

•

provide certain disclosure regarding executive compensation required of larger public companies;

•

hold nonbinding shareholder advisory votes on executive compensation; or

•

obtain shareholder approval of previously unapproved golden parachute payments in connection with proposed merger and sale transactions.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

The Offering

Common stock offered by Ute Energy

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

Common stock offered by the selling stockholders

Total common stock offered

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

Common stock outstanding after the offering

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

Common stock owned by the selling stockholders after the offering

Option to purchase additional shares

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

Use of proceeds

We expect to receive approximately $ million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses (or approximately $ million if the underwriters’ option to purchase additional shares is exercised in full). We will use approximately $ million of the net proceeds from this offering to repay in full debt that we intend to assume from our parent company in connection with this offering. The remaining net proceeds of approximately $ million (or approximately $ million if the underwriters’ option to purchase additional shares is exercised in full) will be used to fund a portion of our $281 million budget for drilling and completion costs during 2012. We will not receive any proceeds from the sale of shares by the selling stockholders. Affiliates of certain of the underwriters are lenders under our parent’s credit facilities and therefore will indirectly receive a portion of the proceeds of this offering in connection with the repayment of the debt assumed by us. Please read “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital resources” and “Underwriting (Conflicts of Interest).”

Conflicts of interest

Affiliates of certain of the underwriters are lenders under our parent’s credit facilities and, accordingly, will receive a substantial portion of the proceeds from this offering in the form of the repayment of the debt assumed by us.

Because affiliates of certain of the underwriters are lenders under our parent’s credit facilities and will receive more than 5% of the net proceeds of this offering due to the repayment of the debt assumed by us, this offering will be conducted in accordance with Rule 5121 of the Financial Industry Regulatory Authority, Inc., which requires, among other things, that a “qualified independent underwriter” has participated in the preparation of, and has exercised the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Credit Suisse Securities (USA) LLC has agreed to act as qualified independent underwriter for this offering. Please read “Use of Proceeds” and “Underwriting (Conflicts of Interest).”

Dividend policy

We do not anticipate paying any cash dividends on our common stock. In addition, we anticipate that our new credit facility will restrict the payment of dividends on our common stock. Please read “Dividend Policy.”

New York Stock Exchange symbol

We have been approved to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “UTE.”

Risk factors

You should carefully read and consider the information beginning on page 19 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.

Summary Historical and Unaudited Pro Forma Financial Data

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

Set forth below is our summary historical and pro forma financial data as of and for the years ended December 31, 2009, 2010 and 2011 and the three months ended March 31, 2011 and 2012. Historical operations data for the years ended December 31, 2009, 2010 and 2011 and balance sheet data as of December 31, 2009, 2010 and 2011 are derived from the audited financial statements of Ute Energy Upstream Holdings LLC. Historical operations data for the three months ended March 31, 2011 and 2012 and balance sheet data as of March 31, 2011 and 2012 are derived from the unaudited financial statements of Ute Energy Upstream Holdings LLC. Although we were formed in 2008, we had no assets or operating activities until March 2010. In March 2010, our parent assigned all of its oil and gas participation rights and other oil and gas assets, except its ownership in Ute/FNR, LLC, as well as the related costs to us. Oil and gas assets subsequently acquired by our parent were also assigned to us. This transfer of interests was accounted for as a transaction between entities under common control which requires us to record the conveyances at our parent’s historical basis applied retrospectively to our financial statements of all prior periods beginning January 1, 2008. The financial statements as of and for the years ended December 31, 2010 and 2011 have been audited by KPMG LLP, an independent registered public accounting firm, and are included elsewhere in this prospectus. The financial statements for the year ended December 31, 2009 have been audited by Ehrhardt Keefe Steiner & Hottman PC, an independent registered public accounting firm, and are included elsewhere in this prospectus. The balance sheet data as of December 31, 2009 are derived from the audited balance sheet of Ute Energy Upstream Holdings LLC, which is not included herein.

The pro forma financial data for the year ended December 31, 2011 give effect to the Horseshoe Bend acquisition described in “Summary—Horseshoe Bend Acquisition” and our corporate reorganization as described in “Summary—Corporate Reorganization” and are derived from our unaudited pro forma financial information included elsewhere in this prospectus. The pro forma financial information has been prepared as if the Horseshoe Bend acquisition took place on January 1, 2011. The pro forma balance sheet data as of March 31, 2012 give effect to our corporate reorganization as described under “Summary—Corporate Reorganization.” The pro forma financial data are presented for informational purposes only, should not be considered indicative of actual results that would have been achieved had the Horseshoe Bend acquisition and the reorganization occurred on the dates indicated and do not purport to be indicative of our results of operations for any future periods. In particular, the pro forma financial statements do not include any adjustment for general and administrative expense resulting from the acquisition and ownership of the Horseshoe Bend assets. All unaudited financial information has been prepared on a basis consistent with our audited financial statements and the notes thereto and includes all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of such information.


	Historical															Pro Forma for the Year Ended December 31, 2011
	Year Ended December 31,									Three Months Ended March 31,
	2009			2010			2011			2011			2012
										(Unaudited)						(Unaudited)
	(In thousands)
Statement of operations data:
Oil and gas revenue	$	10,025		$	38,756		$	88,451		$	14,795		$	39,618		$	97,172
Operating expenses:
Lease operating expenses		1,694			4,113			11,996			2,246			6,035			13,295
Production taxes		1,732			2,965			4,044			759			1,789			4,394
Gathering and transportation expenses		1,113			2,079			5,664			792			1,624			5,723
Depreciation, depletion and amortization		5,594			13,852			30,784			5,614			12,551			33,026
Exploration expenses		40			60			21			10			8			21
Impairment of oil and gas properties and dry hole expenses		—			—			1,092			—			173			1,092
General and administrative expenses		1,067			3,375			8,194			1,532			3,246			8,194

Total operating expenses	$	11,240		$	26,444		$	61,795		$	10,953		$	25,426		$	65,745

Income (loss) from operations		(1,215	)		12,312			26,656			3,842			14,192			31,427
Other income (expense):
Equity in earnings (losses) from Ute/FNR, LLC(1)		(725	)		23			—			—			—			—
Unrealized loss on derivative instruments		(936	)		(1,615	)		(2,382	)		(10,220	)		(18,636	)		(2,382	)
Realized gain (loss) on derivative instruments		(896	)		1,338			(201	)		(266	)		(2,210	)		(201	)
Interest expense		—			(439	)		(1,856	)		(270	)		(2,223	)		(1,856	)
Write-off of deferred debt issue costs		(274	)		—			(814	)		—			—			(814	)
Interest and other income (expense)		38			35			—			—			—			—

Total other expense		(2,793	)		(658	)		(5,253	)		(10,756	)		(23,069	)		(5,253	)

Income (loss) before income taxes		(4,008	)		11,654			21,403			(6,914	)		(8,877	)		26,174

Income tax expense(2)		—			—			—			—			—			(9,322)

Net income (loss)	$	(4,008	)	$	11,654		$	21,403		$	(6,914	)	$	(8,877	)	$	16,852


	As of December 31,									As of March 31,						Pro Forma as of March 31, 2012
	2009			2010			2011			2011			2012			Pro Forma as of March 31, 2012
										(Unaudited)						(Unaudited)
	(In thousands)
Balance sheet data:
Cash and cash equivalents	$	162		$	67		$	4,497		$	908		$	1,328		$	1,328
Total property and equipment, net		34,677			88,845			338,490			100,261			386,400			386,400
Total assets		53,690			99,661			365,297			110,239			411,322			416,457
Long-term debt		—			10,000			116,932			19,500			152,600			152,600
Total owner’s equity		47,882			66,655			193,767			60,875			188,268			111,298



	Year Ended December 31,									Three Months Ended March 31,
	2009			2010			2011			2011			2012

	(In thousands)
Cash flow data:
Net cash provided by operating activities	$	128		$	22,467		$	62,935		$	8,769		$	15,182
Net cash used in investing activities		(11,261	)		(54,342	)		(266,783	)		(18,414	)		(56,315	)
Net cash provided by financing activities		11,285			31,780			208,278			10,486			37,964


	Year Ended December 31,						Three Months Ended March 31,				Pro Forma for the Year Ended December 31, 2011
	2009		2010		2011		2011		2012		Pro Forma for the Year Ended December 31, 2011
							(Unaudited)				(Unaudited)
	(In thousands)
Other financial data:
Adjusted EBITDAX(3)	$	2,798	$	27,585	$	58,352	$	9,200	$	24,714	$	65,365

(1)

Reflects equity investment income (loss) of our parent resulting from its equity investment in Ute/FNR, LLC (“Ute/FNR”) for the years ended December 31, 2009 and 2010. Our parent’s interest in Ute/FNR has not been contributed to us, and we do not expect to own an interest in Ute/FNR upon the consummation of this offering. The exclusion of our parent’s interest in Ute/FNR from our business is reflected as a distribution to our parent of this interest in March 2010 following the contribution to us by our parent of its other upstream operations in existence at that time. Our parent’s interest in Ute/FNR is not reflected in our financial statements for periods ending after December 31, 2010. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Basis of Presentation” for more information regarding our accounting treatment of our parent’s equity investment in Ute/FNR.

(2)

As a limited liability company treated as a disregarded entity for federal income tax purposes, we are taxed at the member unitholder level rather than at the company level. Following the corporate reorganization described in this prospectus, we will be taxed at the company level. As a result, for periods following the corporate reorganization, our financial statements will include a tax provision on our income. On a pro forma basis after giving effect to the corporate reorganization, we would have recorded a tax provision (benefit) of approximately $7.6 million, $4.0 million and $(2.0) million for the years ended December 31, 2011, 2010 and 2009, respectively, and approximately $(3.4) million and $(2.7) million for the three months ended March 31, 2012 and 2011, respectively.

(3)	Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our net income (loss) and net cash provided by operating activities, please read “—Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

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.

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

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 loss and net cash provided by operating activities, respectively.


	Year Ended December 31,								Three Months Ended March 31,						Pro Forma for the Year Ended December 31, 2011
	2009			2010			2011		2011			2012			Pro Forma for the Year Ended December 31, 2011
									(Unaudited)						(Unaudited)
	(In thousands)
Reconciliation of Adjusted EBITDAX to net income (loss):
Net income (loss)	$	(4,008	)	$	11,654		$	21,403	$	(6,914	)	$	(8,877	)	$	16,852
Unrealized loss on derivative instruments		936			1,615			2,382		10,220			18,636			2,382
Interest expense		—			439			1,856		270			2,223			1,856
Depreciation, depletion and amortization		5,594			13,852			30,784		5,614			12,551			33,026
Impairment of oil and gas properties and dry hole expenses		—			—			1,092		—			173			1,092
Write-off of deferred debt issue costs		274			—			814		—			—			814
Exploration expenses		40			60			21		10			8			21
Income tax expense		—			—			—		—			—			9,322
Other income		(38	)		(35	)		—		—			—			—

Adjusted EBITDAX	$	2,798		$	27,585		$	58,352		9,200			24,714		$	65,365


	Year Ended December 31,									Three Months Ended March 31,
	2009			2010			2011			2011			2012
										(Unaudited)
	(In thousands)
Reconciliation of Adjusted EBITDAX to net cash flows provided by operating activities:
Net cash provided by operating activities	$	128		$	22,467		$	62,935		$	8,769		$	15,182
Interest expense		—			439			1,856			270			2,223
Exploration expenses		40			60			21			10			8
Amortization in interest expense		—			(194	)		(441	)		(79	)		(212	)
Equity in earnings (losses) from Ute/FNR, LLC		(725	)		23			—			—			—
Changes in working capital		3,393			4,825			(6,019	)		230			7,513
Other income		(38	)		(35	)		—			—			—

Adjusted EBITDAX	$	2,798		$	27,585		$	58,352			9,200			24,714

Summary Historical and Pro Forma Operating and Reserve Data

The following table presents summary historical and pro forma data with respect to our estimated net proved oil and natural gas reserves as of the dates indicated. The estimated reserve data presented as of December 31, 2009 are based on a report prepared by Cawley, Gillespie & Associates, Inc., independent reserve engineers (“Cawley Gillespie”), and the estimated reserve data presented as of December 31, 2010 and 2011 are based on reports prepared by Ryder Scott Company, L.P., independent reserve engineers (“Ryder Scott”). The reserve estimates presented as of December 31, 2009, 2010 and 2011 were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. For additional information regarding our estimated net proved oil and natural gas reserves, as well as the impact of the SEC’s rules governing the presentation of reserve information, please read “Business—Our Operations—Estimated proved reserves.”


	As of December 31,
	2009			2010			2011
Reserve data(1):
Estimated proved reserves:
Oil (MMBbls)		2.0			7.1			33.5
Natural gas (Bcf)		5.7			17.3			25.2
Natural gas liquids (MMBbls)		0.1			0.2			0.6
Total estimated proved reserves (MMBoe)		3.1			10.2			38.3
Estimated proved developed reserves (MMBoe)		1.4			3.7			9.0
Percent developed		45	%		37	%		24	%
Estimated proved undeveloped reserves (MMBoe)		1.7			6.4			29.2
PV-10 (in millions)(2)	$	26.8		$	112.6		$	564.6
Standardized Measure (in millions)(3)	$	26.8		$	112.6		$	564.6

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


	As of December 31,
	2009		2010		2011
Oil and natural gas prices(1):
Oil (per Bbl)	$	61.18	$	79.43	$	96.19
Natural gas (per MMBtu)	$	3.87	$	4.38	$	4.12

(1)

Benchmark prices for oil and natural gas at December 31, 2009, 2010 and 2011 reflect the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months, using NYMEX WTI posted prices for oil and NYMEX Henry Hub prices for natural gas. For oil and natural gas liquids volumes, the benchmark WTI posted price is adjusted for quality, transportation fees and regional price differentials. The adjustment varies by project area, and the prices used to calculate estimated reserves as of December 31, 2011 reflected a weighted average discount from benchmark prices of 16%. For gas volumes, the Henry Hub spot price is adjusted for energy content, transportation fees and regional price differentials. The adjustment varies by project area, and the prices used to calculate estimated reserves as of December 31, 2011 reflected a weighted average discount from benchmark prices of 7%.

(2)

For more information, please read Note 12 to our audited financial statements included elsewhere in this prospectus. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

(3)

Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depreciation, depletion and amortization, discounted at 10% per annum to reflect timing of future cash flows. As a limited liability company treated as a disregarded entity for federal income tax purposes, we are not subject to federal income taxes and thus make no provision for federal income taxes in the calculation of our Standardized Measure. In connection with the closing of this offering, we will convert into a corporation that will be a taxable entity for federal income tax purposes. Future calculations of Standardized Measure will include the effects of income taxes on future net revenues. For more information, please read Note 12 to our audited financial statements included elsewhere in this prospectus. Standardized Measure does not give effect to derivative transactions. We expect to continue to hedge a substantial portion of our future estimated production from total proved producing reserves. For further discussion of income taxes, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical basis for the periods presented. The unaudited pro forma information gives effect to the Horseshoe Bend acquisition as if it had occurred on January 1, 2011.


	Year Ended December 31,						Three Months Ended March 31,				Pro Forma for the Year Ended December 31, 2011
	2009		2010		2011		2011		2012		Pro Forma for the Year Ended December 31, 2011
Operating data:
Net production volumes:
Oil (MBbls)		164.9		507.6		992.1		164.9		429.5		1,106.1
Natural gas (MMcf)		571.3		1,247.8		1,751.8		412.1		549.8		1,751.8
Natural gas liquids (MBbls)		6.2		7.6		33.7		6.4		8.5		33.7
Oil equivalents (MBoe)		266.3		723.1		1,317.8		240.0		529.6		1,431.8
Average daily production (Boe/d)		729		1,981		3,610		2,666		5,820		3,923
Average sales prices:
Oil, without realized derivatives (per Bbl)	$	47.86	$	66.89	$	79.88	$	78.42	$	87.70	$	79.53
Oil, with realized derivatives (per Bbl)		42.43		68.12		78.70		75.23		81.72		78.47
Natural gas, without realized derivatives (per Mcf)		3.31		3.51		3.90		3.49		2.38		3.90
Natural gas, with realized derivatives (per Mcf)		3.31		4.08		4.45		4.13		3.04		4.45
Natural gas liquids (per Bbl)		39.03		55.66		70.42		66.09		75.41		70.42
Costs and expenses (per Boe of production):
Lease operating expenses	$	6.36	$	5.69	$	9.10	$	9.36	$	11.40	$	9.29
Production taxes		6.50		4.10		3.07		3.16		3.38		3.07
Gathering and transportation expenses		4.18		2.88		4.30		3.30		3.07		4.00
Depreciation, depletion and amortization		21.01		19.16		23.36		23.39		23.70		23.07

RISK FACTORS

You should carefully consider the risks described below before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

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

The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. For example, from January 1, 2008 to December 31, 2011 NYMEX West Texas Intermediate crude oil prices ranged from a low of $31.41 per Bbl to a high of $145.29 per Bbl, and NYMEX Henry Hub natural gas prices ranged from a low of $1.88 per MMBtu to a high of $13.31 per MMBtu. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•

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

•

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

•

political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and Africa and conditions in South America and Russia;

•

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

•

the level of global oil and natural gas inventories;

•

costs associated with exploration and development;

•

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

•

localized supply and demand fundamentals and transportation availability;

•

the availability of refining capacity;

•

weather conditions and natural disasters;

•

domestic and foreign governmental regulations;

•

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

•

technological advances affecting energy consumption;

•

the impact of energy conservation efforts and the price and availability of alternative fuels; and

•

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

Substantially all of our production is sold to purchasers at market based prices. Lower oil and, to a lesser extent, natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. For more information, please read “—Our exploration, development and production projects require substantial capital expenditures. We may be unable to obtain sufficient capital or financing on satisfactory terms to fund our operations or drilling program, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.”

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. For more information, please read “—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” and “—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.”

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development and production of our oil and natural gas properties. Our cash flows used in investing activities were $266.8 million related to capital expenditures for the year ended December 31, 2011. Our anticipated capital expenditure budget for 2012 is approximately $296 million, with approximately $281 million allocated for drilling and completion operations. To date, our capital expenditures have been financed by proceeds from equity investments in our parent and borrowing under our parent’s credit facilities that our parent contributed to us, bank borrowings under our prior revolving credit facility and net cash provided by operating activities. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, changes in commodity prices, actual drilling results, drilling permit availability, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

An increase in product prices could result in a desire to increase our capital expenditures. We expect to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our new credit facility as well as the net proceeds from this offering. Our financing needs, however, may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would have a dilutive effect on the value of your common stock.

Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:

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our proved reserves;

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the amount of oil and natural gas we are able to produce from our existing wells;

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the price at which our oil and natural gas is sold;

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the costs of developing and producing oil and natural gas from our properties;

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our ability to acquire, locate and produce new reserves;

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our ability to borrow funds; and

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our ability to access the equity and debt capital markets.

If our revenues 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 on terms favorable to us, or at all. If cash generated by operations or borrowings available under our new credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our identified potential drilling locations, which in turn could lead to the possible expiration of our leases and a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

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

Our future financial condition and results of operations will depend on the success of our exploration, development and production activities. Our oil and natural gas exploration, development and production activities are subject to numerous risks, including the risk that drilling will not result in commercial oil or natural gas production. Our decisions to purchase, explore or develop drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, please read “—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.” Our cost of drilling, completing and operating wells is often uncertain before drilling is completed. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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shortages of or delays in obtaining equipment and qualified personnel;

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unavailability of drilling and/or operating permits;

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facility or equipment malfunctions;

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leaks of oil, natural gas, produced water and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations;

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unexpected adverse drilling conditions;

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unexpected operational events;

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pressure or irregularities in geological formations;

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adverse weather conditions;

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reductions in oil and natural gas prices;

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delays imposed by or resulting from compliance with regulatory requirements;

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proximity to and capacity of transportation facilities;

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title problems; and

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limitations in the market for oil and natural gas.

The identified potential drilling locations that we decide to drill may not yield oil or natural gas in commercial quantities.

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

our drilling locations. Further, initial production rates reported by us or other operators in the Uinta Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has specifically identified and scheduled certain potential drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2011, only 615 of our 6,084 specifically identified potential future gross drilling locations were attributed to proved undeveloped reserves. These identified potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these identified potential drilling locations depends on a number of factors, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, the availability of gathering systems, marketing and transportation constraints, refining capacity, regulatory approvals and other factors. Because of the uncertainty inherent in these factors, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations.

If we fail to drill wells or establish production sufficient to maintain our acreage, we may lose future rights to drill on our current acreage.

As of December 31, 2011, we had exclusive rights to drill on Tribal acres representing 28,752 net acres expiring in 2012, 3,044 net acres expiring in 2013 and 31,118 net acres expiring in 2014. Unless wells are drilled within the spacing units covering undeveloped or unearned Tribal acres, our rights to drill on such acreage will expire. The Exploration and Development Agreements (“EDAs”) with the Tribe require a payment to extend the exclusive right to drill on the acreage for an additional five years. In addition, the Tribal EDAs contain minimum annual drilling commitments to maintain the exclusive right to drill on the acreage during the terms of the EDAs.

As of December 31, 2011, we had leases on fee, state, federal and allotted lands representing 2,799 net acres expiring in 2012, 6,504 net acres expiring in 2013 and 10,097 net acres expiring in 2014. Unless production is established within the spacing units covering the undeveloped acres on these properties, the leases for such acreage will expire. Any renewal of such leases could require us to make significant expenditures, and the cost to renew these leases may increase significantly. We may not be able to renew all such leases on commercially reasonable terms or at all.

If we fail to drill wells or establish production sufficient to maintain our acreage, then our actual drilling activities may materially differ from those presently identified, which could have a material adverse effect on our business, financial condition and results of operations.

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

Approximately 76% of our total proved reserves were classified as proved undeveloped as of December 31, 2011. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the 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.

There is limited transportation and refining capacity for our yellow and black wax crude oil, which may limit our ability to sell our current production or to increase our production.

The crude oil we produce in the Uinta Basin is known as yellow wax or black wax because it has a high paraffin content. Due to its high parrafin content, our transportation options are limited, and most of the oil is transported by truck to refiners in the Salt Lake City area. Our inability to obtain transportation or refining services or a failure to obtain such services on acceptable terms could limit our ability to sell our current production or increase our production, which could have a material adverse impact on our financial condition and results of operations.

We are party to agreements with one area marketer and one area refiner that provide reasonable certainty of base load sales of our production on our operated acreage in Randlett through November 2012 and a portion of our operated acreage through 2014. Our production on the acreage acquired in the Horseshoe Bend acquisition is sold under arrangements in place at the time of the acquisition that expire in May 2012. However, there is a risk that the purchasers party to the various marketing arrangements regarding our operated production may fail to satisfy their obligations to us under these arrangements. In addition, we sell our non-operated production through our operating partners under their marketing and transportation arrangements. Any delays in payments from the purchasers of our crude oil will have an immediate impact on our cash flows. Additionally, if we are unable to market our production for any extended period of time, we may be required to shut in wells, and if our production becomes shut-in, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market. We continue to work with refiners, marketers and our operating partners to expand the market for our existing yellow and black wax crude oil production and to expand the market to allow for production growth. However, without additional refining capacity, our ability to increase production from the Uinta Basin may be limited.

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

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

The process of estimating oil and natural gas reserves is complex. It requires analysis of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these analyses or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. Please read “Business—Our Operations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2011.

To prepare our estimates, we must project production rates and the timing of development expenditures. We also must analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of funds. There are numerous

uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production. In addition, this data with respect to our operated acreage is based on vertically drilled wells, which may not accurately reflect production, development or operating expenditures that may result from the utilization of horizontal drilling techniques.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant negative variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our developed acreage, the estimates of future production associated with our undeveloped properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

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 new credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our new credit facility and our results of operations for the periods in which such charges are taken.

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 SEC requirements for the years ended December 31, 2009, 2010 and 2011, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

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actual prices we receive for oil and natural gas;

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actual cost of 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 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 $1.00 per Bbl, then our PV-10 and Standardized Measure as of December 31, 2011 would decrease approximately $13.9 million, or 2.5%. If natural gas prices decline by $0.10

per Mcf, then our PV-10 and Standardized Measure as of December 31, 2011 would decrease approximately $1.1 million, or 0.2%.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This new requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

A majority of our oil and gas properties are located on the Uintah and Ouray Reservation (the “Reservation”). Operation of oil and gas interests on Native American tribal lands presents unique considerations and complexities that arise from the fact that Native American tribes are “dependent” sovereign nations located within states but are subject only to tribal laws and treaties with, and the laws and Constitution of, the United States. This creates an overlay of three jurisdictional regimes—Native American, federal and state. These considerations and complexities could arise around various aspects of our operations, including real property considerations, permitting, employment practices, environmental matters and taxes.

For example, we are subject to the Ute Tribal Employment Rights Ordinance (the “Employment Act”). The Employment Act requires that we give preference in hiring to members of the Tribe meeting job description requirements, which may sometimes require us to forego offering positions to individuals that are otherwise more qualified. The Employment Act also requires us to give preference to businesses owned by members of the Tribe when we are hiring contractors. These regulatory restrictions can negatively affect our ability to recruit and retain the most highly qualified personnel or to utilize the most experienced and economical contractors for our projects.

Furthermore, because Tribal property is considered to be held in trust by the federal government, before we can take actions such as drilling, pipeline installation or similar actions, we are required to obtain approvals from various federal agencies, including the Bureau of Indian Affairs and the Bureau of Land Management. We are also required to obtain approvals from the Tribe for surface use access on certain of our properties. Gaining these approvals could result in delays in implementation of, or otherwise prevent us from implementing, our development program.

For additional information about the legal complexities and considerations associated with our operations on the Reservation, please read “Business—Laws and Regulations Pertaining to Oil and Gas Operations on the Uintah and Ouray Reservation.”

Our operations are subject to various Native American tribal, federal and state environmental and operational safety laws and regulations that may expose us to significant costs, liabilities and delays.

Our oil and natural gas exploration and production operations occur largely on Tribe Reservation lands and, to a lesser extent, federal, state or private lands located outside those Reservation lands. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management and the Office of Natural Resources Revenue, may promulgate and enforce laws, regulations and/or

other approval requirements addressing environmental conditions and pertaining to oil and natural gas operations on Tribe Reservation lands.

In addition, our oil and natural gas exploration and production operations, particularly those located outside the Tribe Reservation lands, may be subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of a permit before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and waste water discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Part of the regulatory environment in which we operate imposes, under certain circumstances, federal requirements to perform or prepare environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to state regulation of oil and natural gas production and Native American tribe conservation practices and protection of correlative rights. These added requirements may restrict our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from federal, state, local and/or Tribal authorities. Failures or delays in obtaining regulatory approvals or drilling permits or the receipt of a permit with extensive restrictions or requiring the incurrence of significant costs could have a material adverse effect on our ability to explore on or develop our properties. In addition, if we reasonably believe that we cannot obtain required drilling permits covering locations for which we recorded proved undeveloped reserves in a timely manner, we may be required to write down the level of our proved reserves.

Our ability to enforce our rights against the Tribe is limited by the sovereign immunity of the Tribe.

Although the Tribe has sovereign immunity and generally may not be sued without its consent, a limited waiver of sovereign immunity and consent to suit has been granted in connection with the Tribe’s EDAs with us.

These waivers were subject to various United States governmental approvals, which we believe have been obtained. If any waiver of sovereign immunity with us is held to be ineffective, including as a result of failing to obtain appropriate federal governmental approvals, we could be precluded from judicially enforcing our rights and remedies against the Tribe. In addition, some of the EDAs provide that the limited waiver of sovereign immunity is only enforceable for a period of six months following the termination of the EDAs.

Obtaining jurisdiction over a Native American tribe, such as the Tribe, can be difficult. Often, a commercial dispute with a Native American tribe or tribal instrumentality cannot be heard in federal court because the typical requirements for federal jurisdiction are absent. It is possible that neither a federal nor a state court would accept jurisdiction to resolve a matter involving a commercial dispute between us and the Tribe, and no legal recourse to a state or federal court may be available to us. Pursuant to the waivers of sovereign immunity we have obtained from the Tribe, the Tribe has waived its rights to have certain matters resolved in any Tribal court or other proceeding of the Tribe. The Tribe has a Tribal court system, and a federal or state court may defer to such Tribal courts if, contrary to the waivers of sovereign immunity by the Tribe, the Tribe seeks or alleges its right to seek Tribal proceedings for resolution of a dispute. The Tribal courts may not reach the same conclusions that would be reached in state or federal courts.

Additionally, any state or federal court judgment requiring satisfaction or enforcement within Tribal territories may require that an order for such enforcement be issued by Tribal courts. Tribal courts do not have specific rules related to granting full faith and credit to judgments of courts of the United States or any state, except in limited circumstances.

A significant reduction by the Tribe of their ownership interests in us could adversely affect us.

The Tribe is our largest stockholder. We believe that the Tribe’s substantial investment in us provides us with a significant competitive advantage in securing drilling and operating permits on Tribal lands and otherwise working with government entities with oversight authority for oil and natural gas exploration and production on Tribal lands. Following the 180th day after the closing of this offering, however, the Tribe will not be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If the Tribe sells all or a substantial portion of its ownership interest in us, the Tribe may have less incentive to assist in our success. A lack of assistance from the Tribe could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

All of our producing properties and operations are located in the Uinta Basin region, making us vulnerable to risks associated with a lack of geographic diversification.

As of December 31, 2011, all of our proved reserves and production were located in the Uinta Basin in northeastern Utah. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells 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 the Uinta Basin, 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. For more information, please read “—There is limited transportation and refining capacity for our yellow and black wax crude oil, which may limit our ability to sell our current production or to increase our production.”

We are not the operator on a significant portion of our identified gross potential 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 any non-operated assets.

We are not the operator on approximately 67% of our identified gross potential drilling locations (approximately 44% of our identified net potential drilling locations). As a result, we may have limited ability to exercise influence over the operation of the drilling locations or subsequent production with respect to wells operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells;

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selection of technology; and

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the rate of production of reserves, if any.

This limited ability to exercise control over the operations of a majority of our identified potential drilling locations may cause a material adverse effect on our results of operations and financial condition.

We have a limited history of operating our drilling locations and may be unable to realize our target returns on the drilling locations that we operate.

Historically, we have not operated our drilling locations. As a result of our limited history as an operator, we may incur higher costs related to the drilling, completion and operation of wells on the drilling locations that we operate as compared to larger, more experienced operators. Our inability to effectively and efficiently operate the drilling locations on which we are the operator could have a material adverse effect on our financial condition, results of operations and reserves.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel. In addition, because we are a relatively small company, we may be disproportionately affected by adverse operational, financial and other events in the ordinary course of our business.

Our ability to acquire additional oil and natural gas properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring oil and natural gas properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. As a relatively small oil and natural gas company, many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. In addition, these companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective oil and natural gas properties, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

Furthermore, events that would not significantly impact the business of larger companies may have a material adverse effect on our business, financial condition and results of operations. For example, larger

companies may be better able to withstand the financial pressures of unsuccessful drilling attempts, operational incidents, customer loss, and sustained periods of volatility in financial markets, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, all of which could adversely affect our business, financial condition and results of operations.

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

We utilize third-party services to maximize the efficiency of our operations. The cost of oilfield services may increase or decrease depending on the demand for services by other oil and gas companies. While we currently have good working relationships with oilfield service companies, we cannot assure you that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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

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

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

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abnormally pressured formations;

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

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fires, explosions and ruptures of pipelines;

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personal injuries and death; and

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natural disasters.

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

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injury or loss of life;

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

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pollution and other environmental damage and associated clean-up responsibilities;

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regulatory investigations, penalties or other sanctions;

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suspension of our operations; and

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repair and remediation costs.

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

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Uinta Basin are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. These limitations restrict our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.

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.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment. Based on these findings, the EPA began adopting and implementing regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another which requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. On May 12, 2010, the EPA also issued a new “tailoring” rule, which makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. On September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. In addition, on November 30, 2010, the EPA published a final rule that expands its existing GHG emissions reporting rule to include certain owners and operators of onshore oil and natural gas production to monitor GHG emissions beginning in 2011 and to report those emissions beginning in 2012. We are currently conducting monitoring of GHG emissions from our operations in accordance with the GHG emissions reporting rule but must evaluate the data from those monitoring activities to determine whether we exceed the threshold level of GHG emissions triggering a reporting obligation. To the extent we exceed the applicable regulatory threshold level, we will report the emissions beginning in 2012. Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur significant costs to reduce emissions of GHGs associated with operations or could adversely affect demand for our production.

Adoption and/or implementation of new air emissions restrictions in the Uinta Basin could result in increased operating costs and limits on the development of wells in the basin.

On July 1, 2011, the EPA promulgated a final Federal Implementation Plan (“FIP”) that implements federal New Source Review (“NSR”) pre-construction air pollution control requirements for facilities emitting pollutants in Indian Country. The FIP establishes two rules to protect air quality in Indian lands. The first rule is the Minor NSR rule, which applies to new and modified minor stationary sources and to minor modifications at existing major stationary sources found on Indian lands. The second rule is the Non-Attainment Major NSR rule, which applies to new and modified major stationary sources in areas of Indian lands that do not meet National Ambient Air Quality Standards (“NAAQS”) established by the EPA under the federal Clean Air Act. Under the rules, a source owner or operator will need to apply for a permit before building a new facility or expanding an existing one if the facility increases emissions above applicable limits included in the rules. The permitting authority, which may be the EPA or a tribe (should the tribe accept delegation of the federal program or develop and implement an EPA-approved Tribal Implementation Plan), will review the application and grant or deny the air emissions permits. These permits will undergo public notice and comment as part of the review process. With regard to our operations upon the Reservation, promulgation of the FIP and establishment of the two permit

programs will require us to acquire air emissions permits prior to well construction, which could result in delays in siting and development of wells and increase the costs of development and production although, at this point, we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities on Indian lands.

In addition, the EPA and several other agencies are pursuing or planning to pursue monitoring studies to assess elevated levels of wintertime ground-level ozone found in the recent past in the Uinta Basin. Ground-level ozone, a gas that is created by a chemical reaction between nitrogen oxides and volatile organic compounds in the presence of sunlight, is one of six criteria pollutants regulated by the EPA under the NAAQS. Ambient concentrations of ground-level ozone were measured in the Uinta Basin between January and March 2010 at levels in excess of the NAAQS of 75 parts per billion for an eight-hour average established by the EPA in 2008. No final determination has been made for the occurrence of elevated concentrations of ozone in the Uinta Basin during the wintertime but a contributing factor could be oil and gas production in the region. The EPA, Utah Department of Environmental Quality, U.S. Fish & Wildlife Service and the federal Bureau of Land Management, among other agencies, are pursuing or are planning to pursue, individually or collectively, long-term wintertime monitoring for ozone and key “precursors” to the chemical formation of ground-level ozone in the Uinta Basin. Any determinations made that emissions from oil and gas development in the Uinta Basin is adversely contributing to air quality in the Uinta Basin, including formation of ground-level ozone at levels in excess of the applicable NAAQS, could result in the adoption and implementation of restrictive federal, state, regional or local requirements relating to current or future oil and gas development in the basin, which restrictions may include increased costs to install added air pollution control equipment and the possibility of partial or total delays or bans in such developmental activities in certain areas of the basin.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We anticipate that most, if not all, of the wells we plan to drill will involve hydraulic fracturing of the producing formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S.

Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the U.S. Securities & Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

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

The Budget for Fiscal Year 2013 sent to Congress by President Obama on February 13, 2012, contains recommendations that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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

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

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recoverable reserves;

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future oil and natural gas prices and their appropriate differentials;

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development and operating costs; and

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potential environmental and other liabilities.

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

able to fulfill its contractual obligations. Problems with properties we acquire could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

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challenge of attracting and retaining personnel associated with acquired operations.

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

Many of the anticipated benefits of significant acquisitions, such as the Horseshoe Bend acquisition, may not be realized. If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

We acquired significant assets in connection with the Horseshoe Bend acquisition with the expectation that the acquisition would result in various benefits, including, among other things, an increase in reserves, producing wells, and operated assets and diversification of our properties. However, the success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with our existing operations. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from a significant acquisition, such as the Horseshoe Bend acquisition, our results of operations may be adversely affected.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring new oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of experienced oil and gas lease field landmen who examine records in the county courthouse or the appropriate governmental office to determine mineral ownership before we acquire an oil and gas lease covering a specific mineral interest.

Prior to the drilling of an oil or gas well, it is the normal practice in our industry for the operator of the well to obtain a drilling title opinion from a qualified title attorney to ensure there are no obvious title defects on the property on which the well is to be located. The title attorney will research all documents that are of record, including liens, taxes and all applicable contracts that burden the property. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to completely cure any title defects may invalidate our title to the property and adversely impact our ability in the future to increase production and reserves. Additionally, because a less strenuous title review is conducted on lands where a well has not yet been scheduled, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we could suffer a financial loss.

We have incurred losses from operations during certain periods since our inception and may do so in the future.

We incurred a net loss of $4.0 million for the year ended December 31, 2009. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

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

To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Joseph N. Jaggers, our President and Chief Executive Officer and other members of our senior management team, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We expect to record a 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.

We expect to record a substantial non-cash compensation expense with respect to certain of our Management Incentive Units that will have vested by the time of this offering. Please read “Executive Compensation and Other Information—Components of our Executive Compensation Program—Long-term incentives” and Note 9 to our audited financial statements for more information regarding our Management Incentive Units. We estimate that this expense will be approximately $ million in the quarter in which this offering is consummated. We may 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. If our board elects to exercise this option upon the consummation of this offering, we estimate that up to approximately $ 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 cannot determine the actual amount of these new stock-related compensation and benefit expenses at this time because applicable accounting practices generally require that they be based on the fair market value of the options or shares of common stock at the date of the grant; however, we expect them to be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

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

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the 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 a 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 arrangements also expose us to the risk of financial loss in certain other circumstances, including when:

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

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

In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements. 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 adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use commodity derivative contracts to reduce the effect of commodity prices, interest rates and other risks associated with our business.

The United States Congress adopted comprehensive financial reform legislation in 2010 that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the legislation. In December, 2011, the CFTC extended temporary exemptive relief from deadlines for the promulgation of certain regulations applicable to swaps until no later than July 16, 2012. The CFTC recently promulgated regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when these regulations will become effective. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivatives activities, although the application of those provisions is uncertain at this time. The legislation may also require the counterparties to our commodity derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with capital requirements, which could result in increased costs to counterparties such as us.

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

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, increases in interest rates or a reduction in credit rating. 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.

We expect to enter into a new credit facility upon the completion of this offering, which will contain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

We expect to enter into a new credit facility upon the completion of this offering, which will contain covenants that will, among other things, restrict:

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our investments, loans and advances and the payment 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 our new credit facility and certain permitted liens;

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

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

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

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our capital expenditures.

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

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

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

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

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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 will 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 may 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 our borrowing base 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 and natural gas 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.

The borrowing base under our new credit facility will be subject to periodic redeterminations, and the borrowing base could be reduced in the future if commodity prices decline, which will limit our available funding for exploration and development.

The borrowing base under our new credit facility will be re-determined from time to time by our lenders according to the terms of our new credit facility. The lenders will re-determine the borrowing base based on an engineering report with respect to our oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time. In the future, we may not be able to access adequate funding under our new credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. If oil and natural gas commodity prices materially deteriorate or our estimated oil reserves decline, we anticipate that the revised borrowing base under our new credit facility may be reduced. As a result, we may be unable to obtain adequate funding under our new credit facility or even be required to pay down amounts outstanding under our new credit facility to reduce our level of borrowing. If funding is not available when needed, or is available only on unfavorable terms, our exploration and development plans as currently anticipated and our ability to make new acquisitions could be adversely affected, each of which could have a material adverse effect on our production, revenues and results of operations.

Our obligations under our new credit facility will be secured at all times by substantially all of our assets.

Our obligations under our new credit facility will be secured by substantially all of our assets. Therefore, a default by us on any of our obligations under our new credit facility could result in our lenders foreclosing on our assets or otherwise being entitled to revenues generated by and through our assets.

Risks Related to the Offering and our Common Stock

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid 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, the selling stockholders and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting (Conflicts of Interest)” beginning on page 136 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 identified potential 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, the selling stockholders or other stockholders, or the perception that such sales may occur;

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general market conditions, including fluctuations in commodity prices; and

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

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

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

Based on an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the pro forma as adjusted net tangible book value per share of common stock from the initial public offering price, and our pro forma as adjusted net tangible book value as of December 31, 2011 after giving effect to this offering would be $ per share. Please read “Dilution” for a complete description of the calculation of net tangible book value.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. The JOBS Act contains provisions that, among other things, relax certain reporting requirements for

“emerging growth companies,” including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise, (4) provide certain disclosure regarding executive compensation required of larger public companies, (5) hold shareholder advisory votes on executive compensation or (6) obtain shareholder approval of previously unapproved golden parachute payments in connection with proposed merger and sale transactions.

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

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC 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 (“Section 404”) 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;

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

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establish an investor relations function.

Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we may 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. Furthermore, while we generally must comply with Section 404 of the Sarbanes-Oxley Act of 2002 for our fiscal year ending December 31, 2013, we are not required to have our independent public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2017.

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. Further, our efforts may not enable us to avoid potential material weaknesses or significant deficiencies in the future. Any failure to prevent 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 do not intend to pay, and we anticipate our new credit facility will restrict us 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 stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we expect that the new credit facility that we expect to enter into upon the completion of this offering will place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us 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.

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 outstanding shares of common stock. This number includes shares that we and the selling stockholders are selling in this offering (assuming no exercise of the underwriters’ option to purchase additional shares), which may be resold immediately in the public market. Following the completion of this offering, the selling stockholders will own shares, or approximately % of our total outstanding shares, and certain of our affiliates will own shares, or approximately % of our outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. The selling stockholders are each party to a Stakeholders’ Agreement with us that will become effective upon the completion of this offering and will require us to effect the registration of the selling stockholders’ shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. For more information, please read “Certain Relationships and Related Party Transactions—Stakeholders’ Agreement.” The holders of the remaining shares and a small portion of shares owned by our affiliates which will be distributed to non-officer employees and other non-affiliates totaling up to approximately shares, or approximately % of our outstanding shares, are not subject to lock-up agreements and, subject to compliance with Rule 144 under the Securities Act, may sell such shares into the public market.

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 shares of our common stock issued or reserved for issuance under

our stock incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under this registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or 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.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•

limitations on the removal of directors;

•

limitations on our stockholders’ ability to amend our certificate of incorporation and bylaws, which provide that while the Tribe and Quantum collectively own more than 50% of our outstanding common stock, the affirmative vote of holders of a majority of our then outstanding common stock is required to amend our certificate of incorporation and bylaws, and that after such time the affirmative vote of holders of two-thirds of our then outstanding common stock is required to amend our certificate of incorporation and bylaws;

•

no ability for stockholders to call special meetings, provided that while the Tribe and Quantum collectively own more than 50% of our outstanding common stock, special meetings may be called at the request of holders of record of a majority of the outstanding shares of common stock; and

•

advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

Upon completion of this offering (assuming no exercise of the underwriters’ option to acquire additional shares of common stock), we anticipate that the Tribe and Quantum will initially own up to approximately % and %, respectively, of our outstanding common stock (based on an assumed initial public offering price of $ per share, the midpoint of the price range set forth on the cover of this prospectus).

In addition, we have entered into a Director Designation Agreement with the Tribe and Quantum that will permit the Tribe and Quantum to designate two of our initial four directors and three of the remaining four directors that the Director Designation Agreement contemplates will be added to our board of directors within one year of the closing of this offering. Thereafter, the Director Designation Agreement provides that the Tribe will be entitled to designate three directors, two of whom must meet the independence standards of the New York Stock Exchange and Quantum will be entitled to designate two directors, one of whom must meet the independence standards of the New York Stock Exchange. If either

the Tribe or Quantum owns less than 25% of our outstanding common stock, the number of directors they can designate will be reduced by one, and if either of the Tribe or Quantum owns less than 10% of our outstanding common stock their right to designate directors will lapse. In addition, the Director Designation Agreement provides that our board of directors will nominate Joseph N. Jaggers, our chief executive officer, to one of the initial board seats. For more information, please read “Certain Relationships and Related Party Transactions—Director Designation Agreement.”

Consequently, each of the Tribe and Quantum will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership and right to designate director nominees will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Quantum and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Quantum is a private equity firm that has invested in, among other things, companies in the energy industry. As a result, the existing and future portfolio companies which Quantum controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

We have also renounced our interest in certain business opportunities. Please read “—Our certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.”

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

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

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

•

business strategy;

•

reserves;

•

technology;

•

cash flows and liquidity;

•

financial strategy, budget, projections and operating results;

•

oil and natural gas realized prices;

•

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

•

availability of drilling and production equipment;

•

availability of oil field labor;

•

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

•

availability and terms of capital;

•

drilling of wells;

•

competition and government regulations;

•

marketing of oil and natural gas;

•

exploitation or property acquisitions;

•

costs of exploiting and developing our properties and conducting other operations;

•

general economic conditions;

•

competition in the oil and natural gas industry;

•

effectiveness of our risk management activities;

•

environmental liabilities;

•

counterparty credit risk;

•

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

•

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

•

uncertainty regarding our future operating results;

•

estimated future net reserves and present value thereof; and

•

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

All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

USE OF PROCEEDS

We will receive net proceeds of approximately $ million from the sale of the common stock offered by us, assuming an initial public offering price of $ 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 $ million (or approximately $ million if the underwriters’ option to purchase additional shares is exercised in full). We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders.

Immediately prior to the closing of this offering, we intend to assume approximately $ million in aggregate principal amount of the outstanding loans under our parent’s credit facilities, and we will use a portion of the net proceeds from this offering to repay in full such assumed debt at the closing of this offering. The remaining net proceeds of approximately $ million (or approximately $ million if the underwriters’ option to purchase additional shares is exercised in full) will be used to fund a portion of our $281 million budget for drilling and completion costs during 2012. We intend to use cash generated from operations and borrowings under our new credit facility to fund the remainder of our 2012 budget for drilling and completion costs and for other capital expenditures, including strategic infrastructure, maintaining leasehold positions and for general corporate purposes, such as facilities costs. The amount and allocation of capital we spend may fluctuate materially based on drilling results, market conditions and drilling permit availability. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We intend to apply the net proceeds from this offering in the following manner:


Use of Proceeds		Amount (in millions)
Repayment of allocated portion of our parent’s senior secured revolving credit facility		$
Repayment of allocated portion of our parent’s second lien credit facility
Payment of portion of 2012 budget for drilling and completion costs

Total		$

Our parent’s revolving credit facility matures in May 2016 and bears interest at a variable rate of LIBOR plus 2.00 to 3.00% per annum. The allocated portion of the debt borrowed by us under our parent’s revolving credit facility had a weighted average interest rate of approximately 2.99% as of June 12, 2012 and was used for drilling and operating expenses, acquisitions and general corporate purposes. Our parent’s second lien credit facility matures in November 2016 and bears interest at a variable rate of LIBOR plus 7.00% per annum with a minimum LIBOR floor of 1.50%. The allocated portion of the debt borrowed by us under our parent’s second lien credit facility had a weighted average interest rate of 8.50% as of June 12, 2012 and was used for drilling and operating expenses, acquisitions and general corporate purposes. For more information regarding our parent’s credit facilities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital resources” beginning on page 66 of this prospectus.

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, after deducting estimated expenses and underwriting discounts and commissions, to increase or decrease by approximately $ million. If our net proceeds are reduced, then we will have fewer proceeds with which to fund our 2012 budget for drilling and completion costs and may not have sufficient funds to pay off the debt assumed from our parent. If we do not raise sufficient funds to pay off the debt assumed from our parent, we will have to borrow funds under our new revolving credit facility, which will increase our interest expense, decrease our net income and reduce the amount available for future borrowing under our new revolving credit facility.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. In addition, we anticipate that our new credit facility will restrict the payment of dividends on our common stock. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities.

CAPITALIZATION

The following table sets forth our capitalization as of March 31, 2012,

on an actual basis;

on an as adjusted basis to give effect to the transactions described under “Summary—Corporate Reorganization”; and

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

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


	As of March 31, 2012
	Actual		As Adjusted	As Further Adjusted
	(In thousands)
Cash and cash equivalents(1)(2)	$	1,328	$	$

Long-term debt, including current maturities:
Our parent’s senior secured revolving credit facility(3)	$	102,600	$	$
Our parent’s second lien credit facility		50,000
Ute Energy Corporation revolving credit facility(4)		—

Total long-term debt(4)		152,600

Owner’s / stockholders’ equity:
Capital contributions		188,268
Common stock, $0.01 par value; no shares authorized, issued and outstanding (actual); shares authorized (as adjusted and as further adjusted); shares issued and outstanding (as adjusted); shares issued and outstanding (as further adjusted)		—
Preferred stock, $0.01 par value; no shares authorized (actual); shares authorized (as adjusted and as further adjusted); no shares issued and outstanding		—
Additional paid-in capital		—
Retained earnings (accumulated loss)(5)		—

Total owner’s / stockholders’ equity		188,268

Total capitalization	$	340,868	$	$

(1)	As of June 12, 2012, our cash and cash equivalents were $4.0 million.

(2)

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) our as further adjusted cash and cash equivalents by approximately $ , common stock by approximately $ , additional paid-in capital by approximately $ and total stockholders’ equity by approximately $ .

(3)	As of June 12, 2012, our parent had borrowed $165.0 million under its revolving credit facility, $143.8 million of which was used to fund our upstream operations.

(4)	We will enter into a new $500.0 million credit facility, approximately $150.0 million of which will be available for borrowing upon the completion of this offering.

(5)

In connection with our corporate reorganization, an estimated net deferred tax liability will be established for differences between the book and tax basis of our assets and liabilities, and a corresponding expense will be recorded to net income for accounting purposes. At March 31, 2012, the amount of this charge would have been $77.0 million.

DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of March 31, 2012, after giving pro forma effect to the transactions described under “Summary—Corporate Reorganization,” was approximately $ million, or $ per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering including giving effect to our corporate reorganization. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of March 31, 2012 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share equivalent to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to investors purchasing shares in this offering of $ per share. The following table illustrates the per share dilution to investors purchasing shares in this offering:


Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of March 31, 2012 (after giving effect to our corporate reorganization)	$
Increase per share attributable to new investors in this offering

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

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

The following table summarizes, on an as adjusted pro forma basis as of March 31, 2012, 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 investors in this offering at $ (the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus) calculated before deduction of estimated underwriting discounts and commissions:

Shares Acquired

Total Consideration

Average Price
Per Share

Number

Percent

Amount

Percent

Existing stockholders(1)

New investors(2)

Total

(1)	The number of shares disclosed for the existing stockholders includes shares being sold by the selling stockholders in this offering.

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

If the underwriters’ option to purchase additional shares from us is exercised in full, the number of shares of common stock held by new investors will be increased to shares, or % of the aggregate number of shares of common stock outstanding after this offering. The total consideration paid by our new investors would be $ million, or %, and the average price per share paid by new investors would be $ .

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

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

Set forth below is our selected historical and pro forma financial data as of and for the years ended December 31, 2007, 2008, 2009, 2010 and 2011 and the three months ended March 31, 2011 and 2012. The historical operations data for the years ended December 31, 2008, 2009, 2010 and 2011 and the balance sheet data as of December 31, 2008, 2009, 2010 and 2011 are derived from the audited financial statements of Ute Energy Upstream Holdings LLC. Historical operations data for the three months ended March 31, 2011 and 2012 and balance sheet data as of March 31, 2011 and 2012 are derived from the unaudited financial statements of Ute Energy Upstream Holdings LLC. Although we were formed in 2008, we had no assets or operating activities until March 2010. In March 2010, our parent assigned all of its oil and gas participation rights and other oil and gas assets, except its ownership in Ute/FNR, LLC, as well as the related costs to us. Oil and gas assets subsequently acquired by our parent were also assigned to us. This transfer of interests was accounted for as a transaction between entities under common control which requires us to record the conveyances at our parent’s historical basis applied retrospectively to our financial statements of all prior periods beginning January 1, 2008. The financial statements as of and for the years ended December 31, 2010 and 2011 have been audited by KPMG LLP, an independent registered public accounting firm, and are included elsewhere in this prospectus. The financial statements for the year ended December 31, 2009 have been audited by Ehrhardt Keefe Steiner & Hottman PC, an independent registered public accounting firm, and are included elsewhere in this prospectus. The balance sheet data as of December 31, 2009 and the historical financial data as of and for the year ended December 31, 2008 are derived from the audited financial statements of Ute Energy Upstream Holdings LLC, which are not included herein. The historical financial data as of and for the year ended December 31, 2007 are derived from the audited financial statements of Ute Energy LLC, our predecessor, which are not included herein.


				Historical																		Pro Forma for the Year Ended December 31, 2011
	Predecessor			Ute Energy Upstream Holdings LLC
	Year Ended December 31,			Year Ended December 31,												Three Months Ended March 31,
	2007			2008			2009			2010			2011			2011			2012
																(Unaudited)						(Unaudited)
				(In thousands)
Statement of operations data:
Oil and gas revenue	$	1,635		$	14,319		$	10,025		$	38,756		$	88,451		$	14,795		$	39,618		$	97,172
Operating expenses:
Lease operating expenses		509			2,111			1,694			4,113			11,996			2,246			6,035			13,295
Production taxes		143			984			1,732			2,965			4,044			759			1,789			4,394
Gathering and transportation expenses		141			800			1,113			2,079			5,664			792			1,624			5,723
Depreciation, depletion and amortization		1,542			7,792			5,594			13,852			30,784			5,614			12,551			33,026
Exploration expenses		530			—			40			60			21			10			8			21
Impairment of oil and gas properties and dry hole expenses		1,119			1,354			—			—			1,092			—			173			1,092
General and administrative expenses		1,496			1,653			1,067			3,375			8,194			1,532			3,246			8,194

Total operating expenses	$	5,480		$	14,694		$	11,240		$	26,444		$	61,795		$	10,953		$	25,426		$	65,745

Income (loss) from operations		(3,845	)		(375	)		(1,215	)		12,312			26,656			3,842			14,192			31,427
Other income (expense):
Equity in earnings (losses) from Ute/FNR, LLC(1)		505			1,371			(725	)		23			—			—			—			—
Unrealized loss on derivative instruments		—			—			(936	)		(1,615	)		(2,382	)		(10,220	)		(18,636	)		(2,382	)
Realized gain (loss) on derivative instruments		271			—			(896	)		1,338			(201	)		(266	)		(2,210	)		(201	)
Interest expense		(1,012	)		(339	)		—			(439	)		(1,856	)		(270	)		(2,223	)		(1,856	)
Write-off of deferred debt issue costs		(215	)		—			(274	)		—			(814	)		—			—			(814	)
Interest and other income (expense)		60			76			38			35			—			—			—			—

Total other income (expense)		(391	)		1,108			(2,793	)		(658	)		(5,253	)		(10,756	)		(23,069	)		(5,253	)

Income (loss) before income taxes		(4,236	)		733			(4,008	)		11,654			21,403			(6,914	)		(8,877	)		26,174

Income tax expense(2)		—			—			—			—			—			—			—			(9,322	)

Net income (loss)	$	(4,236	)	$	733		$	(4,008	)	$	11,654		$	21,403		$	(6,914	)	$	(8,877	)	$	16,852


	Historical																					Pro Forma as of March 31, 2012
	Predecessor			Ute Energy Upstream Holdings LLC
	As of December 31,			As of December 31,												As of March 31,
	2007			2008			2009			2010			2011			2011			2012
																(Unaudited)						(Unaudited)
				(In thousands)
Balance sheet data:
Cash and cash equivalents	$	—		$	10		$	162		$	67		$	4,497		$	908		$	1,328		$	1,328
Total property and equipment, net		8,353			29,155			34,677			88,845			338,490			100,261			386,400			386,400
Total assets		28,348			47,783			53,690			99,661			365,297			110,239			411,322			416,457
Long-term debt		—			—			—			10,000			116,932			19,500			152,600			152,600
Total owner’s equity		25,078			40,605			47,882			66,655			193,767			60,875			188,268			111,298


	Year Ended December 31,									Three Months Ended March 31,
	2009			2010			2011			2011			2012
										(Unaudited)
	(In thousands)
Cash flow data:
Net cash provided by operating activities	$	128		$	22,467		$	62,935		$	8,769		$	15,182
Net cash used in investing activities		(11,261	)		(54,342	)		(266,783	)		(18,414	)		(56,315	)
Net cash provided by financing activities		11,285			31,780			208,278			10,485			37,964


	Year Ended December 31,						Three Months Ended March 31,				Pro Forma for the Year Ended December 31, 2011
	2009		2010		2011		2011		2012		Pro Forma for the Year Ended December 31, 2011
							(Unaudited)				(Unaudited)
	(In thousands)
Other financial data:
Adjusted EBITDAX(3)	$	2,798	$	27,585	$	58,352	$	9,200	$	24,714	$	65,365

(1)

Reflects equity investment income (loss) of our parent resulting from its equity investment in Ute/FNR for the years ended December 31, 2007, 2008, 2009 and 2010. Our parent’s interest in Ute/FNR has not been contributed to us, and we do not expect to own an interest in Ute/FNR upon the consummation of this offering. The exclusion of our parent’s interest in Ute/FNR from our business is reflected as a distribution to our parent of this interest in March 2010 following the contribution to us by our parent of its other upstream operations in existence at that time. Our parent’s interest in Ute/FNR is not reflected in our financial statements for periods ending after December 31, 2010. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Basis of Presentation” for more information regarding our accounting treatment of our parent’s equity investment in Ute/FNR.

(2)

(3)	Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our net loss and net cash provided by operating activities, please read “Summary Historical and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measure.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in the prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Please read “Cautionary Note Regarding Forward-Looking Statements” beginning on page 43 of this prospectus.

Overview

We are an independent oil and natural gas company engaged in the exploration, development, production and acquisition of oil and natural gas reserves with a primary focus on acquiring and developing oil reserves. All of our current acreage positions are concentrated in the Uinta Basin in northeastern Utah where we have accumulated approximately 165,608 net leasehold acres, approximately 94% of which are undeveloped. We are focused on the development of our significant inventory of identified potential drilling locations to grow our reserves, production and cash flow over time. We also seek high quality acquisitions and leasing opportunities with the potential for long-term drilling prospects that generate attractive rates of return.

Our parent company, Ute Energy LLC, was formed in 2005 by the Tribe to participate in the exploration and development of the Tribe’s mineral estate in the Uinta Basin. Prior to our formation in 2008, the Tribe contributed to our parent non-operated net acreage positions in the Lake Canyon, Wolf Flat, Blacktail Ridge and North Monument Butte project areas in exchange for its equity in our parent. Our parent subsequently entered into an Exploration and Development Agreement (“EDA”) for the Bridgeland project area in October 2008. We were formed by our parent to acquire all of our parent’s oil and natural gas participation rights under the EDAs relating to these project areas and to manage our oil and gas operations distinctly from our parent’s other energy investments. In March 2010, our parent assigned all of its oil and natural gas participation rights under the EDAs to us.

Since the assignment of the EDAs to us by our parent in March 2010, we entered into two EDAs where we have operated interests. In December 2010, we entered into an EDA for our operated Randlett project area for an initial lease bonus of $1.3 million, and in March 2011, we entered into an EDA for our Rocky Point project area, which we jointly operate with Newfield, for an initial net lease bonus of $1.5 million. The following table summarizes our core Tribal EDAs.


Tribal EDAs	Closing Date	Net Tribal Acres at Closing
Lake Canyon	May 4, 2005	31,198
Blacktail Ridge	February 23, 2007	25,714
North Monument Butte	February 23, 2007	11,725
Bridgeland	October 15, 2008	4,561
Randlett	December 27, 2010	17,181
Rocky Point	March 21, 2011	8,374

During 2010, we shifted our focus from participating primarily in non-operated positions to establishing a significant portfolio of operated acreage and growing our asset base primarily through operated drilling activities. Since our strategic shift, we have increased our operated acreage position in the Uinta Basin through an active leasing and acquisition program and we have balanced our portfolio of Tribal acreage with the addition of significant interests in fee, state, federal and allotted lands. We currently have operated acreage positions in the Randlett, Rocky Point and Horseshoe Bend project areas. We commenced operated drilling in Randlett in April 2011 and expect to commence operated drilling in Rocky Point and Horseshoe Bend in 2012. We believe that our shift to operated activities will enable us to better control timing, costs and drilling and completion techniques.

Our recent focus on establishing a significant portfolio of operated acreage and growing our asset base primarily through operated drilling activities has significantly impacted our business. As of December 31, 2011, we had 78,170 net operated acres, which represents 47% of our total net acreage position, and we have 68,041 net acres on fee, state, federal and allotted lands, which represents 41% of our total net acreage position. Our operated net acres increased 264% from December 31, 2010 to December 31, 2011. As of December 31, 2011, approximately 61% of our proved reserves and 70% of our PV-10 were in operated project areas while our operated acreage had no associated proved reserves as of December 31, 2010. For the month ended December 31, 2011, our operated production contributed 43% of our total net production while we had no operated production prior to 2011.

We continue to derive substantial benefits from our non-operated positions throughout the Uinta Basin and expect to participate in active drilling on our non-operated acreage positions in the future. We believe our participation in non-operated project areas offers attractive return opportunities and enables us to gain additional exposure to emerging resource plays without committing all of the capital required to drill the wells during the early-stage testing and refinement of drilling and completion techniques. In addition, we believe that the knowledge and expertise gained through our non-operated positions will enhance our ability to continue efficiently growing our operated acreage positions. As of December 31, 2011, we had 87,438 net non-operated acres primarily in five core project areas.

Recent Acquisitions

During 2011, we completed two acquisitions and one election in an area of mutual interest (“AMI”), which increased our operated acreage position and diversified our acreage position with additional fee, state, federal and allotted acreage. The following table highlights our 2011 acquisitions as well as our Bridgeland AMI election.


Project Areas	Closing Date	Adjusted Purchase Price(1) (In millions)		Net Fee Acres at Closing(2)
Randlett	April 20, 2011	$	2.3		5,911
Bridgeland (AMI election)	June 15, 2011	$	12.1		3,964
Horseshoe Bend and Randlett	November 30, 2011	$	99.9		35,343

(1)	The purchase price for the Horseshoe Bend and Randlett acquisition that closed on November 30, 2011 remains subject to post-closing adjustments.

(2)	Net acres include fee, state, federal and allotted acreage.

Basis of Presentation

We were formed by our parent to acquire all of our parent’s oil and natural gas participation rights under the EDAs and to manage our oil and natural gas operations distinctly from our parent’s other energy investments. Although we were formed in 2008, we had no assets or operating activities until March 2010 when our parent assigned all of its oil and gas participation rights under its EDAs to us. The transfer of interests in the EDAs from our parent to us in March 2010 was accounted for as a transaction between entities under common control and

was retrospectively applied to our financial statements as of January 1, 2008. Prior to 2008, our parent’s upstream business was comprised of the EDAs and the related oil and gas activities conducted under them, which is considered to be our accounting predecessor.

The financial statements included elsewhere in this prospectus have been derived from the accounting records of our parent, principally representing our parent’s oil and natural gas exploration, development, production and acquisition activities. These allocations were based on what our parent considered to be reasonable reflections of the historical utilization levels of these services required in support of our business.

We believe the assumptions underlying the financial statements are reasonable. However, the financial statements may not necessarily reflect our future results of operations, financial position and cash flows or what our results of operations, financial position and cash flows would have been had we been a stand-alone company during the periods presented.

UTE/FNR equity investment. Ute/FNR, LLC (“Ute/FNR”) was formed in 2002 as a joint venture between the Tribe and FIML Natural Resources, LLC (“FIML”) with the Tribe holding a 33% membership interest in Ute/FNR and FIML, the managing member, owning a 67% membership interest in Ute/FNR. In connection with the formation of our parent in 2005, the Tribe contributed its 33% membership interest in Ute/FNR to our parent. Ute/FNR is accounted for as an equity method investment in our parent’s historical consolidated financial statements with our parent’s share of earnings and losses of Ute/FNR reflected as equity in earnings (losses) in other income (expenses) in its consolidated statements of operations. Our parent’s interest in Ute/FNR has not been contributed to us, and we do not expect to own an interest in Ute/FNR upon the consummation of this offering. Our parent’s investment in Ute/FNR is reflected in our statements of operations for the years ended December 31, 2009 and 2010 as an equity investment in Ute/FNR. The exclusion of our parent’s equity investment in Ute/FNR from our business is reflected as a distribution of this equity interest in March 2010 to our parent following our parent’s contribution to us of its other upstream operations in existence at that time. Our parent’s interest in Ute/FNR is not reflected in our financial statements for periods ending after December 31, 2010.

The statements of operations included elsewhere in this prospectus include allocations of costs for corporate functions historically provided to us by our parent, including:

General corporate expenses. Represents costs related to corporate functions such as accounting, tax, treasury, human resources and legal. Other corporate expenses include costs for leasehold expenses related to our corporate offices and general corporate overhead. These costs have been allocated primarily based on estimated use of services as compared to our parent’s other businesses. These costs are included in general and administrative expenses in the statement of operations.

Employee compensation and benefits. Represents compensation, payroll taxes and fringe benefit costs such as health insurance and employer matching on retirement plan contributions. These costs have historically been allocated primarily based on estimated time provided to our activities as compared to our parent’s other businesses. These costs are included in general and administrative expenses in the statement of operations, except for field personnel whose compensation and benefits generally are included in lease operating expense.

Our parent has provided financing to us through cash flows from its other operations, debt incurred and equity investments. The balance sheets and statements of operations included elsewhere in this prospectus include allocations for funding our operations and associated interest expense as follows:

Debt. Historically, we have used a combination of borrowings under a prior revolving credit facility maintained by us (“our prior revolving credit facility”) and proceeds from borrowings under our parent’s credit facilities to fund a portion of our operations. Please read “—Liquidity and Capital Resources—Capital resources” below. Immediately prior to the closing of this offering, we intend to assume the portion of the debt outstanding under our parent’s credit facilities that has been used to fund our operations, and we will use a portion of the net

proceeds from this offering to repay in full such assumed debt at the closing of this offering. Our balance sheet and pro forma condensed balance sheet as of December 31, 2011 include our portion of the debt outstanding under our parent’s credit facilities based on borrowings under those facilities that were used to fund our operations and acquisitions. Prior to the closing of this offering, we guarantee all of the indebtedness under our parent’s credit facilities.

Interest expense. Although the debt incurred by our parent was not allocated to us prior to December 31, 2011, a portion of the interest expense during those periods has been allocated to us based on certain borrowings at our parent’s average borrowing rates. In addition, we have recorded all interest expense related to our prior revolving credit facility. These expenses are included in other income (expense) in the statement of operations. In the remainder of this Management’s Discussion and Analysis of Financial Conditions and Results of Operations, references to “our interest expense” refer to the portion of our parent’s interest expense allocated to us.

Sources of our revenue

Oil, natural gas and natural gas liquids revenues. Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Substantially all of our production is derived from oil wells which also produce limited quantities of natural gas and natural gas liquids. The level of production of natural gas and natural gas liquids is a consequence of changes in our level of oil production. Our oil and natural gas revenues do not include the effects of derivatives, and may vary significantly from period to period as a result of changes in production volumes or commodity prices.

Commodity prices. Our revenues are heavily influenced by commodity prices. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and gas activities, commodity prices have experienced significant fluctuations. The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Uinta Basin. For a description of factors that may impact future commodity prices, please read “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business.”

A comparison of our quarterly average net realized oil prices to the NYMEX West Texas Intermediate (WTI) index prices is shown in the table below.


	Year Ended December 31, 2009		2010								Year Ended December 31, 2010		2011								Year Ended December 31, 2011		2012
	Year Ended December 31, 2009		Q1		Q2		Q3		Q4		Year Ended December 31, 2010		Q1		Q2		Q3		Q4		Year Ended December 31, 2011		Q1
NYMEX WTI	$	61.99	$	78.84	$	77.88	$	76.09	$	85.16	$	79.49	$	94.46	$	102.28	$	89.51	$	94.03	$	95.07	$	102.99
Average Realized Oil Prices ($/Bbl)(1)	$	47.86	$	67.26	$	67.34	$	63.56	$	69.63	$	66.89	$	78.41	$	86.55	$	75.31	$	80.42	$	79.88	$	87.70
Average Price Differential(2)		22.8%		14.7%		13.5%		16.5%		18.2%		15.9%		17.0%		15.4%		15.9%		14.5%		16.0%		14.8%

(1)	Realized oil prices do not include the effect of realized derivative contract settlements.

(2)	Price differential represents the difference between NYMEX West Texas Intermediate crude index price and our actual realized oil prices as a percentage of NYMEX West Texas Intermediate crude index prices.

Crude oil produced and sold in the Uinta Basin has historically sold at a discount to the price quoted by NYMEX for WTI crude oil. Most of the crude oil we produce in the Uinta Basin is known as black wax or yellow wax crude because it has higher paraffin content than crude oil found in most other major North American basins. Due to its high paraffin content, it must remain heated during shipping or be reheated at its destination, so our transportation options are more limited than those of producers in other basins. Currently, our oil production is transported by truck to refiners in the Salt Lake City area. In the past, there have been periods when the discount to the price quoted by NYMEX for WTI crude oil has substantially increased due to the production of oil in the Uinta Basin increasing to a level in excess of the available transportation, regional refining capacity or demand for refined products or due to market shocks. The last such period was late 2008 through early 2009, when oil prices declined significantly compounded by a decrease in regional demand for products refined from black and yellow wax crude. As a result, refiners had less demand for our type of production and the differential increased significantly.

Commodity derivatives. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, we generally enter into derivative arrangements for a significant portion of our crude oil and natural gas production. Please read “—Quantitative and Qualitative Disclosures About Market Risk—Commodity price exposure.” We utilize commodity derivatives to reduce our exposure to fluctuations in NYMEX WTI benchmark prices and, to a lesser extent, fluctuations in natural gas prices, including natural gas basis differentials. While these derivative contracts stabilize our cash flows when market prices are below our contract prices, they also prevent us from realizing increases in our cash flow when market prices are higher than our contract prices. We are unable to effectively hedge our oil differential between black or yellow wax crude oil and NYMEX WTI. We will sustain realized and unrealized losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain realized and unrealized gains to the extent our derivatives contract prices are higher than market prices. Our derivatives contracts are not designated as accounting hedges and, as a result, gains or losses on derivatives contracts are recorded as other income (expense) in our statements of operations. We view the settlement of such derivatives contracts as adjustments to the price received for natural gas, crude oil and natural gas liquids production to determine realized prices.

Principal components of our cost structure

Lease operating expenses. Lease operating expenses are daily costs incurred to bring oil and natural gas out of the ground, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, water hauling and disposal, utilities, maintenance, repairs and workover expenses related to our oil and natural gas properties. Water hauling and disposal is one of our largest operating costs as we produce significant amounts of water during the hydrocarbon recovery process. We pay third party vendors to transport water to an offsite disposal facility and pay a separate fee to dispose of the water in compliance with environmental regulations. Consequently, our water hauling and disposal costs are impacted primarily by the ratio of water to oil produced and the distance to a disposal facility.

Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (as opposed to hedged prices) or at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In general, the amount of production taxes we pay is based on oil and natural gas revenues generated from our production. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

Gathering and transportation expenses. Our oil and natural gas is sold under two types of agreements, both of which are commonly used in our industry. One is a sale at the wellhead where we receive a price, net of the transportation costs incurred by the purchaser. In this case, we record sales at the price received from the purchaser and no gathering and transportation costs are recognized. Under the other arrangement, our oil or natural gas is sold at a specific delivery point and we are charged transportation costs by the purchaser, which are deducted from our sales proceeds. In this case, we report revenue at the gross amounts we receive before taking into account transportation costs, which are reflected in our statements of operations as gathering and transportation expenses. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments, contain revenues that are reported under two separate bases. Under the first arrangement, we have a lower realized price and under the second arrangement we have higher operating costs, but they have a similar impact on operating income.

Depreciation, depletion and amortization (“DD&A”). Depreciation, depletion and amortization includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop our oil and natural gas properties. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate such costs to each unit of production using the units-of-production method. DD&A expense is separately computed for each project area. The capital expenditures for proved properties in each area compared to the proved reserves corresponding to each project area determine a weighted average DD&A rate for current production. We adjust future DD&A rates to reflect

changes in future capital expenditures and proved reserves in specific project areas. We do not include unproved properties in the DD&A calculation. We record depreciation expense on the cost of fixed assets related to our gathering infrastructure and other fixed assets based on their useful lives. DD&A includes accretion expense on our asset retirement obligations, which is recognized in connection with the accretion of the discounted liability over the remaining estimated economic life of the oil and gas property.

Exploration expenses. Exploration expenses consist of exploratory dry hole expenses and costs incurred in evaluating areas that are considered to have prospective oil and natural gas reserves, including costs for topographical, geological and geophysical studies, rights of access to properties and costs of carrying and retaining undeveloped properties, such as delay rentals.

Impairment of unproved and proved properties. These costs include unproved property impairment and costs associated with lease expirations. We also record impairment charges for proved properties if we determine that the carrying value of the properties exceeds estimated future cash flows from the properties. Please read “—Critical Accounting Policies and Estimates—Impairment of proved properties.”

General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our employees, costs of maintaining our corporate office and facilities, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance.

Other income (expense)

Equity in earnings (losses) from Ute/FNR, LLC. This line item represents our proportionate share of the earnings and losses from our parent’s investment in the membership interests of Ute/FNR, an equity method investment. This equity investment was distributed to our parent in March 2010.

Gains (losses) on commodity derivatives, net. Gains and losses on commodity derivatives represent (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivative contracts expire or new derivative contracts are entered into, and (ii) our realized gains and losses on the settlement of these commodity derivative contracts. We view the settlement of such derivatives contracts as adjustments to the price received for crude oil, natural gas and natural gas liquids production to determine realized prices. We classify these gains and losses as operating activities in our statements of cash flows.

Interest expense. Historically, we have financed a portion of our working capital requirements, capital expenditures and acquisitions with contributions made from borrowings under our parent’s credit facilities and our prior revolving credit facility. In the future, we expect to finance our operations with borrowings under our new credit facility in addition to cash generated from operations and proceeds from this offering. As a result, our interest expense is affected by both fluctuations in interest rates and our financing decisions. We record the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees as interest expense in our statements of operations. We capitalize a portion of our interest costs in unproved properties where significant development plans have commenced. We depreciate capitalized interest over the useful life of the assets in the same manner as the depreciation of the underlying assets.

Income tax expense. As of March 31, 2012, we were a limited liability company treated as a disregarded entity for federal income tax purposes. Accordingly, no provision for federal or state corporate income taxes has been provided for the three months ended March 31, 2012 or prior fiscal years because taxable income is allocated directly to our equity holders. In connection with the closing of this offering, we will convert into a corporation that will be subject to federal and state entity-level taxation. We will establish a net deferred tax liability for differences between the tax and book basis of our assets and liabilities, and we will record a corresponding “first day” tax expense to net income from continuing operations. At March 31, 2012, the amount of this charge would have been $77.0 million.

Factors That Significantly Affect Our Results

Our revenue, cash flows from operations, profitability and future growth depend substantially upon the prices and demand for crude oil, natural gas and natural gas liquids, the quantity of our crude oil, natural gas and natural gas liquids production and changes in the fair value of derivative instruments we use to reduce the volatility of the prices we receive for our crude oil, natural gas and natural gas liquids production. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas, or a significant increase in the differential between NYMEX WTI and the price for yellow and black wax crude, could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and the amount we can borrow under our new credit facility.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. Thus, an oil and natural gas exploration company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. We also evaluate secondary recovery techniques, such as waterflooding, to potentially enhance recoverable reserves. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on increasing production from our existing reserves, as well as deploying the capital necessary to add reserves through drilling and acquisitions. Our ability to make capital expenditures to increase production from our existing reserves and add reserves through drilling and acquisitions is dependent on our ability to access capital to fund our growth.

Items Impacting Comparability of Our Financial Results

As a result of our separation from our parent and our recent rapid growth through drilling activities, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.

Results of Operations

The following table summarizes our revenues, expenses and production data for the periods indicated.


	Year Ended December 31,									Three Months Ended March 31,
	2009			2010			2011			2011			2012
										(Unaudited)
	(In thousands, except for production and per unit data)
Revenues:
Oil	$	7,892		$	33,952		$	79,253		$	12,932		$	37,667
Natural gas		1,891			4,381			6,825			1,440			1,310
Natural gas liquids		242			423			2,373			423			641

Total oil and gas revenues		10,025			38,756			88,451			14,795			39,618

Operating expenses:
Lease operating expenses	$	1,694		$	4,113		$	11,996		$	2,246		$	6,035
Production taxes		1,732			2,965			4,044			759			1,789
Gathering and transportation expenses		1,113			2,079			5,664			792			1,624
Depreciation, depletion and amortization		5,594			13,852			30,784			5,614			12,551
Exploration expenses		40			60			21			10			8
Impairment of oil and gas properties and dry hole expenses		—			—			1,092			—			173
General and administrative expenses		1,067			3,375			8,194			1,532			3,246

Total operating expenses	$	11,240		$	26,444			61,795			10,953			25,426

Income (loss) from operations		(1,215	)		12,312			26,656			3,842			14,192
Other income (expense):
Equity in earnings (losses) from Ute/FNR, LLC	$	(725	)	$	23		$	—		$	—		$	—
Losses on commodity derivatives, net		(1,832	)		(277	)		(2,583	)		(10,486	)		(20,846	)
Interest expense		—			(439	)		(1,856	)		(270	)		(2,223	)
Write-off of deferred debt issue costs		(274	)		—			(814	)		—			—
Interest and other income		38			35			—			—			—

Total other income (expense)		(2,793	)		(658	)		(5,253	)		(10,756	)		(23,069	)

Net income (loss)	$	(4,008	)	$	11,654		$	21,403		$	(6,914	)	$	(8,877	)

Production data:
Oil (MBbls)		164.9			507.6			992.1			164.9			429.5
Natural gas (MMcf)		571.3			1,247.8			1,751.8			412.1			549.8
Natural gas liquids (MBbls)		6.2			7.6			33.7			6.4			8.5
Oil equivalents (MBoe)		266.3			723.1			1,317.8			240.0			529.6
Average daily production (Boe/d)		729			1,981			3,610			2,666			5,820
Average sales prices:
Oil, with realized derivatives ($/Bbl)	$	42.43		$	68.12		$	78.70		$	75.23		$	81.72
Oil, without realized derivatives ($/Bbl)		47.86			66.89			79.88			78.42			87.70
Natural gas, with realized derivatives ($/Mcf)		3.31			4.08			4.45			4.13			3.04
Natural gas, without realized derivatives ($/Mcf)		3.31			3.51			3.90			3.49			2.38
Natural gas liquids, without realized derivatives ($/Bbl)		39.03			55.66			70.42			66.09			75.41
Costs and expenses (per Boe of production):
Lease operating expenses	$	6.36		$	5.69		$	9.10		$	9.36		$	11.40
Production taxes		6.50			4.10			3.07			3.16			3.38
Gathering and transportation expenses		4.18			2.88			4.30			3.30			3.07
Depreciation, depletion and amortization		21.01			19.16			23.36			23.39			23.70

Three months ended March 31, 2012 as compared to three months ended March 31, 2011

Revenues

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids revenues increased $24.8 million, or 168%, to $39.6 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Average daily production increased by 3,154 Boe/d, or 118%, to 5,820 Boe/d for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The increase in average daily production was primarily due to the commencement of operated drilling activities in Randlett during the second quarter of 2011, our Horseshoe Bend acquisition in November 2011, and an increased drilling program by our operating partners in our non-operated project areas. Production in Randlett and Horseshoe Bend accounted for 2,407 Boe/d and 329 Boe/d of the increase, respectively, and production from our non-operated project areas, particularly Blacktail Ridge and Lake Canyon, accounted for the remaining increase. The higher production volumes contributed to $17.8 million of the revenue increase, and the remaining $7.0 million increase was attributable to an increase in realized commodity prices. Our period to period revenue increase was predominately driven by increases in crude oil production and realized crude oil prices, with 95% of revenue and 81% of production volumes attributable to crude oil for the three months ended March 31, 2012. Average oil sales prices, without realized derivatives, increased by $9.28 per barrel, or 12%, to an average of $87.70 per barrel for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.

Operating expenses

Lease operating expenses. Our lease operating expenses increased $3.8 million, or 169%, to $6.0 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. This increase was primarily due to the higher number of producing wells and increased production. On a per unit of production basis, lease operating costs increased by $2.04, or 22%, to $11.40 per Boe primarily due to higher per unit water hauling and disposal costs, equipment repairs and maintenance, and the Horseshoe Bend acquisition. Water hauling and disposal costs accounted for $0.51 of the increase in total per Boe lease operating expenses. For the three months ended March 31, 2012 as compared to the three months ended March 31, 2011, the ratio of water to oil produced increased 10%, while the per barrel cost of hauling and disposing water increased 17% due to rising fuel costs and some of our producing oil wells being located further from disposal facilities during the three months ended March 31, 2012. Increased water production also contributed to an increase in other operating costs, such as chemical expenses and purchased electricity for artificial lift. Higher equipment repairs and maintenance costs in Blacktail Ridge accounted for $0.51 of the increase in total per Boe lease operating expenses. The properties acquired in the Horseshoe Bend acquisition, which accounted for $0.48 of the increase in total per Boe lease operating expenses, had higher per unit lease operating expenses than our other project areas primarily due to fixed operating costs on older wells with low production, no new wells drilled since the acquisition, and equipment repairs and maintenance costs incurred to improve well performance.

Production taxes. Our production taxes increased $1.0 million, or 136%, to $1.8 million for the three months ended March 31, 2012, as compared to the three months ended March 31, 2011. On a per unit of production basis, production taxes increased by $0.22 per Boe, or 7%, to $3.38 per Boe for the three months ended March 31, 2012, as compared to the three months ended March 31, 2011. New wells qualify for severance tax exemptions on Tribal and state lands of twelve and six months, respectively. The increase in per unit production taxes was primarily due to higher unit costs in Bridgeland and North Monument Butte, with the expiration of prior tax exemptions and little new drilling activity during 2012, partially offset by lower per unit production taxes in project areas with active drilling during 2012, such as Blacktail Ridge and Randlett.

Gathering and transportation expenses. Our gathering and transportation expense increased $0.8 million, or 105%, to $1.6 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011, primarily due to increased production volumes. Gathering and transportation expense per unit, however, decreased $0.23 per Boe, or 7%, to $3.07 per Boe for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011, primarily due to the shift in production to our Randlett project area, which has lower gathering and transportation costs. These savings are offset, in part, by higher gas

gathering costs in Bridgeland and our entry into a new natural gas marketing agreement in 2012 for Blacktail Ridge that charges higher gathering costs.

Depreciation, depletion and amortization (“DD&A”). Our DD&A expense increased $7.0 million, or 124%, to $12.6 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The increase in the DD&A expense for the three months ended March 31, 2012 was due to increased production volumes. The DD&A rate remained fairly constant quarter over quarter. It increased $0.31 per Boe, or 1%, to $23.70 per Boe for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.

General and administrative expenses. Our general and administrative expenses increased $1.7 million, or 112%, to $3.2 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. This increase resulted primarily from compensation, benefits and other overhead associated with the addition of management, technical and accounting personnel in connection with the expansion of our operated drilling activities. As of March 31, 2012, we had 64 full-time employees compared to 32 employees as of March 31, 2011.

Other income (expense)

Gains (losses) on commodity derivatives, net. As a result of our derivative activities, we incurred cash settlement losses of $2.2 million the three months ended March 31, 2012 and cash settlement losses of less than $0.3 million for the three months ended March 31, 2011. In addition, as a result of forward oil price changes, we recognized $18.6 million of unrealized losses for the three months ended March 31, 2012 and $10.2 million of unrealized losses for the three months ended March 31, 2011.

Interest expense. Our interest expense increased $2.0 million to $2.2 million for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Interest costs increased in conjunction with higher borrowings to fund our development drilling program and acquisitions during the three months ended March 31, 2012.

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

Revenues

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids revenues increased $49.7 million, or 128%, to $88.5 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Average daily production increased by 1,629 Boe/d, or 82%, to 3,610 Boe/d for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in average daily production was primarily due to the commencement of operated drilling activities in Randlett during 2011 and an active drilling program by our operating partners in our non-operated project areas. Production in Randlett accounted for 667 Boe/d of the increase, and production from our non-operated properties, particularly Blacktail Ridge and North Monument Butte, accounted for the remaining increase. The higher production amounts contributed to $31.9 million of the revenue increase, and the remaining $17.8 million increase was attributable to an increase in realized commodity prices. Our period to period revenue increase was predominately driven by increases in crude oil production and realized crude oil prices, with 90% of revenue and 75% of production volumes attributable to crude oil for the year ended December 31, 2011. Average oil sales prices, without realized derivatives, increased by $12.99 per barrel, or 19%, to an average of $79.88 per barrel for the year ended December 31, 2011 as compared to the year ended December 31, 2010.

Operating expenses

Lease operating expenses. Our lease operating expenses increased $7.9 million, or 192%, to $12.0 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. This increase was primarily due to the higher number of producing wells as a result of the commencement of production in Randlett

and drilling activity in Blacktail Ridge and North Monument Butte. Per unit lease operating costs increased by $3.41, or 60%, to $9.10 per Boe primarily due to increased water production and the associated water hauling and disposal costs. The ratio of water to oil produced increased 29% in total, and 62% in Blacktail Ridge, from the year ended December 31, 2010 to the year ended December 31, 2011. The per barrel cost of hauling and disposing water also increased approximately 31% from the year ended December 31, 2010 as compared to the year ended December 31, 2011 due to rising trucking fuel costs and some of our producing oil wells being located further from disposal facilities than in previous years. Increased water production also contributes to higher other operating costs, such as chemical expenses and purchased electricity for artificial lift.

Production taxes. Our production taxes increased $1.1 million, or 36%, to $4.0 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Per unit production taxes, however, declined $1.03 per Boe, or 25%, to $3.07 per Boe for the year ended December 31, 2011 as compared to the year ended December 31, 2010 primarily due to increased drilling activity. New wells qualify for severance tax exemptions on Tribal and state lands of twelve and six months, respectively. As a result, new production is not subject to severance tax and yields a lower effective tax rate in periods of increasing production from new wells.

Gathering and transportation expenses. Our gathering and transportation expense increased $3.6 million, or 172%, to $5.7 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010, primarily due to increased production volumes. Gathering and transportation expense per unit increased $1.42 per Boe, or 49%, to $4.30 per Boe for the year ended December 31, 2011 as compared to the year ended December 31, 2010, primarily due to higher gas gathering costs in Bridgeland and our entry into a new natural gas marketing agreement in 2011 for Blacktail Ridge that charges higher gathering costs. The higher gathering cost in Blacktail Ridge is partially offset by increased revenue from sales of natural gas liquids, which our new natural gas marketing agreement allows us to capture.

Depreciation, depletion and amortization (“DD&A”). Our DD&A expense increased $16.9 million, or 122%, to $30.8 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in the DD&A expense for the year ended December 31, 2011 was due to both increased production volumes and an increase in the DD&A rate. Average daily production increased 82% for the year ended December 31, 2011 as compared to year ended December 31, 2010. The DD&A rate increased $4.20 per Boe, or 22%, to $23.36 per Boe for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in the DD&A rate was primarily due to higher rates in our Blacktail Ridge and Bridgeland project areas, partially offset by lower rates in our Randlett project area. Blacktail Ridge accounted for approximately $2.20 per Boe, or 52%, of the increase in the average DD&A rate due to an increase in capital expenditures without proportional associated proved developed reserve additions for the period. Our Bridgeland project area experienced gathering system constraints during 2011 which resulted in negative reserve revisions and accounted for $1.96 per Boe, or 47%, of the increase in the DD&A rate. We commenced drilling activities in our operated Randlett project area during 2011 which had a DD&A rate approximately 33% less than the average DD&A rate for the company for the year ended December 31, 2011.

General and administrative expenses. Our general and administrative expenses increased $4.8 million, or 143%, to $8.2 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. This increase resulted primarily from compensation, benefits and other overhead associated with the addition of management, technical and accounting personnel in connection with the expansion of our operated drilling activities. As of December 31, 2011, we had 56 full-time employees compared to 23 employees as of December 31, 2010.

Other income (expense)

Gains (losses) on commodity derivatives, net. As a result of our derivative activities, we incurred cash settlement losses of $0.2 million for the year ended December 31, 2011 and received cash settlement gains of $1.3 million for the year ended December 31, 2010. In addition, as a result of forward oil price changes, we recognized $2.4 million of unrealized losses for the year ended December 31, 2011 and $1.6 million of unrealized losses for the year ended December 31, 2010.

Interest expense. Our interest expense increased $1.4 million to $1.9 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Interest costs increased in conjunction with higher borrowings to fund our development drilling program and acquisitions during the year ended December 31, 2011.

Write-off of deferred debt issue costs. We expensed $0.8 million of deferred loan costs in the year ended December 31, 2011 when we refinanced our prior revolving credit facility in May 2011 with our parent’s revolving credit facility.

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

Revenues

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids sales revenues increased $28.7 million, or 287%, to $38.8 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Average daily production increased 1,252 Boe/d, or 172%, to 1,981 Boe/d for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in average daily production was primarily due to increased drilling in our Blacktail Ridge, North Monument Butte and Bridgeland project areas in response to higher oil prices. The higher production volumes contributed to $17.2 million of the revenue increase, and the remaining $11.5 million increase was attributable to an increase in realized commodity prices. Our period to period revenue increase was predominately driven by increases in crude oil production and realized crude oil prices, with 88% of revenue and 70% of production volumes attributable to crude oil for the year ended December 31, 2010. Average oil sales prices, without realized derivatives, increased $19.03, or 40%, per barrel to $66.89 per barrel for the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Operating expenses

Lease operating expenses. Our lease operating expenses increased $2.4 million, or 143%, to $4.1 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. This increase was primarily due to the higher number of producing wells as a result of the increased drilling activity in our Blacktail Ridge, North Monument Butte and Bridgeland project areas. Per unit lease operating costs declined $0.67 per Boe, or 11%, to $5.69 per Boe for the year ended December 31, 2010 as compared to the year ended December 31, 2009 due to the 172% increase in production providing greater economies of scale for fixed costs.

Production taxes. Our production taxes increased $1.2 million, or 71%, to $3.0 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Per unit production taxes, however, declined $2.40 per Boe, or 37%, to $4.10 per Boe for the year ended December 31, 2010 as compared to the year ended December 31, 2009 primarily due to production from increased drilling activity. New wells qualify for severance tax exemptions on Tribal and state lands for twelve and six months, respectively, which results in a lower effective tax rate in periods of increasing production from new wells.

Gathering and transportation expenses. Our gathering and transportation expenses increased $1.0 million, or 87%, to $2.1 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Gathering and transportation costs per unit decreased $1.30 per Boe, or 31%, to $2.88 per Boe for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The decrease in per unit gathering and transportation was primarily due to a reduction of the contribution of production from higher cost project areas and higher total production in project areas in which we have a fixed component to our infield gathering rate.

Depreciation, depletion and amortization (“DD&A”). Our DD&A expense increased $8.3 million, or 148%, to $13.9 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase was primarily due to a 172% increase in production volumes partially offset by a decline in the DD&A rate. The DD&A rate declined $1.85 per Boe, or 9%, to $19.16 per Boe for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The decrease in the DD&A rate was due to an increase in

associated proved developed reserves additions recorded within the period in proportion to capital expenditures in the same period, in particular in Blacktail Ridge and North Monument Butte, and lower finding costs.

General and administrative expenses. Our general and administrative expenses increased $2.3 million, or 216%, to $3.4 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. This increase resulted primarily from compensation, benefits and other overhead associated with the additional personnel hired to execute our strategic shift to becoming an operator. As of December 31, 2010, we had 23 full-time employees compared to eight employees as of December 31, 2009.

Other income (expense)

Gains (losses) on commodity derivatives, net. As a result of our derivative activities, we received cash settlement gains of $1.3 million for the year ended December 31, 2010 and incurred cash settlement losses of $0.9 million for the year ended December 31, 2009. In addition, as a result of forward oil price changes, we recognized $1.6 million of unrealized losses in 2010 and $0.9 million of unrealized losses during 2009.

Interest expense. Interest expense increased $0.4 million to $0.4 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. At December 31, 2010 the principal amount of debt outstanding under our prior revolving credit facility was $10.0 million.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our parent, borrowings under our prior revolving credit facility, proceeds of borrowings under our parent’s credit facilities and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Liquidity and cash flow

Our cash flows for the years ended December 31, 2009, 2010 and 2011 and for the three months ended March 31, 2011 and 2012 are presented below:


	Year Ended December 31,									Three Months Ended March 31,
	2009			2010			2011			2011			2012
										(Unaudited)
	(In thousands)
Net cash provided by operating activities	$	128		$	22,467		$	62,935		$	8,769		$	15,182
Net cash used in investing activities		(11,261	)		(54,342	)		(266,783	)		(18,414	)		(56,315	)
Net cash provided by financing activities		11,285			31,780			208,278			10,486			37,964

Net change in cash	$	152		$	(95	)	$	4,430		$	841		$	(3,169	)

Net cash provided by operating activities was $8.8 million and $15.2 million for the three months ended March 31, 2011 and 2012, respectively. The increase in cash flows from operations was primarily the result of increased oil and gas revenues from increased production volumes at higher crude prices, largely resulting from our commencement of operated drilling activities in 2011.

Net cash provided by operating activities was $0.1 million, $22.5 million and $62.9 million for the years ended December 31, 2009, 2010 and 2011, respectively. The increase in cash flows from operations for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily the result of increased oil and gas revenues from increased production volumes at higher crude oil prices, largely resulting from our commencement of operated drilling activities in 2011. Cash flows from operations during the year ended

December 31, 2010 increased compared to 2009 due to increased oil and gas revenues from increased production volumes at higher realized crude oil prices.

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

Net cash used in investing activities was $18.4 million and $56.3 million during the three months ended March 31, 2011 and 2012, respectively. The increase in cash used in investing activities for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 was primarily a result of increased capital expenditures for drilling and development costs, particularly related to our operated drilling activities in Randlett.

Net cash used in investing activities was $11.3 million, $54.3 million and $266.8 million during the years ended December 31, 2009, 2010 and 2011, respectively. The increase in cash used in investing activities for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily a result of increased capital expenditures for drilling and development costs, particularly related to our operated drilling in Randlett, and acquisitions in 2011. Additionally, our capital expenditures were $120.9 million for leasehold and acquisition costs during the year ended December 31, 2011 compared to $3.4 million for the year ended December 31, 2010. The increase in cash used in investing activities for the year ended December 31, 2010 compared to the year ended December 31, 2009 was attributable to increased drilling activity during 2010 in response to increased oil prices.

Our capital expenditures for the years ended December 31, 2009, 2010 and 2011 and for the three months ended March 31, 2012 are summarized in the following table:


	Year Ended December 31,						Three Months Ended March 31, 2012
	2009		2010		2011		Three Months Ended March 31, 2012
							(Unaudited)
	(In thousands)
Drilling and completion of wells	$	11,136	$	51,258	$	132,448	$	50,371
Leasehold and acquisition costs		1,295		3,408		120,928		1,358
Construction of gathering infrastructure		—		—		12,956		4,324
Information technology and other		—		74		451		262

Total	$	12,431	$	54,740	$	266,783	$	56,315

Net cash provided by financing activities was $10.5 million and $38.0 million during the three months ended March 31, 2011 and 2012, respectively. For the three months ended March 31, 2011 and 2012, the net cash provided by financing activities consisted primarily of borrowings under our parent’s credit facilities. Our long term debt was $116.9 million at December 31, 2011 and $152.6 million at March 31, 2012.

Net cash provided by financing activities was $11.3 million, $31.8 million and $208.3 million for the years ended December 31, 2009, 2010 and 2011, respectively. For the years ended December 31, 2009, 2010 and 2011, the net cash provided by financing activities consisted primarily of proceeds from contributions from our parent, borrowings under our parent’s credit facilities and borrowings by us under our prior revolving credit facility. During the years ended December 31, 2010 and 2011, our parent received equity investments of $61.0 million and $103.0 million, respectively. Our long term debt was $10.0 million at December 31, 2010 and $116.9 million at December 31, 2011.

Capital resources

During 2010 and 2011, we and our parent incurred indebtedness under the credit facilities described below to partially fund our drilling activities and lease acquisitions, including our recent Horseshoe Bend acquisition. Our historical financial information prior to 2010 reflects our share of indebtedness incurred by our parent and as transferred to us as a parent contribution and used to fund our operations. Please read “—Items Impacting Comparability of Our Financial Results.”

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Our prior revolving credit facility. During 2010 and 2011, we incurred indebtedness under our prior revolving credit facility to partially fund our drilling activities and our parent contributed the remainder of our financing needs. We entered into our prior revolving credit facility on March 9, 2010, which provided for a three-year $100.0 million credit facility and an initial borrowing base of $10.0 million. The borrowing base was subsequently increased to $25.0 million on August 11, 2010 and $35.0 million on March 18, 2011. We had borrowings outstanding under this facility of $10.0 million at December 31, 2010 and borrowed an additional $20.5 million through May 2011. On May 27, 2011, we repaid all outstanding indebtedness under our prior revolving credit facility with proceeds from a new revolving credit facility at our parent that our parent contributed to us and terminated our prior facility.

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Parent revolving credit facility. Our parent entered into a new revolving credit facility on May 27, 2011, which initially provided for a five-year $300.0 million credit facility and an initial global borrowing base of $95.0 million, $55.0 million of which was based on our upstream oil and gas assets. We are a guarantor of our parent’s revolving credit facility. Our parent borrowed $30.7 million under the new facility to repay all of the outstanding borrowings and accrued interest on our prior credit facility. After entering into the new facility and retiring the prior facility, our parent sold additional membership interests in its company to the Tribe and Quantum for $100.0 million in cash and used a portion of the proceeds to repay all of the debt outstanding under the new credit facility in the third and fourth quarters of 2011, which included borrowings used to repay the $30.7 million in borrowings and accrued interest under our prior credit facility. Since the $30.7 million was repaid with the proceeds from a capital contribution by the Tribe and Quantum and this capital contribution was allocated to us, we have no further obligation to our parent with respect to this $30.7 million. Since then, our parent re-borrowed funds under the new credit facility to fund our upstream operations and our parent’s other energy investments. On March 15, 2012, the oil and gas borrowing base of our parent’s revolving credit facility was $196.0 million, $150.0 million of which is based on our upstream oil and gas assets. As of June 12, 2012, our parent had borrowed $165.0 million under its revolving credit facility, $143.8 million of which was drawn to fund our upstream operations and $21.2 million was drawn to fund our parent’s other energy investments.

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Parent second lien credit facility. Our parent entered into a $50.0 million senior secured second lien credit facility on September 30, 2011. We are a guarantor of this facility, which matures in November 2016. On September 30, 2011, our parent borrowed $24.5 million under its second lien facility and on November 7, 2011 our parent borrowed the remaining $25.5 million in availability under this facility. Our parent contributed the proceeds of these borrowings to us in order to fund our drilling activities and acquisitions.

Our balance sheet and pro forma condensed combined balance sheet as of March 31, 2012 includes our portion of the borrowings outstanding under our parent’s credit facilities used to repay our prior revolving credit facility and to fund a portion of our operations and acquisitions. Our parent received $103.0 million in equity contributions to provide additional funding for our operations in 2011.

Immediately prior to the closing of this offering, we intend to assume approximately $ million in aggregate principal amount of the loans outstanding under our parent’s credit facilities, which loans are secured by liens on substantially all of our properties. We will use a portion of the net proceeds from this offering to repay in full such assumed debt at the closing of this offering. Upon repayment in full of the loans, we will be released from any further obligations under our parent’s credit facilities and the liens on our properties will be released. As of June 12, 2012, our parent had $215.0 million drawn on its credit facilities, of which $193.8 million was attributable to our upstream operations and $21.2 million was attributable to our parent’s other energy investments.

New credit facility. In connection with the completion of this offering, we will enter into a new $500.0 million senior secured reserve-based revolving credit facility with an initial borrowing base of $150.0 million and a maturity of five years from the closing date of the new credit facility. The borrowing base under our new credit facility will be subject to redetermination on January 1, April 1, July 1 and October 1 of each of the first two years following entry into the facility and semi-annually on April 1 and October 1 of each year thereafter. The first borrowing base redetermination will be on July 1, 2012. We and the administrative agent, acting at the direction of lenders collectively holding two-thirds of the outstanding loans and unfunded commitments under the facility, shall each have the option to request one unscheduled borrowing base redetermination between each scheduled redetermination, but in no instance may we or the administrative agent request redeterminations more often than twice every 12 months; however, if an event of default under the facility has occurred and is continuing the administrative agent may request additional redeterminations without such limitations. The borrowing base will be calculated in the sole discretion of the administrative agent and the lenders in accordance with their customary internal standards and practices for valuing and redetermining the value of oil and gas properties in connection with reserve-based oil and gas loan transactions. Our new credit facility will be available to finance capital expenditures, ongoing working capital, including permitted acquisitions and investments, and general corporate purposes.

At our election, interest will be generally determined by reference to:

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the London interbank offered rate, or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum (based upon borrowing base usage); or

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the alternate base rate plus an applicable margin between .75% and 1.75% per annum (based upon borrowing base usage). The alternate base rate is equal to the higher of Wells Fargo’s prime rate, the federal funds rate plus 0.5% per annum or the reference LIBOR plus 1.0%.

Our new revolving credit facility will be secured by mortgages on greater than 80% of the present value of the proved reserves of our oil and natural gas properties. Our new revolving credit facility also will contain covenants that, among other things, will require us to maintain specified ratios or conditions. We must maintain a current ratio, consisting of consolidated current assets, including the unused amount of the borrowing base, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash derivative assets and liabilities, as of the last day of any fiscal quarter. Under our new revolving credit facility, the current ratio would have been 1.6 to 1.0 as of March 31, 2012, calculated by dividing our consolidated current assets of $65.6 million by our consolidated current liabilities of $42.0 million. In addition, we must maintain a leverage ratio, consisting of our consolidated Leverage Indebtedness (as defined in the credit agreement) to our consolidated EBITDAX (as defined in the credit agreement) of not more than 4.0 to 1.0 for the four quarters ended on the last day of each fiscal quarter. Under our new revolving credit facility, the leverage ratio would have been 1.8 to 1.0 as of March 31, 2012, calculated by dividing our consolidated leverage indebtedness of $153.0 million by our consolidated EBITDAX of $85.1 million.

Our new revolving credit facility contains a negative covenant restricting our ability to incur additional debt, subject to certain exceptions, including, but not limited to, the following:

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indebtedness existing under our new revolving credit facility or that was existing upon entry into the facility, as set forth in our new revolving credit facility, including extensions, replacements and refinancings that do not increase the principal amount of such indebtedness;

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capital lease obligations and purchase money indebtedness having an aggregate principal amount not exceeding $10,000,000;

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certain guarantees of indebtedness;

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obligations of us or our subsidiaries existing or arising under any rate contract permitted by our new revolving credit facility;

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certain intercompany indebtedness of our subsidiaries that is subordinated to debt arising under our new revolving credit facility or any secured rate contract;

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indebtedness representing deferred compensation to our employees incurred in the ordinary course of business in an aggregate amount not exceeding $500,000;

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certain customary obligations in respect of purchase price or similar adjustments incurred by us or our subsidiaries in connection with dispositions, investments or acquisitions, but excluding guarantees of indebtedness, subject to certain requirements as described in our new revolving credit facility;

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certain unsecured purchase price adjustments; and

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other unsecured indebtedness having a principal amount not exceeding $5,000,000 in the aggregate.

In addition, our new revolving credit facility will contain affirmative covenants that are customary for credit facilities of this type. The covenants will include delivery of financial statements and other financial information, notice of defaults and certain other matters, payment of obligations, compliance with laws, maintenance of books and records, certain inspection rights, further assurances and operation and maintenance of properties. Our new revolving credit facility will also contain additional negative covenants that will limit our ability to:

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grant certain liens;

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engage in certain asset dispositions;

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merge or consolidate;

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make certain investments or loans;

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enter into transactions with affiliates;

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use proceeds for certain purposes, including to purchase or carry margin stock;

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incur certain contingent obligations;

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engage in certain transactions that violate ERISA or certain employee benefit plans;

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make certain dividends, distributions or redemptions of stock or stock equivalents;

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engage in any business other than the exploration, acquisition, development and production of oil and gas and activities reasonably incidental or related thereto;

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make certain amendments to our organizational documents;

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make certain accounting changes, except as required by GAAP;

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make certain amendments to or violate certain requirements of material contracts;

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

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violate the regulations issued by the Office of Foreign Assets Control;

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issue press releases or other public disclosure using the name, logo or otherwise referring to the agent of the new revolving credit facility and its affiliates without its prior written consent, except as required by law;

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enter into certain sale or leaseback arrangements;

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

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enter into, modify or cancel certain rate contracts.

Our new revolving credit facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting our new revolving credit facility to be in full force and effect and change of control. If such an event of default occurs, the lenders under our new

revolving credit facility would be entitled to take various actions, including the acceleration of amounts due under our new revolving credit facility and all actions permitted to be taken by a secured creditor.

Future capital requirements. Our future natural gas, crude oil and natural gas liquids reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We intend to grow our reserves and production by increasing our operated drilling activities and participating in wells drilled by our partners. We anticipate that acquisitions, including acquisitions of undeveloped leasehold interests, will continue to play a significant role in our business strategy as those opportunities periodically arise from time to time.

The amount and allocation of capital we spend may fluctuate materially based on drilling results, market conditions and drilling permit availability. Our 2011 capital budget was funded with proceeds from borrowings under our parent’s credit facilities, capital contributions of $103.0 million from our parent’s equity investors and borrowings under our prior revolving credit facility. We believe the net proceeds from this offering together with cash flows from operations and borrowings under our new credit facility will be sufficient to fund our 2012 capital expenditure budget.

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors. Our ability to continue to meet our liquidity requirements and execute on our growth strategy can be impacted by economic conditions outside of our control, such as the ongoing disruption in the capital and credit markets resulting from the European sovereign debt crisis, as well as continued commodity price volatility, which could, among other things, lead to a decline in the borrowing base under our revolving credit facility in connection with a borrowing base redetermination. In such case, we may be required to seek other sources of capital earlier than anticipated, although the restrictions in our credit agreements may impair our ability to access other sources of capital, and access to additional capital may not be available on terms acceptable to us or at all.

Obligations and Commitments

We have the following contractual obligations and commitments as of March 31, 2012 (in thousands):


	Payments Due by Period
Contractual Obligations	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Debt borrowed under our parent’s senior secured revolving credit facility(1)	$	102,600	$	—	$	—	$	102,600	$	—
Debt borrowed under our parent’s second lien credit facility(1)		50,000		—		—		50,000		—
Operating leases(2)		853		339		514		—		—
Drilling rig commitments(2)		1,773		1,773		—		—		—
Firm transportation(2)		3,163		745		2,418		—		—
Asset retirement obligations(3)		2,808		—		—		—		2,808

Total contractual cash obligations	$	161,197	$	2,857	$	2,932	$	152,600	$	2,808

(1)	Amount excludes applicable interest during the periods presented. Maturity is based on the requirements of our parent’s credit facilities.

(2)	Please read Note 10 to our audited financial statements for a description of lease obligations and drilling contract commitments.

(3)

Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. Please read Note 7 to our audited financial statements.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read Note 2 to our audited financial statements for a discussion of additional accounting policies and estimates made by management.

Method of accounting for oil and natural gas properties

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed as incurred. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in the statement of operations in our financial statements. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the

viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

Revenue from our interests in producing wells is recognized when delivery to the purchaser has occurred, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. We report revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

Impairment of proved 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. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

Impairment of unproved properties

We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.

We have historically recognized impairment expense for unproved properties at the time when the lease term has expired or sooner if, in management’s judgment, the unproved properties have lost some or all of their carrying value. We consider the following factors in our assessment of the impairment of unproved properties:

•

the remaining amount of unexpired term under our leases;

•

our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;

•

our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•

our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

•

our evaluation of the continuing successful results from the application of completion technology by us or by other operators in areas adjacent to or near our unproved properties.

The assessment of unproved properties to determine any possible impairment requires managerial judgment.

Asset retirement obligations

In accordance with the Financial Accounting Standard Board’s (FASB) authoritative guidance on asset retirement obligations, or ARO, we record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our statement of operations.

We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under other income (expense) in our statement of operations.

Profits sharing and stock-based compensation

Our parent established a Management Incentive Plan in which the parent may grant Management Incentive Units (“MIUs”), which are profits interests that participate in certain distribution events following the sale, merger, or other transaction involving the stock or assets of our parent or its subsidiaries only after certain return thresholds are met by all other classes of member interests. When distributions occur, the MIU holder may be subject to future service conditions. Rights to future distributions under the MIUs are generally forfeited if an employee is terminated. We account for MIUs under the provisions of ASC Topic 710, Compensation General (“ASC 710”), under which the amount of compensation cost will be measured based on the value distributed to the holders of the MIUs and recognized at the time such events occur.

In certain circumstances, future distributions to MIU holders of equity instruments of the parent or its subsidiaries may result in a creation of an equity award to be accounted for prospectively under the provisions of ASC Topic 718, Stock Compensation (“ASC 718”). For such awards, we will determine the amount of stock-based compensation expense to be recognized based on the fair market value of the equity instrument on the distribution date of the respective award. We will recognize the resulting stock-based compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period of the award. Based on an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), we would expect to record $ as compensation expense at the time of the initial public offering, and we would expect to record $ as compensation expense on a straight-line basis, net of estimated forfeitures, over the weighted average remaining service period of approximately years.

Recent accounting pronouncements

Fair value. In May 2011, the FASB issued authoritative guidance which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011 and we are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements, and is effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The adoption of this guidance did not have a significant impact on our financial position, results of operations or cash flows.

Oil and gas reporting requirements. In December 2008, the SEC released the final rule, “Modernization of Oil and Gas Reporting,” which adopts revisions to the SEC’s oil and gas reporting disclosure requirements. The disclosure requirements under this final rule require reporting of oil and gas reserves using the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months rather than year-end prices, and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are allowed, but not required, to disclose probable and possible reserves in SEC filings. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. In January 2010, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. We have presented and applied this new guidance for our reserve estimates as of December 31, 2009, 2010 and 2011.

Business combinations. In December 2010, the FASB issued an accounting standards update relating to disclosure of supplementary pro forma information for business combinations. This guidance provides clarification on disclosure requirements and amends current guidance to require entities to disclose pro forma revenue and earnings of the combined entity as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period. Qualitative disclosures describing the nature and amount of any material, nonrecurring pro forma adjustments directly attributable to the business combinations included in the reported pro forma revenue and earnings are also required. This guidance is effective for business combinations with acquisition dates on or after the beginning of the first annual reporting period beginning on or after December 15, 2010, with early adoption permitted. This pronouncement affects only disclosures and did not impact our financial condition and results of operations.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an

annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2009, 2010 and 2011 or the three months ended March 31, 2012. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosures About Market Risk

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

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production. Based on our derivative contracts in place at December 31, 2011, the fair value of our derivatives would change by $3.5 million for a $1.00 per bbl increase or decrease in crude oil prices and $0.2 million for a $0.10 per mcf increase or decrease in natural gas prices.

We utilize derivative financial instruments (primarily swaps, costless collars and basis swaps) to manage risks related to changes in oil prices. We record all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

The following is a summary of our derivative contracts as of March 31, 2012:


	Remainder Year 2012			Year 2013		Year 2014		Year 2015		Year 2016
Oil positions(1):
Swaps:
Hedged volume (Bbls)		1,022,917			1,436,077		176,263		150,236		45,519
Weighted average price ($/Bbl)	$	94.49		$	92.63	$	91.48	$	92.15	$	98.13
Collars:
Hedged volume (Bbls)		34,000			—		222,567		175,169		82,397
Weighted average floor price ($/Bbl)	$	80.00		$	—	$	91.67	$	91.67	$	91.67
Weighted average ceiling price ($/Bbl)	$	99.50		$	—	$	110.33	$	110.33	$	110.33
Natural gas positions(2):
Henry Hub Swaps:
Hedged volume (MMBtu)		262,253			—		—		—		—
Weighted average price ($/MMBtu)	$	6.11		$	—	$	—	$	—	$	—
Basis Swaps:
Hedged volume (MMBtu)		262,253			—		—		—		—
Weighted average price ($/MMBtu)	$	(0.60	)	$	—	$	—	$	—	$	—
Rockies Swaps:
Hedged volume (MMBtu)		117,800			423,500		358,300		261,600		—
Weighted average price ($/MMBtu)	$	4.60		$	4.60	$	4.60	$	4.60	$	—

(1)	The oil derivatives are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude Oil.

(2)

The Henry Hub natural gas swaps are settled based on the NYMEX monthly settlement price and the Rockies swaps are settled based on the Northwest Pipeline Corporation monthly settlement price as quoted in Platt’s Inside FERC. The basis swap derivatives are settled based on the differential between the NYMEX gas price and the Northwest Pipeline Corporation price.

Interest rate risk. On May 27, 2011, we refinanced our prior revolving credit facility, which bore interest at floating rates with a minimum LIBOR rate of 2.00%, with our parent’s revolving credit facility. On September 30, 2011, our parent entered into a second lien credit facility. At December 31, 2011, we had allocated indebtedness outstanding under our parent’s revolving credit facility of $66.9 million, which bears interest at floating rates, and $50.0 million outstanding allocated under our parent’s second lien credit facility, which bears interest at a floating rate plus a fixed margin with a minimum LIBOR rate of 1.50%. The weighted average interest rates on our parent’s revolving credit facility and second lien credit facility from date of entering into the facilities until December 31, 2011 were 2.61% and 8.52%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended March 31, 2012 would have resulted in an estimated $0.3 million increase in interest expense for the three months ended March 31, 2012.

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

Counterparty and customer credit risk. For the three months ended March 31, 2012, production from properties operated by Bill Barrett and Newfield was sold under their marketing arrangements and accounted for approximately 30% and 15%, respectively, of our total revenue. We sell our operated crude oil production under three marketing arrangements. We sell our Randlett crude oil production to a marketing firm and to an area refinery. Our production on the acreage acquired in the Horseshoe Bend acquisition will be sold through December 31, 2012 under arrangements in place at the time of the acquisition. The marketing firm accounted for 15%, the refiner accounted for 32% and the Horseshoe Bend contract accounted for 6% of our total revenue for the three months ended March 31, 2012. We expect the percentage of crude oil sold under our marketing arrangements to increase over time as our operated oil production increases as a percentage of our total production. Please read “Business—Our Operations—Marketing and major customers” for further detail about our significant customers. It is possible that one or more of our customers will become financially distressed and default on their obligations to us. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

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

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements. Please read “—Obligations and Commitments” and Note 10 to our audited financial statements included elsewhere in this prospectus for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

BUSINESS

Overview

During 2010, we shifted our focus from participating primarily in non-operated positions to establishing a significant portfolio of operated acreage and growing our asset base primarily through operated drilling activities. As a part of this strategy, we hired a dedicated management team and technical personnel with significant industry and operational experience. Our management team is led by Joseph N. Jaggers, an industry veteran with over 30 years of experience managing oil and gas operations. Most recently, Mr. Jaggers served as President and Chief Operating Officer of Bill Barrett, where he achieved significant production and reserve growth. Mr. Jaggers has operational experience in many basins in North America, including the Uinta Basin, and leads an experienced team with extensive engineering, geosciences, land, environmental and financial capabilities.

Since our strategic shift, we have increased our operated acreage position in the Uinta Basin through an active leasing and acquisition program and we have balanced our portfolio of Tribal acreage with the addition of significant interests in fee, state, federal and allotted lands. As of December 31, 2011, we have 78,170 net operated acres, which represents 47% of our total net acreage position, and we have 68,041 net acres on fee, state, federal and allotted lands, which represents 41% of our total net acreage position. Additionally, we spud our first operated well in our Randlett project area in April 2011, our 10th well in July 2011, our 20th well in September 2011 and our 30th well in November 2011. We had drilled 34 gross (34 net) operated wells as of December 31, 2011, and we operated 43% of our average net daily production for the month ended December 31, 2011. We operated approximately 50% of our average net daily production for the month ended March 31, 2012.

In addition to expanding our operated acreage position, we continue to derive substantial benefits from our non-operated properties throughout the Uinta Basin. As of December 31, 2011, we have participated in 339 gross (101.6 net) non-operated wells. These wells are operated by other leading operators in the basin, including Berry Petroleum, Bill Barrett and Newfield. We believe our participation in non-operated project areas offers attractive return opportunities and enables us to gain additional exposure to emerging resource plays without committing all of the capital required to drill the wells during the early-stage testing and refinement of drilling and completion techniques. For example, our operating partners are leading the development of an emerging horizontal play targeting the Uteland Butte producing zone of the lower Green River formation. Through December 31, 2012, we have participated in eight gross (2.25 net) horizontal Uteland Butte wells drilled by our operating partners.

Our oil and natural gas properties are divided among multiple project areas within the Uinta Basin. These project areas are described in more detail under the heading “—Our Operations—Our core project areas” beginning on page 90 of this prospectus. The following table presents a summary of acreage, identified potential drilling locations, reserves and production for each of our project areas as of the dates, and for the periods, indicated.


	Net Acreage as of December 31, 2011		Identified Potential Drilling Locations as of December 31, 2011(1)				Estimated Net Proved Reserves as of December 31, 2011						Average Net Daily Production (Boe/d) for the Three Months Ended March 31, 2012
	Net Acreage as of December 31, 2011		Gross		Net		MMBoe(2)		% of Total Proved Reserves		% Oil
Randlett		41,478		1,008		917.0		14.1		37%		93%		2,407
Horseshoe Bend		29,281		820		567.7		9.2		24%		100%		329
Rocky Point		11,071		507		213.3		—		—		—		—
Blacktail Ridge		28,603		647		312.9		8.6		22%		75%		1,496
North Monument Butte		11,724		1,050		262.5		5.4		14%		79%		721
Bridgeland		10,124		573		200.5		0.6		2%		52%		472
Lake Canyon		30,066		1,462		365.5		0.3		1%		67%		330
Other		3,261		17		8.2		0.1		0%		0%		65

Total		165,608		6,084		2,847.6		38.3		100%		88%		5,820

(1)	Please read “—Identification of Potential Drilling Locations” for more information on how we identify our potential drilling locations.

(2)	One Boe is equal to one Bbl of oil or six Mcf of natural gas based on an approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

Our ability to develop our identified potential drilling locations depends, in part, on our ability to obtain drilling permits. Through March 31, 2012, we have received a total of 141 drilling permits in our Randlett project area and have an inventory of 87 unused permits. We expect to receive an additional 97 drilling permits by the end of the third quarter of 2012 and plan to submit applications for another 152 drilling permits by year end 2012, with anticipated approvals in the first half of 2013. In our Horseshoe Bend project area, we currently hold 8 valid drilling permits and have 47 available for submission under the current Gusher Federal Environmental Assessment (EA).

The amount and allocation of capital we spend may fluctuate materially based on drilling results, market conditions and drilling permit availability. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Identification of Potential Drilling Locations

Our Competitive Strengths

We believe the following competitive strengths will allow us to successfully execute our business strategies:

•

•

Our Business Strategy

Our goal is to increase stockholder value by growing our reserves and increasing our production and cash flows by executing the following strategies:

•

operating partners are leading the development of an emerging horizontal play targeting the Uteland Butte producing zone of the lower Green River formation. Through December 31, 2011, we have participated in eight gross (2.25 net) horizontal Uteland Butte wells drilled by our operating partners. We plan to apply the knowledge and expertise gained from participating in the drilling and completion of these wells to target prospective horizontal Uteland Butte or other prospective horizontal zones in our operated portfolio of oil and natural gas properties in the future. In addition, we believe that the knowledge and expertise gained through our non-operated positions will enhance our ability to continue efficiently growing our operated acreage positions throughout the Uinta Basin.

•

Horseshoe Bend Acquisition

Our Operations

Estimated proved reserves

The summary data with respect to our estimated proved reserves presented below has been prepared by our independent reserve engineering firms, Cawley Gillespie and Ryder Scott, in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. In this prospectus, proved reserve estimates do not include any value for probable or possible reserves which may exist. Our estimated proved reserves for the years ended December 31, 2009, 2010 and 2011 were prepared in

accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. For a definition of proved reserves under the SEC rules for the periods ending on or after December 31, 2009, please read the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus. For more information regarding our independent reserve engineers, please read “—Qualifications of technical persons and internal controls over reserves estimation process” below.

The table below summarizes our estimated proved reserves and related PV-10 at December 31, 2009, 2010 and 2011 for each of our project areas. The reserve estimates presented as of December 31, 2009 are based on a report prepared by Cawley Gillespie. The reserve estimates presented as of December 31, 2010 and 2011 are based on reports prepared by Ryder Scott. In preparing their reports, Cawley Gillespie and Ryder Scott evaluated properties representing all of our PV-10 at December 31, 2009, 2010 and 2011 under the SEC’s rules applicable to such periods. For more information regarding our independent reserve engineers, please read “—Qualifications of technical persons and internal controls over reserves estimation process” below. The information in the following table does not give any effect to or reflect our commodity hedges.


	As of December 31, 2009				As of December 31, 2010				As of December 31, 2011
Project Area	Proved Reserves (MMBoe)		PV-10 (in millions)(1)		Proved Reserves (MMBoe)		PV-10 (in millions)(1)		Proved Reserves (MMBoe)		PV-10 (in millions)(1)
Randlett		0.0	$	0.0		0.0	$	0.0		14.1	$	274.8
Horseshoe Bend		0.0		0.0		0.0		0.0		9.2		122.8
Rocky Point		0.0		0.0		0.0		0.0		0.0		0.0
Blacktail Ridge		0.5		6.6		4.7		55.8		8.6		68.6
North Monument Butte		1.8		14.3		3.0		35.2		5.4		82.8
Bridgeland		0.5		4.5		2.2		20.3		0.6		9.1
Lake Canyon		0.2		1.2		0.2		1.0		0.3		6.3
Other		0.1		0.2		0.1		0.3		0.1		0.2

Total		3.1	$	26.8		10.2	$	112.6		38.3	$	564.6

(1)

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because as of the period presented, we were a disregarded entity for federal income tax purposes not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, in connection with the closing of this offering, we will convert into a corporation that will be a taxable entity for federal income tax purposes. As a result, we will be a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. For more information, please read Note 12 to our audited financial statements included elsewhere in this prospectus. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

The following table sets forth more information regarding our estimated proved reserves at December 31, 2009, 2010 and 2011.


	As of December 31,
	2009			2010			2011
Reserve Data(1):
Estimated proved reserves:
Oil (MMBbls)		2.0			7.1			33.5
Natural gas (Bcf)		5.7			17.3			25.2
Natural gas liquids (MMBbls)		0.1			0.2			0.6
Total estimated proved reserves (MMBoe)		3.1			10.2			38.3
Estimated proved developed reserves:
Oil (MMBbls)		0.9			2.5			7.3
Natural gas (Bcf)		2.8			7.1			9.5
Natural gas liquids (MMBbls)		0.0			0.1			0.2
Total estimated proved developed reserves (MMBoe)		1.4			3.7			9.0
Percent developed		45	%		37	%		24	%
Estimated proved undeveloped reserves:
Oil (MMBbls)		1.2			4.6			26.2
Natural gas (Bcf)		2.9			10.2			15.7
Natural gas liquids (MMBbls)		0.1			0.1			0.4
Total estimated proved undeveloped reserves (MMBoe)		1.7			6.4			29.2
PV-10 (in millions)(2)	$	26.8		$	112.6		$	564.6
Standardized Measure (in millions)(3)		26.8			112.6			564.6

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


	As of December 31,
	2009		2010		2011
Oil and Natural Gas Prices(1):
Oil (per Bbl)	$	61.18	$	79.43	$	96.19
Natural gas (per MMBtu)	$	3.87	$	4.38	$	4.12

(1)

(2)

our future taxable income. For more information, please read Note 12 to our audited financial statements included elsewhere in this prospectus. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

(3)

Estimated proved reserves at December 31, 2011 were 38.3 MMBoe, a 276% increase from reserves of 10.2 MMBoe at December 31, 2010. At December 31, 2011, estimated proved reserves increased 28.1 MMBoe over our December 31, 2010 estimated reserves primarily due to the addition of 23.2 MMBoe of proved reserves in Randlett and Horseshoe Bend, which had no associated proved reserves as of December 31, 2010. In Randlett, we commenced operated drilling and production during 2011 and had 14.1 MMBoe of proved reserves as of December 31, 2011. We acquired our Horseshoe Bend properties on November 30, 2011 and had proved reserves of 9.2 MMBoe as of December 31, 2011. The remaining increase was due to the drilling activities of our operating partners and higher oil price assumptions at December 31, 2011. Our commodity price assumption for oil increased $16.76 per Bbl to $96.19 per Bbl as of December 31, 2011 from $79.43 per Bbl at December 31, 2010. Our proved developed reserves increased 5.3 MMBoe, or 143%, to 9.0 MMBoe as of December 31, 2011 from 3.7 MMBoe as of December 31, 2010 due to increased operated and non-operated drilling activity and our increased oil price assumption. Our proved undeveloped reserves increased to 29.2 MMBoe as of December 31, 2011 from 6.4 MMBoe as of December 31, 2010 primarily due to recording offset undeveloped locations in our Randlett project area and our acquired Horseshoe Bend project area.

Estimated proved reserves at December 31, 2010 were 10.2 MMBoe, a 233% increase from reserves of 3.1 MMBoe at December 31, 2009. Our 2010 estimated proved reserves increased 7.1 MMBoe over our 2009 estimated reserves due to our participation in increased drilling activity by our operating partners during 2010 and higher oil price assumptions at December 31, 2010. Our commodity price assumption for oil increased $18.25 per Bbl to $79.43 per Bbl at December 31, 2010 from $61.18 per Bbl at December 31, 2009. Our proved developed reserves increased 2.4 MMBoe, or 175%, to 3.7 MMBoe as of December 31, 2010 from 1.4 MMBoe as of December 31, 2009 due to increased non-operated drilling activity. Our proved undeveloped reserves increased to 6.4 MMBoe as of December 31, 2010 from 1.7 MMBoe as of December 31, 2009 due to the recognition of additional proved undeveloped drilling locations as a result of our non-operated drilling activity.

The PV-10 of our estimated proved reserves at December 31, 2011 was $564.6 million, a 401% increase from PV-10 of $112.6 million at December 31, 2010. Our PV-10 of estimated proved reserves at December 31, 2011 increased $452.0 million over the PV-10 at December 31, 2010 due to the commencement of operated drilling activities in Randlett, acquisitions, including Horseshoe Bend, ongoing drilling activities by our operating partners and higher oil price assumptions.

The PV-10 of our estimated proved reserves at December 31, 2010 was $112.6 million, a 320% increase from PV-10 of $26.8 million at December 31, 2009. Our PV-10 of estimated proved reserves at December 31, 2010 increased $85.8 million over the PV-10 at December 31, 2009 due to higher oil prices and increased non-operated developmental drilling activity in response to higher oil prices.

The following table sets forth a reconciliation of our proved undeveloped reserves at December 31, 2010 to our proved undeveloped reserves at December 31, 2011.


		MBOE
Proved undeveloped reserves as of December 31, 2010		6,417
Revisions		(1,276)
Acquisitions		7,728
Extensions and discoveries		17,304
Conversion to proved developed reserves		(968)

Proved undeveloped reserves as of December 31, 2011		29,205

During the year ended December 31, 2011, approximately 33% of our gross wells drilled were associated with proved undeveloped reserves at December 31, 2010. Approximately 15% of the proved undeveloped reserves at December 31, 2010 were developed by drilling 41 gross (12.8 net) development wells at an aggregate capital cost to us of approximately $12.9 million.

The following table sets forth the estimated future net cash flows, excluding derivatives contracts, from proved reserves, the present value of those net revenues (PV-10), and the expected benchmark prices used in projecting net revenues at December 31, 2009, 2010 and 2011 (in thousands).


	As of December 31,
	2009		2010		2011
Future net cash flows	$	48,396	$	190,394	$	1,290,872
Present value of future net cash flows:
Before income tax (PV-10)(1)		26,760		112,608		564,636
After income tax (Standardized Measure)		26,760		112,608		564,636
Benchmark oil price(2)($/Bbl)	$	61.18	$	79.43	$	96.19

(1)

(2)

adjustment varies by project area, and the prices used to calculate estimated reserves as of December 31, 2011 reflected a weighted average discount from benchmark prices of 7%.

Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2009, 2010 and 2011 are based on costs in effect at December 31, 2009, 2010 and 2011, respectively, and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the periods January 2009 through December 2009, January 2010 through December 2010 and January 2011 through December 2011, respectively, without giving effect to derivative transactions, and are held constant throughout the life of the properties. We cannot assure you that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Reserve estimates

Our estimated reserves and related future net revenues and PV-10 at December 31, 2010 and 2011 are based on reports prepared by Ryder Scott in accordance with Society of Petroleum Engineering (“SPE”) engineering and evaluation principles and definitions and current guidelines established by the SEC, and our estimated reserves and related future net revenues and PV-10 at December 31, 2009 are based on a report prepared by Cawley Gillespie in accordance with SPE engineering and evaluation principles and definitions and current guidelines established by the SEC. Ryder Scott and Cawley Gillespie are independent reserve engineers. Copies of the reports of Ryder Scott and Cawley Gillespie have been filed as exhibits to the registration statement containing this prospectus.

Technology used to establish proved reserves

Under the SEC’s rules, 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 have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott and Cawley Gillespie 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, available downhole and production data, 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. For wells and locations targeting the Green River and Wasatch formations, the evaluation included an assessment of the beneficial impact of the use of multi-stage hydraulic fracture stimulation treatments on estimated recoverable reserves. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and seismic data related to the Green River and Wasatch formations were used to estimate original oil in place.

Qualifications of technical persons and internal controls over reserves estimation process

In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, Ryder Scott, our independent reserve engineers, estimated our proved reserve information at December 31, 2010 and 2011, and Cawley Gillespie, our former independent reserve engineers, estimated our proved reserve information at December 31, 2009. The technical persons responsible for preparing the reserves estimates presented herein at December 31, 2009, 2010 and 2011 meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Robert A. Gardner, our Engineering Manager, and James T. Jaggers, our Reservoir Engineer, are the technical personnel within the company primarily responsible for overseeing the preparation of our reserves estimates. Our Engineering Manager has over 20 years of industry experience with positions of increasing responsibility in engineering and reserve evaluations and holds both a Bachelor of Science degree and Master of Science degree in mechanical engineering. Our Reservoir Engineer has over six years of industry experience, holds a Bachelor of Science degree in petroleum engineering and is a Licensed Petroleum Engineer. Our Engineering Manager reports directly to our Chief Operating Officer.

Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. Our internal professional staff works closely with Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide Ryder Scott other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our Chief Operating Officer with representatives of our independent reserve engineers and internal technical staff. Following the consummation of this offering, we anticipate that our audit committee will conduct a similar review on an annual basis.

Production, revenues and price history

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

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The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical and pro forma basis for the periods presented. The unaudited pro forma information gives pro forma effect to the Horseshoe Bend acquisition as if it had occurred on January 1, 2011. For additional information on price calculations, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,						Three Months Ended March 31,				Pro Forma for the Year Ended December 31, 2011
	2009		2010		2011		2011		2012		Pro Forma for the Year Ended December 31, 2011
Operating data:
Net production volumes:
Oil (MBbls)		164.9		507.6		992.1		164.9		429.5		1,106.1
Natural gas (MMcf)		571.3		1,247.8		1,751.8		412.1		549.8		1,751.8
Natural gas liquids (MBbls)		6.2

Ute Energy Upstream Holdings LLC S-1/A