Ellora Energy S1/A IPO registration (amended)

Use these links to rapidly review the document
TABLE OF CONTENTS
Index to Financial Statements of Ellora Energy Inc

As filed with the Securities and Exchange Commission on June 20, 2008

Registration No. 333-138442

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 11 to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Ellora Energy Inc.
(Exact name of registrant as specified in its charter)

Delaware	1311	01-0717160
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)
5665 Flatiron Parkway Boulder, CO 80301 (303) 444-8881 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
T. Scott Martin Chairman, President and Chief Executive Officer 5665 Flatiron Parkway Boulder, CO 80301 (303) 444-8881 (Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:
Dallas Parker Kirk Tucker Thompson & Knight LLP 333 Clay Street, Suite 3300 Houston, TX 77002 (713) 654-8111		T. Mark Kelly Vinson & Elkins LLP 1001 Fannin Street, Suite 2500 Houston, TX 77002 (713) 758-2222

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

If any 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, as amended (the "Securities Act"), check the following box. o

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

If this form is a post-effective amendment filed pursuant to Rule 462(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. o

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

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 or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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

Subject to Completion
Preliminary Prospectus dated June 20, 2008

P R O S P E C T U S

11,363,189 Shares

Common Stock

We are offering 8,000,000 shares of our common stock, and the selling stockholders named in this prospectus are offering 3,363,189 shares of common stock. We will not receive any proceeds from the sale of common stock by the selling stockholders. This is the initial public offering of our common stock. We currently expect the initial public offering price to be between $17.00 and $19.00 per share. Our common stock has been approved for listing, subject to official notice of issuance, on the Nasdaq Global Market under the symbol "LORA."

Investing in our common stock involves a high degree of risk. See "Risk Factors" beginning on page 12.

	Per Share	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to us	$	$
Proceeds to the selling stockholders(1)	$	$

(1): Expenses associated with the offering, other than underwriting discounts, will be paid by us.

The underwriters may also purchase up to an additional 1,704,478 shares from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments.

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

The underwriters expect to deliver the shares on or about , 2008.

Merrill Lynch & Co.

Raymond James

KeyBanc Capital Markets

Tudor, Pickering, Holt & Co.

Howard Weil Incorporated

Tristone Capital

Thomas Weisel Partners LLC

The date of this prospectus is , 2008.

Ellora Energy Inc. Areas of Operation
As of and for the quarter ended March 31, 2008

TABLE OF CONTENTS

		Page
Prospectus Summary		1
The Offering		8
Summary Combined and Consolidated Historical Financial Data		9
Summary of Oil and Gas Data		11
Risk Factors		12
Cautionary Statement Regarding Forward-Looking Statements		25
Use of Proceeds		26
Dividend Policy		26
Capitalization		27
Dilution		28
Selected Combined and Consolidated Historical Financial Data		29
Management's Discussion and Analysis of Financial Condition and Results of Operations		31
Business		45
Management		60
Executive Compensation		64
Summary of Compensation		73
Security Ownership of Certain Beneficial Owners and Management		80
Certain Relationships and Related Party Transactions		81
Selling Stockholders		83
Description of Capital Stock		85
Shares Eligible for Future Sale		89
Material United States Federal Income Tax Considerations for Non-United States Holders		93
Underwriting		97
Legal Matters		101
Experts		101
Where You Can Find More Information		101
Glossary of Selected Oil and Gas Terms		102
Index to Financial Statements of Ellora Energy Inc.		F-1
Executive Summary Report of Ryder Scott Company, L.P.		A-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. We are not making an offer to sell these securities in any state where an offer or sale is not permitted. You should not assume that the information appearing in this prospectus is accurate as of any date other than the respective dates as of which the information is given.

PROSPECTUS SUMMARY

This summary highlights selected information from this prospectus but does not contain all information that you should consider before investing in our common stock. You should read this entire prospectus carefully, including "Risk Factors" beginning on page 12, and the financial statements included elsewhere in this prospectus. In this prospectus, we refer to Ellora Energy Inc., its subsidiaries and predecessors as "Ellora Energy," "we," "us," "our," or "our company." Unless otherwise indicated, share numbers in this prospectus assume that the underwriters do not exercise their over-allotment option to purchase additional shares of common stock. We have engaged Ryder Scott Company, L.P., independent petroleum engineers ("Ryder Scott"), to evaluate our properties. The estimates of our proved reserves included in this prospectus as of March 31, 2008 are based on a reserve report prepared by Ryder Scott. A summary of Ryder Scott's report with respect to these estimated proved reserves as of March 31, 2008 is attached to this prospectus as Appendix A. We discuss sales volumes, per Mcfe revenue, per Mcfe cost and other data in this prospectus net of any royalty owner's interest. We have provided definitions for some of the industry terms used in this prospectus in the "Glossary of Selected Oil and Gas Terms."

Ellora Energy Inc.

Overview

We are an independent oil and gas company engaged in the acquisition, exploration, development and production of onshore domestic U.S. oil and gas properties and have been operating since our inception in June 2002. We primarily operate in two areas: east Texas and adjacent lands in western Louisiana, which we collectively refer to as East Texas, and the Hugoton field in southwest Kansas. We have assembled combined acreage of approximately 921,000 gross (852,000 net) acres, providing us with 891 identified drilling locations. At March 31, 2008, we owned working interests in 336 gross (243 net) wells, and for the three months ended March 31, 2008, our average net production was approximately 31 MMcfe/d. At March 31, 2008, our estimated total proved oil and gas reserves were approximately 229 Bcfe. Our proved reserves are approximately 78% gas and 37% proved developed. Our total proved reserves have a reserve life index of approximately 20 years and our proved producing reserves have a reserve life index of approximately 8 years. Using prices as of March 31, 2008, our proved reserves had an estimated pre-tax net present value, discounted at 10%, or PV-10, of approximately $820 million, of which 40% was proved developed. See "Selected Combined and Consolidated Historical Financial Data—Reconciliation of Non-GAAP Financial Measures" for additional information regarding PV-10. As operator of over 90% of our proved reserves, we have a high degree of control over our capital expenditure budget and other operating matters.

The following table sets forth by operating area a summary of our estimated net proved reserves as of March 31, 2008 and our estimated average daily net production information for the three months ended March 31, 2008.

		Estimated Proved Reserves at March 31, 2008								Production for the Three Months Ended March 31, 2008
		Developed (Bcfe)	Undeveloped (Bcfe)	Total (Bcfe)	Percent of Total Reserves		PV-10(1) ($Millions)		Identified Drilling Locations(2)	Net Average MMcfe/d	Percent of Total
East Texas		54	83	137	60	%	$	388	263	20.1	65	%
Hugoton (Kansas)		28	59	87	38			414	613	10.1	33
Other (primarily Colorado)		3	2	5	2			18	15	0.9	2

	Total	85	144	229	100	%	$	820	891	31.1	100	%

(1): Based on March 31, 2008 average wellhead prices of $9.28 per MMBtu of gas and $97.41 per Bbl of oil held flat for the life of the reserves.
(2): Represents total gross drilling locations identified by management as of March 31, 2008, of which 207 locations are classified as proved. Based on fluctuations in commodity prices, the number of drilling locations will change.

Areas of Operation

East Texas

We acquired our initial position in East Texas in June 2002, and as of March 31, 2008, we held 75,000 gross acres (71,000 net acres) in East Texas, with current production primarily from the James Lime formation.

James Lime

From June 2002 until March 31, 2008, we have invested $154 million to drill and complete 47 of 48 James Lime wells, a 98% completion rate. During the three months ended March 31, 2008, we produced an average of 20.1 MMcfe/d from this region. Historically, James Lime wells have been drilled by various operators in Shelby County, Texas with both single and multi-lateral horizontal wellbores, completed naturally with no fracture stimulation. Our development of James Lime acreage has evolved from drilling single laterals that were unstimulated to fractured single laterals to multi-lateral wellbores. Based on our results and those of other operators in the area, we believe that a second lateral can add 30% to the initial rates and ultimate recoveries of our James Lime wells. A typical unstimulated single-lateral well costs $2.1 million to drill and complete, and each additional lateral can add approximately $300,000 to the costs.

As of March 31, 2008, our producing wells in the James Lime had produced an average of 0.8 gross Bcfe per well and had estimated remaining proved reserves of 1.2 gross Bcfe, for a total of 2.0 gross Bcfe per well. At March 31, 2008, we had 87 productive wells in East Texas, of which 76 are in the James Lime play, and total proved reserves of approximately 137 Bcfe in East Texas. As of March 31, 2008, we had identified 129 future drilling locations in the James Lime. We drilled and successfully completed 13 wells in the James Lime play in 2007 and 4 wells in the first quarter 2008, including a re-entry to add an additional lateral to an existing well. We plan to drill or re-enter a total of 16 to 18 wells in 2008 in the James Lime, most of which will be multi-lateral wells. See "—Summary of Capital Expenditures" for our estimated capital expenditures in East Texas.

In addition to the James Lime play, we have initiated development of the lower Cretaceous Fredericksburg (or Edwards) formation. We drilled four wells in the Fredericksburg formation in 2007, three of which are producing and one of which is currently being evaluated. We plan to drill two wells in the Fredericksburg formation in 2008.

Recent Developments

In the last several months, leasing and drilling activity in the Haynesville Shale gas play has increased significantly. The nearest Haynesville Shale production is from vertical wells approximately 11 to 15 miles to the east, north, and west of our East Texas acreage. On June 4, 2008, we entered into a binding letter agreement with a subsidiary of Chesapeake Energy Corporation ("Chesapeake"), pursuant to which Chesapeake agreed to acquire a 65% working interest in our deep rights in East Texas and adjacent areas of Louisiana to target the Haynesville Shale formation. Chesapeake will pay us approximately $350 million in cash, subject to standard conditions to closing such as completion of customary due diligence, the negotiation of a mutually acceptable participation agreement, and a condition that title and related contracts and agreements are acceptable to Chesapeake. We expect to close the transaction on or before July 31, 2008. We will retain all of our interest and our operating rights in the James Lime and Fredericksburg formations, as well a 35% working interest in the deep acreage that is subject to the Chesapeake agreement. Chesapeake will become the operator of the deep rights and will be obligated to drill, at its sole expense, the first five wells in the jointly owned properties during the initial two years following closing, and we will hold a 35% carried interest in each of those wells.

Pipeline System

In East Texas, we also own and operate approximately 100 miles of four-to-eight-inch gas gathering lines and gas pipelines and operate nine compressor stations with 10,395 total compression horsepower, which gather, process and transport our gas and third party gas in our East Texas operations area, which we refer to as English Bay Pipeline. Our ownership of this pipeline system provides us with the benefit of controlling compression location and timing of connection to newly completed wells as well as positioning us to potentially benefit from increases in natural gas production in the area. Our system interconnects to the Texas Eastern, Centerpoint and Gulf South pipelines. In February 2007, we acquired a 100% interest in the Shelby Pipeline in Shelby County, Texas for $6.5 million. The Shelby Pipeline transports gas from the southern portion of the Huxley Field for us and other independent producers. The addition of this approximate 20-mile pipeline increased the English Bay Pipeline system to approximately 100 miles. During the three months ended March 31, 2008, we transported an average of approximately 40 MMcfe/d of gas. Our pipeline activities from transporting third-party production provided us with revenues of approximately $11.0 million for the year ended December 31, 2007 and $3.7 million for the three months ended March 31, 2008.

Hugoton Field (Kansas)

We initially acquired our acreage position in the Hugoton field through our 2005 acquisition of Presco Western LLC, which was party to a farmout agreement that covered approximately 651,000 gross (631,000 net) acres in the Hugoton field. The farmout granted us mineral rights in reservoirs below the Heebner Shale (located at a depth of approximately 4,000 feet), which we refer to as the Hugoton Deep. We acquired, in a series of transactions that were completed by July 2007, the mineral rights to that farmout acreage and acquired additional acreage and producing wells in the Hugoton Deep for $28 million. As a result of this acquisition and additional leasing activities, we increased our acreage in the Hugoton Deep from an approximate 651,000 acres (631,000 net) to 801,000 acres (747,000 net) and increased the net revenue interest in many of our future Hugoton Deep locations from 80% to 87.5%.

Since our entry to the Hugoton Deep, we have invested $66.7 million to complete 67 of 89 wells, a 75% completion rate, and to drill 28 injection and production wells in the Southwest Lemon Victory waterflood project, which we commenced in the fourth quarter of 2007. As of March 31, 2008, the producing wells we operate in the Hugoton Deep had produced an average of 0.8 gross Bcfe per well and had estimated proved reserves of 0.2 gross Bcfe, for a total of 1.0 gross Bcfe per well. According to our March 31, 2008 reserve report, our proved undeveloped wells in the Hugoton Deep average 0.49 Bcfe of gross reserves per well. At March 31, 2008, we had 220 productive wells and total proved reserves of approximately 87 Bcfe, of which 28 Bcfe were proved developed producing and approximately 47% oil. During the three months ended March 31, 2008, we produced an average of 10 MMcfe/d, up from 2 MMcfe/d at the time of acquisition.

For the year ended December 31, 2007, we drilled and successfully completed 44 of 57 wells, and for the three months ended March 31, 2008, we drilled and successfully completed 16 of 18 wells, including waterflood wells in both cases. Our average Hugoton well costs approximately $614,000 to drill and complete. As of March 31, 2008, we had identified three waterfloods and 613 drilling locations in Kansas. We plan to drill 60 to 64 wells in 2008, including 18 waterflood wells.

Summary of Capital Expenditures

The following table summarizes information regarding our historical 2006 and 2007 and our estimated 2008 capital expenditures. The estimated 2008 capital expenditures shown are preliminary full year estimates, including approximately $21.0 million spent from January 1, 2008 through March 31, 2008. The estimated capital expenditures are subject to change depending upon a number of factors,

including availability of capital, drilling results, oil and gas prices, costs of drilling and completion and availability of drilling rigs, equipment and labor.

		Historical
		Year Ended December 31,				Estimated
		Year Ended December 31,				Year Ending December 31, 2008
		2006		2007		Year Ending December 31, 2008
		(In thousands)
Capital expenditures:
	East Texas	$	39,600	$	48,000	$	55,000
	Hugoton		17,500		39,000		40,000
	Other		1,400		—		2,000

	Total capital expenditures	$	58,500	$	87,000	$	97,000
Geological and geophysical			2,100		4,000		7,000

Total capital and geological and geophysical expenditures		$	60,600	$	91,000	$	104,000

Strategy

Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings using a balanced program of (1) developing existing properties, (2) exploiting and exploring undeveloped properties, (3) completing strategic acquisitions and joint ventures, and (4) maintaining financial flexibility. The following are key elements of our strategy:

•

Maintain Technological Expertise. We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 86% since our inception and helped us improve and maximize field recoveries.

•

Accelerate the Development of our Existing Properties. We intend to further develop the significant remaining upside potential of our properties.

•: We have recently employed multilateral drilling to enhance production from the James Lime wells in East Texas, and may fracture stimulate.
•: In the Hugoton field, we have completed studies of two secondary recovery projects that will use traditional waterflood techniques. The Southwest Lemon Victory waterflood project has shown increased production in response to waterflood projects operated by others on contiguous properties. Water injection commenced during the fourth quarter of 2007. We have now completed a majority of the wells planned for the project. Oil production has increased by 100 Bbls/d since we began injection, as we have drilled additional producing wells in the waterflood area.
•: In the Hugoton field, we have acquired 457 square miles of proprietary 3-D seismic and accelerated drilling activity by adding a second drilling rig.
•: We signed a binding letter agreement with Chesapeake to explore our deep acreage in East Texas, including the Haynesville Shale.

•

Acquisition Growth. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects, particularly on opportunities where we believe our reservoir management and operational expertise will enhance the value and performance of acquired properties.

•

Endeavor to be a Low Cost Producer. We will strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and capture operating efficiencies.

•: Maintain Financial Flexibility. On May 1, 2008, we entered into a new credit facility with an initial borrowing base of $190 million. Upon the completion of this offering, our borrowing base will be reduced to $160 million, and we expect that we will have at least $148 million available for borrowings under our revolving line of credit. In addition to this offering, we have also entered into a binding letter agreement to sell a 65% working interest in our East Texas deep acreage to Chesapeake for approximately $350 million. The proceeds from this offering and the sale to Chesapeake will provide us with significant financial flexibility to pursue our business strategy.

Competitive Strengths

We believe our historical success is, and future performance will be, directly related to the following combination of strengths which enable us to implement our strategy:

•: Experienced Management Team. The members of our executive management team have an average of 26 years of experience in the oil and gas industry and significant experience in managing public and private oil and gas companies.
•: Large Long-Lived, Operated Asset Base. We own a large long-lived asset base for which we operate over 90% of our estimated proved reserves. Operating such a large percentage of our reserves allows us to better control and execute our drilling program.
•: Large Acreage Positions. We are a significant acreage holder in each of our two primary operating areas. In East Texas we control over 75,000 gross (71,000 net) acres and in the Hugoton field 801,000 gross (747,000 net) acres.
•: Significant Hugoton Reserve Potential. We believe the deeper zones of the Hugoton field have not been fully explored or developed. Accordingly, we believe that significant amounts of gas and oil remain to be recovered in the current higher price environment using modern exploration and production technologies.
•: Significant Haynesville Acreage. A substantial portion of our East Texas acreage includes rights to the Haynesville Shale. We have entered into a binding letter agreement to sell Chesapeake a 65% working interest in our deep rights in East Texas to jointly explore and develop the Haynesville Shale formation.
•: Drilling Inventory. We have identified 891 drillable, low to moderate risk locations providing us with multiple years of drilling inventory. Of these locations, 207 are classified as proved undeveloped and none are located in the Haynesville Shale.
•: Proven Technical Team. Our technical staff includes 21 geologists, geophysicists, reservoir engineers and technicians with an average of over 22 years of relevant technical experience. Our staff has a proven record of analyzing complex structural and stratigraphic plays using 3-D seismic, geological and geophysical expertise, producing and optimizing oil and gas reservoirs, and drilling, completing and fracing tight gas reservoirs.
•: Drilling Success. The competencies of our proven technical team focused in our large and productive acreage holdings have helped us to achieve a drilling success rate of approximately 86% since our inception in 2002 through the three months ended March 31, 2008. Our technical expertise has also allowed us to improve the production rates and ultimate hydrocarbon recoveries on our wells as compared to those wells drilled by others in similar reservoirs in our primary operating areas.
•: Low Finding and Development Costs. Since our inception, we have invested approximately $238.5 million to drill and complete 178 wells in our operating areas. Our average acquisition, finding and development costs from inception to March 31, 2008 was $1.98 per

Mcfe. For a discussion of how we calculate our finding and development costs, see "Business—Historical Finding and Development Costs."

•: Control of Low-Pressure Gas Gathering Infrastructure and Gas Marketing Flexibility. We own and operate approximately 100 miles of gas gathering lines and gas pipelines that
collect and transport our production and third-party production in our East Texas operations area. Production from both East Texas and the Hugoton field has access to multiple delivery points to several regional and interstate pipelines that provide more than sufficient take away capacity to sell our production.

Our Challenges in Capitalizing on Our Strengths and Implementing Our Strategies

Our ability to successfully leverage our competitive strengths and execute our strategy depends upon many factors and is subject to a variety of risks. For example, our ability to accelerate drilling on our properties and fund our capital budget and, in particular, our estimated growth capital expenditures depend, to a large extent, upon maintaining our borrowing capacity at or near current levels under our revolving credit facility, the availability of future debt and equity financing at attractive terms, and our ability to generate cash flow from operations at or above current levels. Our ability to fund property acquisitions and compete for and retain the qualified personnel necessary to conduct our business is also dependent upon our financial resources. Changes in oil and gas prices, which may affect both our cash flows and the value of our reserves, our ability to replace production through drilling activities, a material adverse change in our oil and gas reserves due to factors other than oil and gas pricing changes, drilling costs and other factors, may adversely affect our ability to fund our anticipated capital expenditures, pursue property acquisitions, and compete for qualified personnel, among other things. You are urged to the read the section entitled "Risk Factors" for more information regarding these and other risks that may affect our business and our common stock.

Corporate Information

Ellora Energy Inc., a Delaware corporation, was formed in June 2002 and secured an equity investment from Yorktown Energy Partners V, L.P. to fund our first East Texas acquisition that same year.

In July 2006, we completed a private equity offering of 12,400,000 shares of our common stock, consisting of 2,500,000 shares issued by us and 9,900,000 shares sold by certain of our existing stockholders. We received aggregate consideration (before offering expenses of approximately $1,400,000 but after the initial purchaser's discount) of approximately $27.9 million, or $11.16 per share. We did not receive any proceeds from the shares sold by the selling stockholders. However, we did receive approximately $6.4 million from certain of the selling stockholders who are employees of our company for the repayment of loans that were made to them in connection with previous purchases of our common stock. We used the net proceeds from the offering, together with the proceeds from the repayment of the selling stockholders' loans, principally to pay down the entire outstanding balance on our credit facility.

Prior to the private equity offering in July 2006 we operated as two separate entities, Ellora Energy Inc. and Ellora Oil & Gas Inc., with one management team and substantially similar ownership. Ellora Oil & Gas Inc. was formed in April 2005 to acquire Presco Western, LLC and Ellora Energy Inc.'s assets in Colorado and interests in a joint venture with Centurion Exploration Company. These entities were merged prior to the closing of the private equity offering, with Ellora Energy Inc. as the surviving entity. The exchange factor was determined by the management and approved by the board of directors of Ellora Oil & Gas Inc. and Ellora Energy Inc. based upon an analysis of management's estimates of the relative equity value of each of Ellora Oil & Gas Inc. and Ellora Energy Inc. These estimates of equity value were based on an analysis of estimated cash flow and net asset value for both

Ellora Energy Inc. and Ellora Oil & Gas Inc. relative to comparable public companies' cash flow, net asset valuations and equity valuations. Ellora Oil & Gas Inc. stockholders received 2.49 shares of Ellora Energy Inc. for each share of Ellora Oil & Gas Inc. Following the merger, we effected an 8.09216-to-1 stock split of our common stock.

Presentations in this prospectus that reflect shares, shares outstanding, or weighted average shares of our common stock or options exercisable for shares of our common stock are reflected on a post-merger and post-split basis.

Our principal executive offices are located at 5665 Flatiron Parkway, Boulder, Colorado 80301. Our telephone number is (303) 444-8881. Our corporate website address iswww.elloraenergy.com. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

THE OFFERING

Common stock offered by us(1)		8,000,000 shares.
Common stock offered by the selling stockholders		3,363,189 shares.
Common stock to be outstanding after this offering(1)(2)(3)		53,384,387 shares.
Use of proceeds		We expect to receive net proceeds from the sale of shares offered by us, after deducting estimated offering expenses and underwriting discounts and commissions, of approximately $132 million, based on an assumed offering price of $18.00 per share. We intend to use our net proceeds from this offering to repay approximately $132 million of the $144 million that was outstanding under our credit facility as of May 31, 2008. We will not receive any proceeds from the sale of shares of our common stock by the selling stockholders. See "Use of Proceeds."
Dividend policy		We do not anticipate that we will pay cash dividends in the foreseeable future. Our existing credit facility restricts our ability to pay cash dividends.
Risk factors		For a discussion of factors you should consider in making an investment, see "Risk Factors."
Nasdaq Global Market symbol		"LORA"

(1): We have granted the underwriters an option to purchase up to an additional 1,704,478 shares of our common stock at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments. Unless otherwise indicated, share numbers assume that the underwriters do not exercise their option to purchase additional shares of common stock.
(2): Represents 45,384,387 shares outstanding as of March 31, 2008 and the 8,000,000 shares to be issued and sold by us in this offering. Excludes options to purchase 2,515,753 shares of our common stock outstanding as of March 31, 2008, of which 2,478,591 were exercisable within 60 days.
(3): This number of shares outstanding includes 12,400,000 shares of our common stock that were sold by us (2,500,000 shares) and certain of our stockholders (9,900,000 shares) in a private placement in July 2006. As part of the terms of the private placement, we entered into registration rights agreements under which we agreed to file registration statements covering the resale of those shares from time to time by the holders of those shares and to use our commercially reasonable efforts to cause the registration statements to become effective under the Securities Act. We have filed these registration statements concurrently with this offering, and we will not receive any proceeds from the sale of any shares that may be sold under those registration statements.

SUMMARY COMBINED AND CONSOLIDATED HISTORICAL FINANCIAL DATA

The following table shows the combined historical financial data as of and for the year ended December 31, 2005, the consolidated historical financial data as of and for each of the two years ended December 31, 2006 and 2007, and the unaudited combined historical financial data as of and for each of the three-month periods ended March 31, 2007 and 2008 for Ellora Energy Inc. and Ellora Oil & Gas Inc. as if they had been one entity throughout the periods presented. These entities were merged in July 2006. You should read the following summary combined historical financial information together with the combined and consolidated financial statements and related notes included elsewhere in this prospectus. The historical combined and consolidated financial data as of December 31, 2006 and 2007 and for the three fiscal years ended December 31, 2005, 2006 and 2007 were derived from the combined and consolidated audited financial statements included in this prospectus. The financial data for the three-month periods ended March 31, 2007 and 2008 were derived from the unaudited combined interim financial statements also included in this prospectus. The summary combined and consolidated historical results are not necessarily indicative of results to be expected in future periods.

			Year Ended December 31,						Three Months Ended March 31,
			2005		2006		2007		2007		2008
									(Unaudited)
			(In thousands, except per share data)
Operating Results Data
Revenue
	Oil and gas sales		$	47,595	$	52,050	$	71,138	$	12,480	$	25,853
	Gas aggregation, pipeline sales and other			5,487		10,638		9,715		1,428		2,678

		Total revenue		53,082		62,688		80,853		13,908		28,531
Costs and expenses
	Lease operating expense			6,141		10,091		14,200		2,465		4,671
	Production taxes			1,813		1,973		2,467		188		1,168
	Gas aggregation and pipeline cost of sales			4,020		5,247		11,009		1,462		3,266
	Depreciation, depletion and amortization			8,189		11,770		20,883		3,923		7,306
	Exploration			422		3,441		4,016		1,784		2,493
	General and administrative			11,766		11,889		18,381		2,957		6,081
	Interest			716		1,642		5,042		574		1,814

		Total costs and expenses		33,067		46,053		75,998		13,353		26,799

Income before provision for income taxes				20,015		16,635		4,855		555		1,732
Provision for deferred income taxes				9,234		6,424		1,832		214		666

Net income			$	10,781	$	10,211	$	3,023		341		1,066

Net income per common share:
	Basic		$	0.28	$	0.23	$	0.07	$	0.01	$	0.02
	Diluted		$	0.27	$	0.23	$	0.07	$	0.01	$	0.02
Weighted average number of shares of common stock—basic				38,753,063		43,485,783		44,976,810		44,834,644		45,304,950
Weighted average number of shares of common stock—diluted				40,209,654		45,339,821		45,724,270		45,904,921		46,334,649

	As of December 31,
	As of December 31,								As of March 31, 2008
	2005		2006			2007			As of March 31, 2008
									(Unaudited)
	(In thousands)
Balance Sheet Data
Property and equipment, net, successful efforts method	$	170,094	$	216,239		$	326,004		$	341,310
Total assets		192,300		231,913			345,878			370,978
Long-term debt		25,750		16,000			110,000			134,000
Stockholders' equity		131,669		176,166			181,194			177,708
Working capital (deficiency)		3,648		(920	)		(8,815	)		(3,057	)

		Year Ended December 31,									Three Months Ended March 31,
		2005			2006			2007			2007			2008
											(Unaudited)
		(In thousands)
Other Financial Data
Net cash provided (used) by:
	Operating activities	$	30,166		$	29,158		$	19,484		$	714		$	(1,971	)
	Investing activities		(106,355	)		(50,209	)		(112,781	)		(32,750	)		(16,028	)
	Financing activities		76,602			22,219			93,619			44,514			24,000
EBITDA(1)		$	33,777		$	31,427		$	32,872		$	5,375		$	11,543

(1): See "Selected Combined and Consolidated Historical Financial Data—Reconciliation of Non-GAAP Financial Measures" for a reconciliation of our net income to EBITDA.

SUMMARY OF OIL AND GAS DATA

Operating Data

The following table presents certain information with respect to our historical operating data for the years ended December 31, 2005, 2006 and 2007 and the three months ended March 31, 2007 and 2008.

			Year Ended December 31,						Three Months Ended March 31,
			2005		2006		2007		2007		2008
Gross wells
	Drilled			29		40		74				21
	Completed			25		34		64				19
Net wells
	Drilled			24.4		38.6		72.8				20.7
	Completed			21.1		32.6		62.9				18.8
Operating Data
	Net production:
		Natural gas (MMcf)		5,348		6,348		7,459		1,514		2,308
		Oil (MBbl)		125		218		354		51		87
		Total (MMcfe)		6,096		7,656		9,584		1,820		2,830
	Average sales price:
		Natural gas (per Mcf)(1)	$	7.58	$	6.21	$	6.29	$	6.49	$	7.74
		Oil (per Bbl)(1)		56.50		58.36		68.44		52.06		91.75
		Total (per Mcfe)(1)		7.81		6.80		7.42		6.86		9.14
Expenses (per Mcfe)
	Lease operating		$	1.01	$	1.31	$	1.48	$	1.35	$	1.65
	Production taxes			0.30		0.26		0.26		0.10		0.41
	General and administrative			1.93		1.54		1.93		1.62		2.15
	Depreciation, depletion and amortization			1.34		1.53		2.18		2.16		2.58

(1): Before consideration of hedging transactions.

Estimated Reserve Data

The estimates in the table below of our net proved reserves as of March 31, 2008 are based on a reserve report prepared by Ryder Scott.

			As of March 31, 2008
Estimated Proved Reserves
	Gas (Bcf)			179.4
	Oil (MMBbls)			8.3

		Total proved reserves (Bcfe)(1)		229.2

	Total proved developed reserves (Bcfe)			84.9
PV-10 value (millions)(2)
	Proved developed reserves		$	329
	Proved undeveloped reserves			491

		Total PV-10 value	$	820

(1): Based on a conversion rate of 6 Mcfe of gas per Bbl of oil/condensate.
(2): Based on March 31, 2008 average wellhead prices of $9.28 per MMBtu of gas and $97.41 per Bbl of oil held flat for the life of the reserves. See "Selected Combined and Consolidated Historical Financial Data—Reconciliation of Non-GAAP Financial Measures" for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

RISK FACTORS

You should consider carefully each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in our common stock.

Risks Related to Our Business

Oil and gas prices are volatile, and a decline in oil and gas prices would adversely affect our financial results and impede our ability to make capital expenditures necessary to grow.

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for oil and gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, such as:

•: domestic and foreign supply of oil and gas;
•: price and quantity of foreign imports;
•: domestic and foreign governmental regulations;
•: political conditions in or affecting other oil producing and gas producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
•: weather conditions, including unseasonably warm winter weather;
•: technological advances affecting oil and gas consumption;
•: overall U.S. and global economic conditions; and
•: price and availability of alternative fuels.

Further, oil prices and gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 78% of our estimated proved reserves as of March 31, 2008 were gas reserves, our financial results are more sensitive to movements in natural gas prices. In the past, the price of gas has been extremely volatile, and we expect this volatility to continue. During the quarter ended March 31, 2008, the NYMEX natural gas spot price ranged from a high of $9.86 per MMBtu to a low of $7.51 per MMBtu. Our oil and gas revenues for the quarter ended March 31, 2008 were $25.9 million. If, on average, gas prices during that period were $1.00 lower than the actual gas prices, our revenues would have been approximately $2.3 million lower than our actual revenues. If oil was $10.00 lower, revenue would have been reduced by $870,000. The results of higher investment in the exploration for and production of gas and other factors may cause the price of gas to drop. Lower oil and gas prices may not only decrease our revenues but also may reduce the amount of oil and gas that we can produce economically. Lower prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management's plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Our future revenues are dependent on the ability to successfully complete drilling activity.

In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless we

conduct successful exploration and development activities or acquire properties containing proved reserves. Exploration and development activities involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•: lack of acceptable prospective acreage;
•: inadequate capital resources;
•: unexpected drilling conditions; pressure or irregularities in formations; equipment failures or accidents;
•: adverse weather conditions, including hurricanes;
•: unavailability or high cost of drilling rigs, equipment or labor;
•: reductions in oil and gas prices;
•: limitations in the market for oil and gas;
•: title problems;
•: compliance with governmental regulations; and
•: mechanical difficulties.

Drilling multilateral wells may not increase our levels of production or our levels of ultimate recovery, despite the increased costs.

We have recently begun to drill multilateral wells in the James Lime formation in Shelby County. Production or ultimate recovery of hydrocarbons may not be enhanced by utilizing this technique. However, costs to drill multilateral wells will be more than single lateral wells.

The interpretation and analysis of 3-D seismic data does not allow the interpreter to know if hydrocarbons are present or economically producible.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than traditional drilling strategies.

The credit default of one of our customers could have a temporary adverse effect on us.

Our revenues are generated under contracts with a limited number of customers. Results of operations would be adversely affected as a result of non-performance by four of our large customers, which represent 10% or more of our sales, of their contractual obligations. A non-payment default by one of these large customers could have an adverse effect on us, temporarily reducing our cash flow.

Our identified drilling location inventories are scheduled out over several 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 drilling locations as an estimation of our future multi-year drilling activities on our acreage. Our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil and gas prices, costs and drilling results. Our final determination on whether to drill any of these drilling

locations will be dependent upon the factors described elsewhere in this prospectus as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil or gas from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations or financial condition.

Unless we replace our oil and gas reserves, our reserves and production will decline.

Our future oil and gas production depends on our success in finding or acquiring additional reserves. Without any success in drilling, our production would decline at an effective rate of 37% in the first year and at an annual average effective rate of 7% over 10 years. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be affected adversely. For the period January 1, 2005 through March 31, 2008 (39 months), we drilled 152.5 net wells. Our production generally increased as a result of this level of drilling activity. However, in the event that we do not equal or exceed this level of drilling activity, we will likely experience a decline in our production. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.

Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage may decline if our drilling results are unsuccessful.

The results of our exploratory drilling in new or emerging plays, such as the Haynesville Shale, are more uncertain than drilling results in the James Lime and the Hugoton, which are more developed and have established production. Since new or emerging plays and new formations have limited or no production history, we are less able to use past drilling results in those areas to help predict our future drilling results. As a result, we may not achieve success in these new areas if drilling results vary from expectations, and our efforts in these exploratory activities could divert management and capital from our developmental activities. As of March 31, 2008, we had not allocated any unproved property costs to the Haynesville Shale.

Our pending Chesapeake transaction may not close as expected.

Our letter agreement with Chesapeake contemplates a closing of the sale of a 65% working interest in our Haynesville Shale acreage on or before July 31, 2008. The pending sale is subject to standard conditions to closing such as completion of customary due diligence, the negotiation of a mutually acceptable participation agreement, and a condition that title and related contracts and agreements are acceptable to Chesapeake. In the event these conditions are not met or require more time to complete, our transaction with Chesapeake may not close or may result in the reduction in the acreage being sold to them. In such an event, we might not receive all or a portion of the anticipated sale proceeds.

In the future we may depend on the skill, ability and decisions of third party operators to a significant extent.

While we presently operate over 90% of our estimated proved reserves, we may not operate significant properties, including our interests in the Haynesville Shale, in the future. The success of the drilling, development and production of the oil and natural gas properties in which we have or expect

to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations. In instances where we own less than 50% of the working interest, drilling and operating decisions may not be within our control. If we disagree with the decision of a majority of working interest owners or the operator, we may be required, among other things, to postpone the proposed activity, relinquish or farm-out our interest, or decline to participate. If we decline to participate, we might be forced to relinquish our interest or may be subject to certain non-consent penalties, as provided in the applicable operating agreement. Such penalties typically allow participating working interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the nonparticipating working interest owner's share of the cost of such operations.

We face uncertainties in estimating proved oil and gas reserves and negative revisions in our estimates have in recent periods resulted in lower than expected reserve quantities and a lower present value of our proved reserves and may continue to do so in the future.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, some of which are in the control of the Company's management, including:

•: historical production from the area compared with production from other similar producing areas;
•: the assumed effects of regulations by governmental agencies;
•: assumptions concerning future oil and gas prices; and
•: assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

•: estimated drainage and recovery areas and recovery factors;
•: the decline rates of existing and future wells;
•: the quantities of oil and gas that are in place;
•: the quantities of oil and gas that are ultimately recovered;
•: the production and operating costs incurred;
•: the amount and timing of future development expenditures; and
•: future oil and gas sales prices.

As of March 31, 2008, approximately 63% of our proved reserves were either proved undeveloped or proved non-producing. Estimates of proved undeveloped or proved non-producing reserves are even less reliable than estimates of proved developed producing reserves.

We have had significant negative reserve revisions each of the last two years. During each of 2006 and 2007 we revised our reserves downward by approximately 51 Bcfe and 50 Bcfe, respectively. These negative reserve revisions were largely the result of disappointing fracture stimulation results and

encountering water-bearing faults in the James Lime in East Texas and certain wells in Kansas that had poorer reservoir quality than anticipated or were pressure-depleted or drilled in limited-drainage reservoirs. We believe the improved understanding of our properties that has developed since the time of acquisition, our hiring of additional engineering personnel to focus on our reserves, our recent engagement of Ryder Scott as our reserve engineers and an increased focus on reserve assessments by senior management have reduced our risk of having downward revisions to our reserves in the future.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this prospectus should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties. As required by the Securities and Exchange Commission, or SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

•: the amount and timing of actual production;
•: supply and demand for oil and gas;
•: increases or decreases in consumption; and
•: changes in governmental regulations or taxation.

In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general.

You should not assume that the present value of future net revenues from our proved reserves referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If gas prices decline by $1.00 per Mcf, our PV-10 as of March 31, 2008 would decrease from $820 million to $736 million. If oil prices decline by $10.00 per Bbl, our PV-10 as of March 31, 2008 would decrease from $820 million to $779 million.

Our bank lenders can limit our borrowing capabilities, which may materially impact our operations.

At May 31, 2008 our debt outstanding under our credit facility was approximately $144 million, and we intend to use all of the proceeds from this offering to repay a portion of the outstanding balance under our credit facility. Our credit facility subjects us to a number of covenants that impose restrictions on us. Our credit facility also provides for periodic redeterminations of our borrowing base, which may affect our borrowing capacity. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our bank lenders have substantial flexibility to reduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of our bank debt to the extent our outstanding borrowings at such time exceeds the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the loan agreement and an acceleration of the loan.

We intend to finance our development, acquisition and exploration activities with cash flow from operations, bank borrowings and other financing activities. In addition, we may significantly alter our capitalization to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may

default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance which is affected by general economic conditions and financial, business and other factors. Our level of debt affects our operations in several important ways, including the following:

•: a portion of our cash flow from operations is used to pay interest on borrowings;
•: the covenants contained in the agreements governing our debt limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in business conditions;
•: 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 leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices, and could limit our ability to withstand competitive pressures; and
•: any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to increases in interest rates.

We depend on our senior management team and other key personnel. Accordingly, the loss of any of these individuals could adversely affect our business, financial condition and the results of operations and future growth.

Our success is largely dependent on the skills, experience and efforts of our people. The loss of the services of one or more members of our senior management team or of our other employees with critical skills needed to operate our business could have a negative effect on our business, financial conditions and results of operations and future growth. We have not entered into, and do not expect to enter into, employment agreements or non-competition agreements with any of our key employees, other than T. Scott Martin, our President and Chief Executive Officer. See "Management—Employment Agreements and Other Arrangements." Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

Market conditions or transportation impediments may hinder our access to oil and gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and gas processing and transportation may hinder our access to oil and gas markets or delay our production. For example, in areas where we do not own the gathering system, such as in the Hugoton, production may be delayed from time to time while we await connection to the gathering system. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In addition, the amount of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and we are often provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell our oil and gas production, we may have to transport our production by more expensive means, or we may be required to shut in gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering system or pipeline capacity, or significant delay in construction of

necessary gathering and transportation facilities, could adversely affect our business, financial condition and results of operations.

We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.

We typically depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, and issuances of common stock. Our future contractual commitments from April 1, 2008 through March 31, 2013 total $155.0 million and include debt obligations, operating lease obligations, and a firm drilling rig lease commitment. We also require capital to fund our capital budget, including acquisitions. In addition, approximately 63% of our total estimated proved reserves were proved undeveloped as of March 31, 2008. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We will be required to meet our needs from our internally generated cash flow, debt financings, and equity financings.

If our revenues decrease as a result of lower commodity 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. We may, from time to time, need to seek additional financing. Our revolving credit facility contains covenants restricting our ability to incur additional indebtedness without the consent of the lender. If we incur additional debt, the related risks that we now face could intensify.

Even 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 available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our projects, which in turn could lead to a possible loss of properties and a decline in our natural gas reserves.

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

Our industry is cyclical, and from time to time there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment, and supplies are substantially greater. As a result of historically strong prices of oil and gas, the demand for oilfield and drilling services has risen, and the costs of these services are increasing. For example, average day rates for land-based rigs have increased substantially during the last two years. We are particularly sensitive to higher rig costs and drilling rig availability, as we presently have two rigs under contract, with one rig under contract on a month-to-month basis. If the unavailability or high cost of drilling rigs, equipment, supplies, or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected.

We may incur losses as a result of title deficiencies.

We purchase working and revenue interests in the natural gas and oil leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is customary in our industry, we rely upon the judgment of natural gas and oil lease brokers, in-house landmen or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We, in some cases, perform

curative work to correct deficiencies in the marketability of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. We obtain title opinions for specific drilling locations prior to the commencement of drilling. In cases involving more serious title problems, the amount paid for affected natural gas and oil leases can be generally lost, and the target area can become undrillable.

Competition in the oil and gas industry is intense, and many of our competitors have resources that are greater than ours.

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

Operating hazards, natural disasters or other interruptions of our operations including, with respect to our Texas and Louisiana operations, those from hurricanes, could result in potential liabilities, which may not be fully covered by our insurance.

The oil and gas business involves certain operating hazards such as:

•: well blowouts;
•: cratering (catastrophic failure);
•: explosions;
•: uncontrollable flows of oil, gas or well fluids;
•: fires;
•: pollution; and
•: releases of toxic gas.

In addition, our operations in Texas and Louisiana are especially susceptible to damage from natural disasters such as hurricanes and involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, and acquisition, or could result in a loss of our properties.

Our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.

Environmental liabilities may expose us to significant costs and liabilities.

We could incur significant environmental costs and liabilities in our oil and natural gas operations due to the handling of petroleum hydrocarbons and generated wastes, the occurrence of air emissions and water discharges from work-related activities, and the legacy of pollution from historical industry operations and waste disposal practices. Environmental liabilities may arise in both the exploration and production of oil and gas as well as in connection with our gas gathering operations. Failure to comply with applicable environmental laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Moreover, joint and several, strict liability may be incurred under these environmental laws and regulations in connection with spills, leaks or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for exploration, production or development activities for many years, oftentimes by third parties not under our control. Private parties, including the owners of properties upon which we conduct drilling and production activities as well as 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, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover some or any of these costs from insurance. See "Business—Environmental Regulation."

Our growth strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.

Our growth strategy may include acquiring oil and gas businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully.

Furthermore, acquisitions involve a number of risks and challenges, including:

•: diversion of management's attention;
•: the need to integrate acquired operations;
•: potential loss of key employees of the acquired companies;
•: potential lack of operating experience in a geographic market of the acquired business; and
•: an increase in our expenses and working capital requirements.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.

Risks Related to this Offering and Our Common Stock

We are controlled by principal stockholders whose interests may differ from your interests and who will be able to exert significant influence over corporate decisions.

Yorktown Energy Partners V, L.P. and Yorktown Energy Partners VI, L.P., or collectively, Yorktown, own approximately 60.4% of our outstanding common stock. After giving effect to this offering, Yorktown will continue to beneficially own approximately 51.4% of our outstanding common stock (49.8% if the over-allotment option is exercised in full). In addition, two Yorktown representatives serve on our board of directors, and our directors, officers and their affiliates will beneficially own or control approximately 60.4% of our common stock outstanding (58.6% if the over-allotment option is exercised in full). See "Security Ownership of Certain Beneficial Owners and Management." As a result of this ownership, Yorktown will have the ability to nominate all our

directors and will have the ability to control the vote in any election of directors. Yorktown will also have control over our decisions to enter into significant corporate transactions and, in its capacity as our majority stockholder, will have the ability to prevent any transactions that it does not believe are in Yorktown's best interest. As a result, Yorktown will be able to control, directly or indirectly and subject to applicable law, all matters affecting us, including the following:

•: any determination with respect to our business direction and policies, including the appointment and removal of officers;
•: any determinations with respect to mergers, business combinations or dispositions of assets;
•: our capital structure;
•: compensation, option programs and other human resources policy decisions;
•: changes to other agreements that may adversely affect us; and
•: the payment of dividends on our common stock.

Yorktown may also have an interest in pursuing transactions that, in their judgment, enhance the value of their respective equity investments in our company, even though those transactions may involve risks to you as a minority stockholder. In addition, circumstances could arise under which their interests could be in conflict with the interests of our other stockholders or you, a minority stockholder. Also, Yorktown and its affiliates have and may in the future make significant investments in other companies, some of which may be competitors. Yorktown and its affiliates are not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us.

There has been no public market for our common stock, and our stock price may fluctuate significantly.

There is currently no public market for our common stock, and an active trading market may not develop or be sustained after the sale of all of the shares covered by this prospectus. The market price of our common stock could fluctuate significantly as a result of:

•: our operating and financial performance and prospects;
•: quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•: changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;
•: liquidity and registering our common stock for public resale;
•: actual or unanticipated variations in our reserve estimates and quarterly operating results;
•: changes in oil and gas prices;
•: speculation in the press or investment community;
•: sales of our common stock by our stockholders;
•: increases in our cost of capital;
•: changes in applicable laws or regulations, court rulings and enforcement and legal actions;
•: changes in market valuations of similar companies;
•: adverse market reaction to any increased indebtedness we incur in the future;
•: additions or departures of key management personnel;
•: actions by our stockholders;

•: general market and economic conditions, including the occurrence of events or trends affecting the price of natural gas; and
•: domestic and international economic, legal, and regulatory factors unrelated to our performance.

If a trading market develops for our common stock, stock markets in general experience volatility that often is unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets.

We have filed two registration statements registering for resale the 12,400,000 shares of common stock that we sold in our private placement during July 2006. The sale of a large number of shares of our common stock pursuant to the resale registration statements, the perception that any such sale might occur, or the issuance of a large number of shares of our common stock in connection with future acquisitions, equity financings or otherwise, could cause the market price of our common stock to decline significantly. After the completion of this offering, we will have approximately 53.3 million shares of common stock issued and outstanding, including approximately 33.7 million shares of our common stock held or controlled by our executive officers and directors which are or will be eligible for sale under Rule 144 after the expiration of the 180-day lock-up period that is applicable to our executive officers, directors, and certain of our stockholders following the completion of this offering. All of the shares of common stock sold in this offering will be freely tradable without restriction or further registration under the Securities Act by persons other than our "affiliates" (within the meaning of Rule 144 under the Securities Act) immediately upon completion of this offering, subject to the 180-day lock-up period. Additionally, we may file one or more registration statements with the Securities and Exchange Commission providing for the registration of up to approximately 3.6 million additional shares of our common stock issued or reserved for issuance under our employee plans, all of which will be eligible for sale without further registration under the Securities Act.

We do not anticipate paying any dividends on our common stock in the foreseeable future.

We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flow generated by operations to expand our business. Our credit facility will restrict our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict our ability to declare or pay cash dividends on our common stock.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We are currently authorized to issue 125,000,000 shares of common stock and 10,000,000 shares of preferred stock with preferences and rights as determined by our board of directors. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future public offerings or private placements of our securities for capital raising purposes, or for other business purposes.

Our filing of free writing prospectuses may result in certain purchasers of our common stock having a right to seek refunds or damages.

In late September and early October 2007, we made two separate slideshow presentations to two groups of securities analysts regarding our then-current operating business. We filed the two analyst presentations as free writing prospectuses with the SEC shortly after the presentations were made. We later determined, however, that we were not eligible to use a free writing prospectus at that time because the price range of the common stock was not contained on the front cover of the statutory prospectus at the time we filed the presentations.

We do not believe that the use or filing of the presentations constituted an illegal written offer to purchase shares of common stock in this offering in violation of Section 5 of the Securities Act of 1933. However, if such a claim was made by a purchaser of our shares in this offering and the use or filing of the presentations were held by a court to be in violation of Section 5 of the Securities Act of 1933, we could be required to repurchase common stock sold in the offering. We would vigorously defend any claim made in this regard.

We strongly caution you not to place any reliance on the contents of the presentations. The contents of the presentations should be totally disregarded and should not be relied upon when making any investment decision regarding our common stock. Any purchaser of our common stock in this offering should rely only on this prospectus when making an investment decision with respect to our common stock. We have carefully analyzed the slideshow presentations and have concluded that there is no material information included in the slideshows that is not also included in our statutory prospectuses.

Provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. For example, our certificate of incorporation and bylaws provide that no stockholder shall have the right to call a special meeting of the stockholders. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

Based on an assumed initial public offering price of $18.00 per share, purchasers of common stock in this offering will experience immediate and substantial dilution of $12.22 per share.

Based on an assumed initial public offering price of $18.00 per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $12.22 per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of March 31, 2008 after giving effect to this offering would be $5.78 per share. See "Dilution."

We will incur increased costs as a result of being a public company.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. The U.S. Sarbanes-Oxley Act of 2002 and related rules of the SEC and the Nasdaq Global Market regulate corporate governance practices of public companies. We expect that compliance with these public company requirements will increase our costs and make some activities more time consuming. For example, we have created new board committees, and we will adopt new internal controls and disclosure controls and procedures. In addition, we will incur additional expenses associated with our SEC reporting requirements. A number of those requirements will require us to carry out activities we have not conducted previously. For example, under Section 404 of the Sarbanes-Oxley Act, for our annual report on Form 10-K for the year ending December 31,

2008, we will need to document and test our internal control procedures, and our management will need to assess and report on our internal control over financial reporting. In addition, for the year ending December 31, 2009, we will not only have to continue with management's assessment and report, but also our independent auditors will need to issue an opinion on the effectiveness of those controls. Furthermore, if we identify any issues in complying with those requirements (for example, if we or our independent auditors identified a material weakness or significant deficiency in our internal control over financial reporting), we could incur additional costs rectifying those issues, and the existence of those issues could adversely affect us, our reputation or investor perceptions of us. We also expect that it could be difficult and will be significantly more expensive to obtain directors' and officers' liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers. Advocacy efforts by stockholders and third parties may also prompt even more changes in governance and reporting requirements. We cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future reserves, production, revenues, income, and capital spending. When we use the words "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," or their negatives, other similar expressions, or the statements that include those words are usually forward-looking statements.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the "Risk Factors" section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

•: our business strategy;
•: our financial position;
•: our cash flow and liquidity;
•: declines in the prices we receive for our oil and gas affecting our operating results and cash flows;
•: economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers;
•: uncertainties in estimating our oil and gas reserves;
•: replacing our oil and gas reserves;
•: uncertainties in exploring for and producing oil and gas;
•: our inability to obtain additional financing necessary in order to fund our operations, capital expenditures, and to meet our other obligations;
•: availability of drilling and production equipment and field service providers;
•: disruptions capacity constraints in, or other limitations on the pipeline systems which deliver our gas and other processing and transportation considerations;
•: the closing of the Chesapeake transaction;
•: competition in the oil and gas industry;
•: our inability to retain and attract key personnel;
•: the effects of government regulation and permitting and other legal requirements;
•: costs associated with perfecting title for mineral rights in some of our properties; and
•: other factors discussed under "Risk Factors."

USE OF PROCEEDS

We estimate that the net proceeds to us from the sale of common stock in this offering will be approximately $132 million, based on an offering price of $18.00 per share, and after deducting the underwriting discount and estimated offering expenses of approximately $12 million payable by us. We intend to use all of the net proceeds from this offering to repay a portion of the debt that is outstanding under our credit facility. Each dollar increase (decrease) in the per share offering price will increase (decrease) the amount of net proceeds we receive from this offering by approximately $7.4 million.

If the underwriters exercise their over-allotment option in full, we estimate that the net proceeds to us will increase by approximately $28.5 million after deducting underwriters' discounts. We intend to use any net proceeds from the exercise of the over-allotment option to repay the balance outstanding under our credit facility, to fund a portion of our 2008 capital expenditures and for other general corporate purposes.

At May 31, 2008, total borrowings under our credit facility were approximately $144 million with an interest rate of 4.69%. We incurred the debt under the credit facility principally to meet our capital expenditure requirements. We believe that we will have approximately $12 million of outstanding indebtedness under our credit facility after the closing of this offering, leaving us with approximately $148 million available for future borrowings under our credit facility. On May 1, 2008, we entered into a new credit facility that increased our borrowing base from $150 million to $190 million, which borrowing base will be decreased to $160 million upon the completion of this offering, and we expect to have approximately $148 million available for borrowings. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Credit Facility" for a description of our credit facility. Also, see "Prospectus Summary—Summary of Capital Expenditures." Certain affiliates of one of the underwriters in this offering are lenders under our credit facility and will receive a portion of the net proceeds we receive from this offering as a result of our repayment of a portion of the loans they have extended under our credit facility.

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

On June 4, 2008, we entered into a binding letter agreement to sell a 65% working interest in our deep rights in East Texas for approximately $350 million in a transaction that we expect to close on or before July 31, 2008. We intend to use the proceeds from this sale for debt reduction and general corporate purposes including, but not limited to, acquisition and exploration and development activities.

DIVIDEND POLICY

We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to reinvest cash flow generated by operations in our business. Our credit facility currently limits our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that prohibit or restrict our ability to declare or pay cash dividends on our common stock.

CAPITALIZATION

The following table sets forth our cash and capitalization as of March 31, 2008 on an actual historical basis and on an as adjusted basis after giving effect to this offering, based on an assumed offering price of $18.00 per share, net of the offering expenses and underwriters' discount, and the application of the estimated net proceeds as described above under "Use of Proceeds."

You should refer to "Summary Combined and Consolidated Historical Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the annual combined financial statements included elsewhere in this prospectus in evaluating the material presented below.

			As of March 31, 2008
			Actual		As Adjusted
			(In thousands)
Cash(1)			10,652		10,652

Long-term debt(1)(2)			134,000		2,000

Stockholders' equity:
	Common stock		45		53
	Additional paid-in capital		147,811		279,803
	Retained earnings		35,118		35,118
	Accumulated other comprehensive income		(5,266	)	(5,266	)

		Total stockholders' equity	177,708		309,708

Total capitalization			311,708		311,708

(1): As of May 31, 2008, assuming completion of this offering and our sale of a 65% working interest in our deep rights in East Texas for approximately $350,000,000, our "as adjusted" cash would range from $347,179,000 to $359,179,000, and our long-term debt would range from $0 to $12,000,000 depending on the amount of proceeds used for debt reduction.
(2): As of May 31, 2008, we had an outstanding balance under our credit facility of $144,000,000.

DILUTION

At March 31, 2008, the net tangible book value per share of our common stock was $3.90. Net tangible book value per share is determined by dividing our tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock. After giving effect to the sale of the shares in this offering and based on an assumed offering price of $18.00 per share, assuming the receipt of the estimated net proceeds, after deducting the estimated discounts and offering expenses, our net tangible book value at March 31, 2008 would have been approximately $5.78 per share. This represents an immediate and substantial increase in the net tangible book value of $1.88 per share to existing stockholders and an immediate dilution of $12.22 per share to new investors purchasing common stock in this offering, resulting from the difference between the offering price and the net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing common stock in this offering:

Offering price per share				$	18.00
	Net tangible book value per share at March 31, 2008	$	3.90
	Increase per share attributable to new investors	$	1.88

	As adjusted net tangible book value per share after this offering			$	5.78

Dilution per share to new investors				$	12.22

The following table sets forth, at March 31, 2008, the number of shares of common stock to be sold by us in this offering, the net tangible book value as of March 31, 2008, on a percentage basis, and the net tangible book value per common share based on the average of the total contributions:

	Shares Issued			Total Consideration
	Shares Issued			Total Consideration				Average Consideration Per Share
	Number	Percent		Amount		Percent		Average Consideration Per Share
Shares issued by us in this offering(1)	8,000,000	15.0	%	$	144,000,000	49.3	%	$	18.00
Shares owned by existing stockholders	45,384,387	85.0	%		147,856,000	50.7	%	$	3.26

Total	53,384,387	100.0	%	$	291,856,000	100.0	%	$	5.47

(1): Excludes shares being sold by the selling stockholders and any shares issued to the selling stockholders prior to the closing of this offering due to the exercise of stock options.

If the underwriters' over-allotment option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to 13,067,667 or approximately 23.8% of the total number of shares of common stock outstanding immediately following this offering.

The data in the above table excludes 2,515,753 shares of common stock subject to options outstanding as of March 31, 2008, which have an exercise price ranging from $1.24 per share to $4.95 per share. As of March 31, 2008, options to purchase 2,366,757 of our common stock were currently exercisable. If these options were exercised at the average exercise price, the additional dilution per share to new investors would be $0.09.

SELECTED COMBINED AND CONSOLIDATED HISTORICAL FINANCIAL DATA

The following table shows the selected combined historical financial data as of and for each of the three years ended December 31, 2003, 2004 and 2005, the selected consolidated historical financial data as of and for each of the two years ended December 31, 2006 and 2007, and the unaudited selected combined historical financial data as of and for each of the three-month periods ended March 31, 2007 and 2008 for Ellora Energy Inc. You should read the following summary combined and consolidated historical financial information together with the combined and consolidated financial statements and related notes included elsewhere in this prospectus. The selected historical combined financial and operating data for the year ended December 31, 2005 and the selected historical consolidated financial and operating data for each of the two years ended December 31, 2006 and 2007 are derived from our audited financial statements included herein. The data for the three-month periods ended March 31, 2007 and 2008 were derived from the unaudited combined interim financial statements also included in this prospectus. The summary combined and consolidated historical results are not necessarily indicative of results to be expected in future periods.

			Year Ended December 31,															Three Months Ended March 31,
			2003			2004			2005			2006			2007			2007			2008
																		(Unaudited)
			(In thousands, except per share data)
Operating Results Data
Revenue:
	Oil and gas sales		$	11,810		$	22,780		$	47,595		$	52,050		$	71,138			12,480			25,853
	Gas aggregation, pipeline sales and other			365			1,491			5,487			10,638			9,715			1,428			2,678

		Total revenue		12,175			24,271			53,082			62,688			80,853			13,908			28,531
Costs and expenses:
	Lease operating expense			2,580			4,539			6,141			10,091			14,200			2,465			4,671
	Production taxes			473			1,291			1,813			1,973			2,467			188			1,168
	Gas aggregation and pipeline cost of sales			—			1,316			4,020			5,247			11,009			1,462			3,266
	Depreciation, depletion and amortization			1,432			3,479			8,189			11,770			20,883			3,923			7,306
	Exploration			—			—			422			3,441			4,016			1,784			2,493
	General and administrative			2,497			3,407			11,766			11,899			18,381			2,957			6,081
	Interest			219			355			716			1,642			5,042			574			1,814

		Total costs and expenses		7,201			14,387			33,067			46,053			75,998			13,353			26,799

Income before provision for income taxes				4,974			9,884			20,015			16,635			4,855			555			1,732
Current income tax expense (benefit)				(254	)		—			—			—
Provision for deferred income taxes				2,053			3,850			9,234			6,424			1,832			214			666

Cumulative effect of accounting change				30			—			—			—			—			—			—

Net income			$	3,205		$	6,034		$	10,781		$	10,211		$	3,023			341			1,066

Net income per common share:
	Basic		$	0.15		$	0.22		$	0.28		$	0.23		$	0.07		$	0.01		$	0.02
	Diluted		$	0.15		$	0.22		$	0.27		$	0.23		$	0.07		$	0.01		$	0.02
Balance Sheet Data
Property and equipment, net, successful efforts method			$	44,566		$	70,811		$	170,094		$	216,239		$	326,004		$	248,047		$	341,310
Total assets				51,681			80,206			192,300			231,913			345,878			278,352			370,978
Long-term debt				6,333			10,683			25,750			16,000			110,000			61,000			134,000
Stockholders' equity				37,423			51,757			131,669			176,166			181,194			176,445			177,708
Working capital (deficiency)				96			(1,581	)		3,648			(920	)		(8,815	)		12,966			(3,057	)
Other Financial Data
Net cash provided (used) by:
		Operating activities	$	6,746		$	16,313		$	30,166		$	29,158		$	19,484		$	714		$	(1,971	)
		Investing activities		(19,165	)		(27,491	)		(106,355	)		(50,209	)		(112,781	)		(32,750	)		(16,028	)
		Financing activities		10,448			12,350			76,602			22,219			93,619			44,514			24,000
EBITDA(1)			$	6,655		$	13,718		$	33,777		$	31,427		$	32,872		$	5,375		$	11,543

(1): See "—Reconciliation of Non-GAAP Financial Measures" below for additional information.

Reconciliation of Non-GAAP Financial Measures

The following table shows our reconciliation of our standardized measure of discounted future net cash flows to our PV-10 (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

	As of March 31, 2008
	(In thousands)
Standardized measure of discounted future net cash flows	$	548,095
Present value of future income taxes discounted at 10%		272,146

PV-10	$	820,241

The following table reconciles our net income to EBITDA. EBITDA is defined as net income or loss before interest, income taxes, non-cash compensation, depreciation, depletion and amortization. We have reported EBITDA because we believe EBITDA is useful to investors as an indicator of a company's operating performance and ability to incur and service debt. Management also believes that EBITDA facilitates investors in comparing a company's performance on a consistent basis without regard to capital structures or financing methods. One of the loan covenants in our credit agreement is a measurement of EBITDA plus exploration costs, which is referred to as EBITDAX, compared to total debt outstanding. Our exploration costs are disclosed in our financial statements as a separate line item and include exploratory dry holes, geologic and geophysical costs, and delay rentals.

While we have disclosed our EBITDA to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDA as reported by us may not be comparable in all instances to EBITDA as reported by other companies. In addition, EBITDA amounts may not be fully available for management's discretionary use, due to the requirements to conserve funds for capital expenditures, debt service or other commitments. EBITDA should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles.

		Year Ended December 31,										Three Months Ended March 31,
		2003		2004		2005		2006		2007		2007		2008
		(In thousands)										(Unaudited)
Net income		$	3,205	$	6,034	$	10,781	$	10,211	$	3,023	$	341	$	1,066
	Income taxes		1,799		3,850		9,234		6,424		1,832		214		666
	Non-cash compensation		—		—		4,857		1,380		2,092		323		691
	Depreciation, depletion and amortization		1,432		3,479		8,189		11,770		20,883		3,923		7,306
	Interest		219		355		716		1,642		5,042		574		1,814

EBITDA		$	6,655	$	13,718	$	33,777	$	31,427	$	32,872	$	5,375	$	11,543

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

The following discussion is intended to assist in understanding our results of operations and our present financial condition. Our combined and consolidated financial statements and the accompanying notes included elsewhere in this prospectus contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed.

Overview

We are an independent oil and gas company engaged in the acquisition, development, production and exploration of onshore U.S. oil and gas properties. We own and operate an approximate 100-mile pipeline in East Texas that gathers and transports gas in the area for delivery to other pipelines. Our properties are concentrated in East Texas and in the Hugoton field in southwest Kansas. We have increased our proved reserves and production primarily through acquisitions in conjunction with an active drilling program. From inception (April 2002) we have acquired approximately 115 Bcfe of proved reserves (approximately 78 Bcfe net of revisions) for approximately $123 million.

We continually evaluate opportunities to expand our position in our core areas. Since inception, we have closed four East Texas acquisitions: two consisting of reserve acquisitions, one to increase our pipeline ownership position and one to acquire the Shelby Pipeline. The total cost of these acquisitions was approximately $48.2 million. In addition, we have spent approximately $73 million for our current position in the Hugoton field from our initial acquisition in 2005 and our most recent acquisition in 2007.

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

We have identified the impact of generally higher commodity prices in the last several years as compared to prior periods as an important trend that we expect to affect our business in the future. If commodity prices continue at present relatively high levels or increase, we would expect this trend to result not only in increased revenue from the increased commodity prices, but also in an increasingly competitive environment for good drilling prospects, qualified geological and technical personnel and oil field services, including rigs. Competition in these areas, which we expect to increase so long as commodity prices remain relatively high, will likely result in higher costs in these areas, and could result in unavailability of drilling rigs, and thus could affect the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our combined and consolidated financial statements, which have been prepared in accordance with accounting policies generally accepted in the United States of America. The preparation of our combined and consolidated financial statements requires us to make estimates and assumptions that

affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some 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. Actual results may differ from the estimates and assumptions used in the preparation of our combined and consolidated financial statements. Described below are the most significant policies we apply in preparing our combined and consolidated financial statements some of which are subject to alternative treatments under accounting policies generally accepted in the United States of America. We also describe the most significant estimates and assumptions we make in applying these policies. See notes to the financial statements under the heading "Summary of Significant Accounting Policies" for additional accounting policies and estimates by management.

Oil and Gas Activities

Accounting for oil and gas activities is subject to special, unique rules. We utilize the successful efforts method for accounting for our oil and gas activities. The significant principles for this method are:

•: Geological and geophysical evaluation costs are expensed as incurred.
•: Developmental dry holes remain capitalized.
•: Impairments of properties, if any, are based on the evaluation of the carrying value of properties against their fair value based upon pools of properties grouped by geographical and geological conformity.

Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation, and amortization expense; evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time as a result of changing results from operational activity and results. Changes in commodity prices, operation costs and techniques will also change and may affect the overall evaluation of reservoirs.

Our estimated proved reserves as of March 31, 2008 were prepared by Ryder Scott.

Derivative Instruments and Hedging Activities

We enter into derivative contracts to hedge future gas and crude oil production to mitigate a portion of the risk of market price fluctuations.

To designate a derivative as a cash flow hedge, we document at the hedge's inception our assessment as to whether the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge, if any, is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged.

If, during the derivative's term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses on the effective portion of the derivative are reclassified to earnings when the underlying transaction occurs. If it is determined that the designated hedge transaction is not likely to occur, any unrealized gains or losses

are recognized immediately in the consolidated statements of income as a derivative fair value gain or loss.

Recent Accounting Pronouncements

In September 2006, the FASB issued FAS No. 157, "Fair Value Measurements" ("FAS 157"). FAS 157 defines fair value to measure assets and liabilities, establishes a framework for measuring fair value, and requires additional disclosures about the use of fair value. FAS 157 is applicable whenever another accounting pronouncement requires or permits assets and liabilities to be measured at fair value. FAS 157 does not expand or require any new fair value measures. FAS 157 is effective for our fiscal year beginning January 1, 2008. We are currently evaluating the impact that the adoption of FAS 157 will have on our financial position or results of operations.

In February 2007, the FASB issued FAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" ("FAS 159"). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. FAS 159 is effective as of the beginning of an entity's first fiscal year that begins after November 15, 2007, which for us will be January 1, 2008. We are currently evaluating the impact of adopting FAS 159 on our financial position and results of operations.

Effects of 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, 2005, 2006 or 2007. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher prices.

Stock Based and Other Compensation

Our Amended and Restated 2006 Stock Incentive Plan allows grants of stock and or options to management and key employees. Granting of awards may increase our general and administrative expenses subject to the size and timing of the grants.

Public Company Expenses

We believe that our general and administrative expenses will increase in connection with the completion of this offering. This increase will consist of legal and accounting fees and additional expenses associated with compliance with the Sarbanes-Oxley Act of 2002 and other regulations. We anticipate that our ongoing general and administrative expenses will also increase as a result of being a publicly traded company. This increase will be due primarily to the cost of accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors' fees, directors' and officers' insurance, and registrar and transfer agent fees. As a result, we believe that our general and administrative expenses for future periods will increase significantly. Our consolidated financial statements following the completion of this offering will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods prior to the completion of this offering.

Results of Operations

In April 2005 we acquired Presco Western, LLC and in August 2005 we acquired additional acreage in Shelby County, Texas. These acquisitions substantially changed the magnitude of our

operations and resulted in substantially increased production volumes for which the acquired properties were included in the 2005 results from the date of acquisition, together with corollary increases in related income and expenses.

Three Months Ended March 31, 2007 and 2008

		Three Months Ended March 31,
		2007		2008
Net production:
	Natural gas (MMcf)		1,514		2,308
	Oil (MBbl)		51		87
Average sales price before hedging:
	Natural gas (per Mcf)	$	6.49	$	7.74
	Oil (per Bbl)		52.06		91.75
Oil and gas sales (in thousands)		$	12,480	$	25,853
Costs and expenses (in thousands):
	Lease operating expenses	$	2,465	$	4,671
	Production taxes		188		1,168
	Depreciation, depletion and amortization		3,923		7,306
	Exploration		1,784		2,493
	General and administrative		2,957		6,081
	Interest		574		1,814

Oil and Gas Sales. Our oil and gas sales increased from $12.5 million for the three-month period ended March 31, 2007 to $25.9 million for the comparable period in 2008, primarily as a result of a 55% increase in our net production and increased commodity prices. Our increased drilling program increased production in East Texas by 56% and production in Kansas by 78%. Gas prices and oil prices increased by 19% and 76%, respectively.

Gas Aggregation and Pipeline Sales. Gas aggregation and pipeline sales increased from $1.1 million for the three-month period ended March 31, 2007 to $3.7 million for the comparable period in 2008, primarily as a result of increased volumes of third party gas being transported, more favorable margins on the sales of third-party gas, and from the additional revenues derived from our acquisition of the Shelby Pipeline in March 2007. These revenues are derived strictly from transmission and sales of third party gas and gas transactions.

Gain (Loss) on Oil and Gas Hedging Activities. Gains on oil and gas hedging activities decreased from a gain of $271,000 for the three months ended March 31, 2007 to a loss of $995,000 for the comparable period in 2008. Our gains for the three months ended March 31, 2007 were the result of puts having a weighted average price of $10.00 covering 5% of our production during the period. Our losses for the three months ended March 31, 2008 were the result of puts having a weighted average price of $8.11 for 50% of our production for the period.

Lease Operating Expenses. Our lease operating expenses increased from $2.5 million for the three-month period ended March 31, 2007 to $4.7 million for the comparable period in 2008. The increase in 2008 was a result of a 55% increase in our net production, increased costs in the industry for field services and ad valorem taxes.

Production Taxes. Our production taxes increased from $188,000 for the three-month period ended March 31, 2007 to $1.2 million for the comparable period in 2008. In addition to the 55% increase in our production volume during the first quarter of 2008, we received a significant amount of

tax credit refunds during the three months ended March 31, 2007 that lowered costs during that period. Our production taxes are generally calculated as a percentage of oil and gas sales revenue before the effects of hedging.

Gas Aggregation and Pipeline Cost of Sales. Our gas aggregation and pipeline cost of sales increased from $1.5 million for the three-month period ended March 31, 2007 to $3.3 million for the comparable period in 2008. The increase is due to increased volumes transported and costs related to pipeline operations for the Shelby Pipeline for a full three-month period during the first quarter of 2008 as compared with a period of less than one month during the first quarter of 2007 when we acquired the Shelby Pipeline.

Depreciation, Depletion and Amortization (DD&A). Depreciation, depletion and amortization expenses increased from $3.9 million for the three-month period ended March 31, 2007 to $7.3 million for the comparable period in 2008. This is a result of increased production and increased per unit rate for depletion associated with higher finding and development costs. Our DD&A rate used for the three months ended March 31, 2008 was $2.58 per Mcfe as compared to a rate of $2.16 per Mcfe for the comparable period in 2007.

Exploration. Exploration costs increased from $1.8 million for the three-month period ended March 31, 2007 to $2.5 million for the comparable period in 2008. Of the $2.5 million of costs incurred during the three months ended March 31, 2008, $2.1 million was attributable to seismic acquisition and interpretation costs.

General and Administrative. General and administrative costs increased from $3.0 million for the three-month period ended March 31, 2007 to $6.1 million in the comparable period in 2008. As we have grown, we have added additional staff to assist in our operations and the exploitation and evaluation of our properties.

Interest Expense. Interest expense increased from $574,000 for the three-month period ended March 31, 2007 to $1.8 million for the comparable period in 2008. Interest costs are a function of amounts borrowed, the effective rate for borrowing, and interest capitalization. Thus, the increased interest expense was a function of higher interest rates and a larger average balance outstanding.

Income Taxes. Income tax expense increased from $214,000 for the three-month period ended March 31, 2007 to $660,000 for the comparable period in 2008, as our net income before taxes increased $1.2 million. Income taxes are recorded at the combined federal and state effective rate of 38.5%. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. All income taxes for the three months ended March 31, 2007 and 2008 were deferred.

Year Ended December 31, 2006 and 2007

		Year Ended December 31,
		2006		2007
Net production:
	Natural gas (MMcf)		6,348		7,459
	Oil (MBbl)		218		354
Average sales price before hedging:
	Natural gas (per Mcf)	$	6.21	$	6.29
	Oil (per Bbl)		58.36		68.44
Oil and gas sales (in thousands)		$	52,050	$	71,138
Costs and expenses (in thousands):
	Lease operating expenses	$	10,091	$	14,200
	Production taxes		1,973		2,467
	Depreciation, depletion and amortization		11,770		20,883
	Exploration		3,441		4,016
	General and administrative		11,889		18,381
	Interest		1,642		5,042

Oil and Gas Sales. Our oil and gas sales increased from $52.1 million for the year ended December 31, 2006 to $71.1 million for the comparable period in 2007, primarily as a result of a 25% increase in our net production. Oil volumes increased significantly from our drilling results in Kansas. Gas prices and oil prices increased by 1% and 17%, respectively.

Gas Aggregation and Pipeline Sales. Gas aggregation and pipeline sales increased from $4.5 million for the year ended December 31, 2006 to $11.0 million for the comparable period in 2007, primarily as a result of increased volumes of third party gas being transported and, to a lesser extent, from the additional revenues derived from acquiring the Shelby Pipeline in March 2007. These revenues are derived strictly from transmission and sales of third party gas and other gas transactions.

Gain on Oil and Gas Hedging Activities. We account for our hedging transactions as "cash flow" hedges, whereby realized gains and losses are recognized as revenue. Unrealized gains and losses are recognized within comprehensive income and loss. Gains on oil and gas hedging activities decreased from $6.1 million for the year ended December 31, 2006 to a loss of $1.4 million for the comparable period in 2007. Our gains for the year ended December 31, 2006 were the result of puts having a weighted average price of $10.23 per Mcfe covering 34% of our production during the period. Our losses for the year ended December 31, 2007 were the result of gas puts and oil swaps having a weighted average price of $8.43 per Mcfe for 19% of our production for the period.

Lease Operating Expenses. Our lease operating expenses increased from $10.1 million for the year ended December 31, 2006 to $14.2 million for the comparable period in 2007. Our 2006 lease operating expenses included approximately $1 million associated with the re-entry and workover of a horizontal well in East Texas. The increase in 2007 was a result of increased production of 25%, increased costs in the industry for maintenance and acquisitions, and increased use of compression to enhance production in Texas.

Production Taxes. Our production taxes increased from $2.0 million for the year ended December 31, 2006 to $2.5 million for the comparable period in 2007. In addition to our increased volume in 2007, we received a significant amount of tax credit refunds in 2006 that lowered costs during that period. Our production taxes are generally calculated as a percentage of oil and gas sales

revenue before the effects of hedging. We take full advantage of all credits and exemptions from various taxing authorities.

Gas Aggregation and Pipeline Cost of Sales. Our gas aggregation and pipeline cost of sales increased from $5.2 million for the year ended December 31, 2006 to $11.0 million for the comparable period in 2007. The increase is primarily related to increased purchases of third-party gas, compressor rentals, maintenance, and other pipeline costs related to the Shelby Pipeline, which we acquired in the first quarter of 2007.

Depreciation, Depletion and Amortization (DD&A). Depreciation, depletion and amortization expenses increased from $11.8 million for the year ended December 31, 2006 to $20.9 million for the comparable period in 2007. This is a result of increased production and increased per unit rate for depletion associated with higher finding and development costs. Our DD&A rate used for the year ended December 31, 2007 was $2.18 per Mcfe as compared to a rate of $1.53 per Mcfe for the comparable period in 2006.

Exploration. Exploration costs increased from $3.4 million for the year ended December 31, 2006 to $4.0 million for the comparable period in 2007. All costs incurred for exploration were for seismic acquisition and interpretation. Costs increased as we started our acquisition of seismic data in Kansas that will approximate $4 million per year for the next three years.

General and Administrative. General and administrative costs increased from $11.9 million for the year ended December 31, 2006 to $18.4 million in the comparable period in 2007. As we have grown, we have added additional staff to assist in our operations and the exploitation and evaluation of our properties.

Interest Expense. Interest expense increased from $1.6 million for the year ended December 31, 2006 to $5.0 million for the comparable period in 2007. Interest costs are a function of amounts borrowed and the effective rate for borrowing. Thus, the increased interest expense was a function of higher rates and a much larger average balance outstanding.

Income Taxes. Income tax expense decreased from $6.4 million for the year ended December 31, 2006 to $1.8 million for the comparable period in 2007, as our net income before taxes declined by $11.8 million. Income taxes are recorded at the combined federal and state effective rate of 38.5%. We are allowed to deduct various items for tax that are capitalized for purposes of presentation on our financial statements and no taxes are due and payable.

Years Ended December 31, 2005 and 2006

		Year Ended December 31,
		2005		2006
Net production:
	Natural gas (MMcf)		5,348		6,348
	Oil (MBbl)		125		218
Average sales price before hedging:
	Natural gas (per Mcf)	$	7.58	$	6.21
	Oil (per Bbl)		56.50		58.36
Oil and gas sales (in thousands)		$	47,595	$	52,050
Costs and expenses (in thousands):
	Lease operating expenses	$	6,141	$	10,091
	Production taxes		1,813		1,973
	Depreciation, depletion and amortization		8,189		11,770
	Exploration		422		3,441
	General and administrative		11,766		11,889
	Interest		716		1,642

Oil and Gas Sales. Oil and gas sales increased from $47.6 million in 2005 to $52.0 million in 2006 as a result of a 26% increase in net production. Offsetting our increase in net production was a 13% decrease in the blended average sales price of oil and gas. We had no acquisitions of producing properties in 2006. During 2006, we drilled 40 wells (38.6 net) and completed 34 wells (32.6 net).

Gas Aggregation and Pipeline Sales. Our gas aggregation and pipeline sales decreased from $5.6 million in 2005 to $4.5 million in 2006. These revenues represent only those amounts from third-party interests and do not include amounts for the transportation of our gas. Our revenues decreased by 19% as we sold less gas on behalf of third parties. Volumes transported on behalf of others was comparable for each year.

Gain on Oil and Gas Hedging Activities. Gains on oil and gas hedging activities were approximately $6.1 million for the year ended December 31, 2006. These gains were the result of puts having a weighted average price of $10.23 per Mcf covering 34% of our production. In 2005, we had nominal hedging activity.

Lease Operating Expense. Our lease operating expenses increased from $6.1 million in 2005 to $10.1 million in 2006. Costs increased 64% from 2005 to 2006 while production increased 26%. The significant increase was caused by an increase for all supplies and services in the field as well as approximately $1 million incurred to reenter a horizontal well in East Texas to install hardware for stimulation to the well.

Production Taxes. Our production taxes increased from $1.8 million in 2005 to $2.0 million in 2006. During both years, we applied for and received significant refunds of production taxes for wells drilled in previous years. Thus, the tax amounts reflected in the accompanying financial statements are significantly below the anticipated rates due to the refunds received.

Gas Aggregation and Pipeline Cost of Sales. Our gas aggregation and pipeline cost of sales increased from $4.0 million in 2005 to $5.3 million in 2006, primarily as a result of increased volumes of third party gas being transported and, to a lesser extent, from the additional revenues derived from buying and selling pipeline gas. These revenues are derived strictly from transmission and sales of third party gas and gas transactions.

Depreciation, Depletion and Amortization (DD&A). Our depreciation, depletion and amortization increased from $8.2 million in 2005 to $11.8 million in 2006, an increase of 44%. Our production increased 36%. The remainder of this increase can be attributed to an increase in finding costs in 2006 that were associated with a significant increase in the cost of drilling rigs and all other costs associated with drilling oil and gas wells.

Exploration. Our exploration costs increased from $0.4 million in 2005 to $3.4 million in 2006. All of the exploration costs in 2005 were associated with the acquisition and interpretation of seismic data. In 2006, we were associated with a non-operated deep exploration well in Louisiana. Our share of this dry hole was approximately $1.0 million. The remainder of the exploration costs in 2006 were for the acquisition and interpretation of seismic data.

General and Administrative. Our general and administrative costs increased from approximately $11.8 million in 2005 to $11.9 million in 2006. However, our 2005 expenses included $4.8 million of non-cash compensation charges associated with the sale of stock to officers and our 2006 expenses included $1.4 million of non-cash charges for the cost associated with stock options in 2006. Excluding these non-cash charges, the cost increase in 2006 was $3.5 million, a direct result of adding additional personnel for our operations.

Interest Expense. Interest expense increased from $716,000 in 2005 to $1.6 million in 2006, as we had higher levels of debt outstanding in support of our drilling program.

Income Taxes. Our income tax expense decreased from $9.2 million in 2005 to $6.4 million in 2006 as our net income before provision for income taxes was less in 2006 than in 2005. In addition, $4.8 million non-cash compensation charge in 2005 was non-deductible for tax purposes.

Capital Resources and Liquidity

For the three months ended March 31, 2008, we borrowed $24 million from our line of credit, the proceeds of which we used to fund our drilling operations and to acquire $2.1 million of seismic data. In February 2007, we acquired a 100% interest in a 20-mile pipeline in East Texas to connect to and supplement our pipeline operations in the Huxley Field for $6.5 million. In March 2007, we acquired the mineral interests underlying our farmout in the Hugoton Deep, as well as additional acreage and producing properties for $27.3 million, of which $11.7 million had closed as of March 31, 2007.

For the year ended December 31, 2007, we borrowed $94.0 million from our line of credit and generated $19.5 million of cash from operations, the proceeds of which we used to fund our drilling operations and for two acquisitions we made in 2007. In February 2007, we acquired a 100% interest in a 20-mile pipeline in East Texas to connect to and supplement our pipeline operations in the Huxley Field for $6.5 million. In March 2007, we acquired the mineral interests underlying our farmout in the Hugoton Deep in Kansas, as well as additional acreage and producing properties for $28 million.

During 2006, we generated $29.2 million in cash from operations, $26.5 million in cash from our July 2006 equity offering, and borrowed $47.9 million under our line of credit. We used the proceeds from the sale of our common stock to pay back the outstanding amount under our credit facility, but subsequently borrowed additional funds under the line of credit to support our drilling operations, including $53.9 million for drilling in East Texas and Kansas.

For the year ended December 31, 2005, our primary sources of cash were from financing and operating activities. Approximately $121.2 million in proceeds from the sale of stock, borrowings from our line of credit, and cash produced from operations were used to acquire the deep mineral interests in the Hugoton field in southwest Kansas via the acquisition of Presco Western, LLC and additional working interests in producing properties in East Texas.

Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations, particularly China and India. Our working capital is significantly influenced by changes in commodity prices and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations were primarily used to fund exploration and development of our mineral interests. Our cash flows from operations have increased each year since inception as has our investment in the development of our interests.

The following table summarizes our sources and uses of funds for the periods presented:

	Year Ended December 31,									Three Months Ended March 31,
	2005			2006			2007			2007			2008
	(In thousands)
Cash flows provided (used) by operations	$	30,166		$	29,158		$	19,484		$	714		$	(1,971	)
Cash flows used in investing activities		(106,355	)		(50,209	)		(112,781	)		(32,750	)		(16,028	)
Cash flows provided by financing activities		76,602			22,219			93,619			44,514			24,000

Net increase (decrease) in cash and cash equivalents	$	413		$	1,168		$	322		$	12,478		$	6,001

On June 4, 2008, we entered into a binding letter agreement to sell a 65% working interest in our deep rights in East Texas for approximately $350 million in a transaction that we expect to close on or before July 31, 2008, subject to standard conditions to closing such as completion of customary due diligence, the negotiation of a mutually acceptable participation agreement, and a condition that title and related contracts and agreements are acceptable to Chesapeake. We intend to use the proceeds from this sale for debt reduction and general corporate purposes, including, but not limited to, acquisitions and exploration and development activities.

Operating Activities

For the three months ended March 31, 2008, our cash flow used by our operations was negative $2.0 million compared with $0.7 million provided by our operations for the same period in 2007 as a result of our acquisition of $2.1 million of seismic data and payments of our current liabilities. Our cash flow from operations declined from $29.2 million for the year ended December 31, 2006 to $19.5 million for the year ended December 31, 2007 due to weather-related and pipeline problems in the first quarter of 2007 that kept our production flat but increased our costs, increased interest from borrowings to maintain our drilling program, and increased general and administrative costs.

Net cash provided by operating activities decreased from $30.2 million in 2005 to $29.2 million in 2006. In 2006, the decrease in prices compared to 2005 offset increased production.

Investing Activities

For the three months ended March 31, 2008 and 2007, we used our cash flow for drilling, utilizing $15.5 million and $12.3 million, respectively. During the three months ended March 31, 2007, we also spent $11.7 million for the acquisition of oil and gas properties and $6.5 million for the acquisition of Shelby Pipeline, Ltd.

For the years ended December 31, 2007 and 2006, we used our cash flow for drilling, utilizing $73.9 million and $51.7 million in 2007 and 2006, respectively. During the year ended December 31,

2007, we also spent $6.5 million to acquire the 20-mile Shelby Pipeline that was connected to our current pipeline facilities to enhance our operational capabilities in East Texas. In addition we acquired the underlying mineral rights to our farmout agreement in Southwest Kansas. This $28 million acquisition added acreage, increased our net revenue interest in the properties and included some producing wells and properties with preferential rights associated with this transaction. Approximately 2 MMcfe per day of production was acquired in the Southwest Kansas acquisition.

In 2006 we continued to invest in our drilling program, spending $51.7 million for drilling and completion in East Texas and Kansas. Our drilling and exploration capital expenditures have increased each year from inception and totaled $19 million in 2003, $21 million in 2004, and $33 million in 2005. Additionally, we made acquisitions totaling $71 million in 2005.

We acquired deep mineral rights to approximately 651,000 gross (631,000 net) acres in the Hugoton field in southwest Kansas in April 2005 as a result of our $45 million acquisition of Presco Western, LLC, which is a party to a farmout agreement.

In August 2005, we acquired additional working interests for $26 million in existing properties in East Texas from a stockholder and former member of the board of directors. This acquisition enhanced our position in the area and assured our operational control of the properties. This acquisition was funded by working capital and borrowings under of our line of credit.

We have established a development budget of $104 million in 2008 to be funded from cash flow from operations and borrowings under our credit facility. We establish these budgets based upon expected volumes produced and commodity prices.

Financing Activities

For the three months ended March 31, 2008, we borrowed $24 million to fund our drilling activities and for the acquisition of seismic data.

For the year ended December 31, 2007 we borrowed $94.0 million to fund two acquisitions and our drilling activities.

In 2006, we received net proceeds of $26.5 million from the sale of our common stock in our July private equity offering and borrowed $47.9 million under our line of credit.

During 2005, we sold approximately $64.3 million of common stock. These proceeds were primarily used to fund the Presco Western, LLC acquisition and to assist in the development of our interests in the Hugoton field.

In May 2008, we established a new $400 million credit facility with a syndication of several banks. Borrowings under this facility were used to repay and replace a previous facility and to increase our borrowing capabilities thereby enhancing our financial flexibility. As of May 31, 2008, we had an outstanding balance under this credit facility of approximately $144 million with a borrowing base of $190 million. The borrowing base is subject to adjustment twice each year, based on an assessment by the bank petroleum engineers of our future cash flows from proved oil and gas reserves using the bank's pricing parameters and upon completion of this offering, the conforming borrowing base will be $160 million. We intend to pay off approximately $132 million of the credit facility using the net proceeds from this offering, leaving us with approximately $148 million available for future borrowings.

Our goal is to limit borrowing to no more than 50% of book capital to assure that we have flexibility to expand and invest, and to avoid the problems associated with highly leveraged companies of high interest costs and possible debt reductions restricting ongoing operations.

We believe that cash flow from operations and borrowings under our credit facility will be sufficient to finance our anticipated drilling, exploration and capital needs, temporary working capital needs and any expansion of our drilling program through 2008.

Future Capital Expenditures for 2008

The following table summarizes information regarding historical 2006 and 2007 and estimated 2008 capital expenditures. We will be required to meet our needs from our internally generated cash flow, debt financings, and equity financings. The estimated 2008 capital expenditures shown (excluding acquisitions) are preliminary. The estimated capital expenditures are subject to change depending upon a number of factors, including availability of capital, drilling results, oil and gas prices, costs of drilling and completion and availability of drilling rigs, equipment and labor.

		Historical
		Historical				Estimated
		Year Ended December 31,				Estimated
		Year Ended December 31,				Year Ending December 31, 2008
		2006		2007		Year Ending December 31, 2008
		(In thousands)
Capital expenditures:
	East Texas	$	39,600		$48,000	$	55,000
	Hugoton		17,500		39,000		40,000
	Other		1,400		—		2,000

	Total capital expenditures	$	58,500	$	87,000	$	97,000
Geological and geophysical			2,100		4,000		7,000

Total capital and geological and geophysical expenditures		$	60,600	$	91,000	$	104,000

Credit Facility

On May 1, 2008, we entered into a new $400 million revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and certain other lenders. The availability of funds under the credit facility will be subject to a borrowing base, which is currently $190 million. The borrowing base will be redetermined every six months or, upon our election, one additional time each calendar year and upon completion of this offering the conforming borrowing base will be $160 million.

The credit facility will provide for interest on amounts outstanding under the credit facility to accrue at a rate calculated, at our option, at either: (i) the adjusted base rate (which is the greater of the agent's base rate or the federal funds rate plus one half of one percent) plus a margin which ranges from 0% to 1.5%; or (ii) the London Interbank Offered Rate plus a margin which ranges from 1.5% to 3.0% per annum, as applicable, as amounts outstanding under the credit facility increase as a percentage of the borrowing base. In addition, we will pay an annual commitment fee which ranges from 0.375% to 0.5% of non-utilized borrowings available under the credit facility, as amounts outstanding under the credit facility increase as a percentage of the borrowing base. These margins and fees, as well as certain other provisions of the credit agreement, are subject to adjustment if necessary to allow successful syndication of the credit facility.

We will be subject to financial covenants requiring maintenance of a minimum current ratio and a minimum ratio of indebtedness to EBITDAX (generally, EBITDA plus exploration expenses). In addition, we will be subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on our properties.

Loans under the new credit facility will be secured by first priority liens on substantially all of our assets, including equity interests in our subsidiaries. All outstanding amounts under the new credit

facility will be due and payable five years after closing. Upon the completion of this offering, we expect to have approximately $148 million available for borrowings.

Contractual Commitments

In March 2007, we entered into a contract to use a drilling rig in East Texas for three years at approximately $8 million per year. In the event that gas prices have a six-month average below $4.50 per Mcf or above $10 per Mcf the pricing is modified.

In October 2006 and November 2006, respectively, we executed a five-year lease and an amendment thereto for approximately 43,000 square feet of office space for approximately $73,000 per month. We are also under a lease that expires in 2010 for office space we previously occupied at $220,000 per year.

The following table summarizes these commitments as of March 31, 2008:

Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-Term Debt Obligations—Bank Borrowing Facility	$	134,000,000	$	—	$	134,000,000	$	—	$	—
Operating Lease Obligations—Office Leases		3,847,000		1,082,000		2,036,000		729,000		—
Drill Rig Lease		16,427,000		8,578,000		7,849,000		—		—
Well Compressor Obligations		662,000		659,000		3,000		—		—

Total	$	154,936,000	$	10,319,000	$	143,888,000	$	729,000	$	—

Off Balance-Sheet Arrangements

We do not have any off-balance sheet arrangements.

Quantitative and Qualitative Disclosure about Market Risk

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices, and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.

Commodity Price Risk

We enter into derivative contracts to hedge future gas and crude oil production to mitigate a portion of the risk of market price fluctuations.

As of May 31, 2008, we had the following outstanding financial hedge positions:

Contract Type	Weighted Average Strike Price		Floor/Ceiling		Quantity	Contract Period
Futures Swap, Gas	$	8.01		—	100,000 MMBtu/month	01/01/2008-12/31/2008
Futures Swap, Gas	$	8.275		—	100,000 MMBtu/month	01/01/2008-12/31/2008
Futures Swap, Gas	$	8.24		—	200,000 MMBtu/month	02/01/2008-12/31/2008
Futures Swap, Gas	$	9.04		—	50,000 MMBtu/month	03/01/2008-12/31/2008
Futures Swap, Gas	$	9.025		—	50,000 MMBtu/month	03/01/2008-12/31/2008
Futures Swap, Oil	$	100.00		—	15,000 Bbls/month	03/01/2008-12/31/2008
Futures Swap, Oil	$	102.60		—	5,000 Bbls/month	04/01/2008-12/31/2008
Futures Swap, Gas	$	10.20		—	50,000 MMBtu/month	04/01/2008-12/31/2008
Futures Swap, Oil	$	98.05		—	10,000 Bbls/month	01/01/2009-12/31/2009
Futures Swap, Gas	$	9.50		—	100,000 MMBtu/month	01/01/2009-12/31/2009
Futures Swap, Gas	$	9.725		—	100,000 MMBtu/month	01/01/2009-12/31/2009
Futures Swap, Gas	$	10.99		—	100,000 MMBtu/month	01/01/2009-12/31/2009
Futures Collar, Gas		—	$	10.00/13.75	100,000 MMBtu/month	01/01/2009-12/31/2009
Futures Collar, Oil		—	$	100.00/175.00	3,000 Bbls/month	01/01/2009-12/31/2009

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our credit agreement and the collateral for the outstanding borrowings under our credit agreement is used as collateral for our hedges.

BUSINESS

Overview

We are an independent oil and gas company engaged in the acquisition, exploration, development and production of onshore domestic U.S. oil and gas properties and have been operating since our inception in June 2002. We primarily operate in two areas: east Texas and adjacent lands in western Louisiana, which we collectively refer to as East Texas, and the Hugoton field in southwest Kansas (the "Hugoton field"). We have assembled combined acreage of approximately 921,000 gross (852,000 net) acres providing us with 891 identified drilling locations. At March 31, 2008, we owned working interests in 336 gross (243 net) producing wells, and for the three months ended March 31, 2008, our average net production was approximately 31.1 MMcfe/d. At March 31, 2008, our estimated total proved oil and gas reserves were approximately 229 Bcfe. Our proved reserves are approximately 78% gas and 37% proved developed. Our total proved reserves have a reserve life index of approximately 20 years, and our proved producing reserves have a reserve life index of approximately 8 years. Using prices as of March 31, 2008, the PV-10 value of our proved reserves had an estimated pre-tax net present value, discounted at 10%, or PV-10, of approximately $820 million, of which 40% was proved developed. See "Selected Combined and Consolidated Historical Financial Data—Reconciliation of Non-GAAP Financial Measures" for additional information regarding PV-10. As operator of over 90% of our proved reserves, we have a high degree of control over our capital expenditure budget and other operating matters.

Competitive Strengths

We believe our historical success is, and future performance will be, directly related to the following combination of strengths which enable us to implement our strategy:

•: Experienced Management Team and Directors. The members of our executive management team have an average of 26 years of experience in the oil and gas industry and significant experience in managing public and private oil and gas companies. Several of our directors also have significant experience in managing both public and private oil and gas firms.
•: Large Long-Lived, Operated Asset Base. We own a large long-lived asset base for which we operate over 90% of our estimated proved reserves. Operating such a large percentage of our reserves allows us to better control and execute our drilling program. Approximately 78% of our reserves are gas, and almost all of our assets are located in East Texas and the Hugoton field. We believe this property profile will produce stable cash flows while providing us with a large number of development, exploitation and exploration opportunities.
•: Large Acreage Positions. We are a significant acreage holder in each of our two primary operating areas. In East Texas we control over 75,000 gross (71,000 net) acres and in the Hugoton field our interests in the Hugoton Deep amount to 801,000 gross (747,000 net) acres. We believe we have assembled an asset portfolio in prolific oil and gas fields that would be difficult to replicate.
•: Significant Hugoton Reserve Potential. With production commencing in the late 1920's, a substantial majority of gas sold from the Hugoton field has been sold at prices under $2.00 per Mcfe. As a result of these historically lower prices, we believe the deeper zones of the Hugoton field have not been fully explored or developed. Accordingly, we believe that significant amounts of gas and oil remain to be recovered in the current higher price environment using modern exploration and production technologies.
•: Significant Haynesville Acreage. A substantial portion of our East Texas acreage includes rights to the Haynesville Shale. We have entered into a binding letter agreement to sell Chesapeake a 65% working interest in our deep rights in East Texas to jointly explore and develop the Haynesville Shale formation.

•: Drilling Inventory. We have identified 891 drillable, low to moderate risk locations providing us with multiple years of drilling inventory. Of these locations, 207 are classified as proved undeveloped and none are located in the Haynesville Shale. We have traditionally drilled locations that management deems to have the greatest economic potential as opposed to drilling wells designed to
impact our reported proved reserve value by converting probable or possible reserves to proved reserves. See "Prospectus Summary—Summary of Capital Expenditures" for more information regarding our anticipated drilling in East Texas.
•: Proven Technical Team. Our technical staff includes 21 geologists, geophysicists, reservoir engineers and technicians with an average of over 22 years of relevant technical experience. Our staff has a proven record of analyzing complex structural and stratigraphic plays using 3-D seismic, geological and geophysical expertise, producing and optimizing oil and gas reservoirs, and drilling, completing and fracing tight gas reservoirs. Our professionals have developed new horizontal drilling and completion techniques that enhance initial production rates and ultimate reserve recoveries.
•: Drilling Success. The competencies of our proven technical team focused in our large and productive acreage holdings have helped us to achieve a drilling success rate of approximately 86% since our inception in 2002. Our technical expertise has also allowed us to improve the production rates and ultimate hydrocarbon recoveries on our wells as compared to those wells drilled by others in similar reservoirs in our primary operating areas.
•: Low Finding and Development Costs. Our significant reserve potential in our operating areas, our technical expertise and high drilling success have allowed us to achieve relatively lower finding and development costs. Since our inception, we have invested approximately $238.5 million to drill and complete 178 wells in our East Texas and Hugoton operating areas. Our average acquisition, finding and development cost from inception to March 31, 2008 was $1.98 per Mcfe. We calculate our cost per Mcfe by adding our historical costs to date with our expected costs to develop proved undeveloped reserves and dividing the sum by our total proved reserves. Other companies may calculate finding and development costs differently than us and, therefore, their finding and development costs may not be comparable to ours.
•: Control of Low-Pressure Gas Gathering Infrastructure and Gas Marketing Flexibility. We own and operate approximately 100 miles of gas gathering lines and gas pipelines that collect and transport our production and third-party production in our East Texas operations area. Production from both East Texas and the Hugoton field has access to multiple delivery points to several regional and interstate pipelines that provide more than sufficient take away capacity to sell our production.

Strategy

Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings using a balanced program of (i) developing existing properties, (ii) exploiting and exploring undeveloped properties, (iii) completing strategic acquisitions and joint ventures, and (iv) maintaining financial flexibility. The following are key elements of our strategy:

•: Maintain Technological Expertise. We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 86% since our inception and helped us improve and maximize field recoveries. We will use modern geological and geophysical technologies, detailed petrophysical analyses and sophisticated completion and stimulation techniques, including single-lateral frac stimulation technology, to profitably grow our reserves and production.

•

Accelerate the Development of our Existing Properties. We intend to further develop the significant remaining upside potential of our properties.

•: We have recently employed multilateral drilling to enhance production from the James Lime wells in East Texas, and may fracture stimulate.
•: In the Hugoton field we have completed studies of two secondary recovery projects using traditional waterflood techniques. The Southwest Lemon Victory waterflood project has shown increased production in response to waterflood projects operated by others on contiguous properties. Water injection in our Southwest Lemon Victory waterflood project commenced during the fourth quarter of 2007. We have now completed a majority of the wells planned for the project. Oil production has increased by 100 Bbls/d since we began injection, as we have drilled additional producing wells in the waterflood area.
•: In the Hugoton field, we have acquired 457 square miles of proprietary 3-D seismic and accelerated drilling activity by adding a second drilling rig.
•: We intend to acquire an additional 500 square miles of proprietary 3-D seismic data with respect to our Hugoton properties over the next five years. This data will add to our current inventory of 457 square miles of proprietary 3-D seismic. Therefore, our seismic acquisition plan for the next five years would ultimately cover approximately 72% of our net acreage.
•: We signed a binding letter agreement with Chesapeake to explore our deep acreage in East Texas.

•

Acquisition Growth. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects, particularly on opportunities where we believe our reservoir management and operational expertise will enhance the value and performance of acquired properties. We may enter into hedging agreements in connection with future acquisitions to protect our return on investment. Our management team members have gained significant acquisition experience during their careers with Ellora and previous employers.

•

Endeavor to be a Low Cost Producer. We will strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and capture operating efficiencies.

•

Maintain Financial Flexibility. On May 1, 2008, we entered into a credit facility with an initial borrowing base of $190 million. Upon the completion of this offering, the conforming borrowing base will be $160 million, and we expect that we will have at least $148 million available for borrowings under our revolving line of credit, providing us with significant financial flexibility to pursue our business strategy. Our goal is to limit borrowing to no more than 50% of book capital to assure that we have flexibility to expand and invest, and to avoid the problems associated with highly leveraged companies, including large interest costs and possible debt reductions that can restrict ongoing operations. We have historically used puts (or floors) to protect a portion of our exposure to commodity price fluctuations while capturing all of the upside potential of prices. We may enter into additional commodity hedge agreements, including fixed price, forward price, physical purchase and sales contracts, futures, financial swaps, option contracts and put options. In addition to this offering, we have also entered into a binding letter agreement to sell a 65% working interest in our East Texas deep acreage to Chesapeake for approximately $350 million. The proceeds from this offering and the sale to Chesapeake will provide us with significant financial flexibility to pursue our business strategy.

Areas of Operations

We own oil and gas properties, producing and non-producing, principally in East Texas and in the Hugoton field in southwestern Kansas. The following is a brief summary of our major producing and exploration activity areas.

East Texas

We acquired our initial position in East Texas in June 2002. Our acreage includes the Huxley and East Bridges fields, which we believe are among the most productive areas of the James Lime. We drill our horizontal wells using fresh water and without drilling mud, which is known as underbalanced drilling. The James Lime has a vertical depth of approximately 6,100 feet and horizontal lengths of up to 8,000 feet. Our acreage across the James Lime is a porous packstone with up to 125 feet of net pay with net porosity greater than 8% in nine different intervals in the limestone. Historically, James Lime wells have been drilled by various operators in Shelby County, Texas with both single and multi-lateral horizontal wellbores, completed naturally with no fracture stimulation. Our development of James Lime acreage has evolved from drilling single laterals that were unstimulated to fractured single laterals to multi-lateral wellbores. Based on our results and those of other operators in the area, we believe that a second lateral can add 30% to the initial rates and ultimate recoveries of our James Lime wells. A typical single-lateral well costs $2.1 million to drill and complete, and each additional lateral can add approximately $300,000 to the costs. As of March 31, 2008, our producing wells in the James Lime had produced a cumulative total of 0.8 gross Bcfe per well and had estimated proved reserves remaining of 1.2 gross Bcfe, for a total of 2.0 gross Bcfe per well. According to our March 31, 2008 reserve report, our proved undeveloped locations in the James Lime average 2.2 gross Bcfe per well. Our production in East Texas averaged approximately 4.5, 7.9, 12.8, 13.8 and 15.8 MMcfe/d for the years ended December 31, 2003, 2004, 2005, 2006 and 2007, respectively. Production for the three months ended March 31, 2008 averaged approximately 20.1 MMcfe/d. Our average working interest and net revenue interest in our producing wells in East Texas are 81% and 64%, respectively. The average working and net revenue interest for proved undeveloped locations is 91% and 72%, respectively. The average initial rate (30-day average) for the successful wells we drilled in 2007 was 1.6 MMcfe/d gross and
1.8 MMcfe/d gross for the three months ended March 31, 2008. We expect to achieve similar initial production rates for successful wells that we drill in proved undeveloped locations in the future.

In addition to the James Lime play we have begun developing the lower Cretaceous Fredericksburg (or Edwards) formation using horizontal drilling. Fredericksburg wells are also drilled underbalanced with water and completed with no stimulation. We have identified 111 future locations in the Fredericksburg formation, of which 11 are proved. We drilled and completed four wells in the Fredericksburg formation in 2007, three of which are producing and one of which is being evaluated. We plan to drill two wells in the Fredericksburg formation in 2008.

Additional deep potential on our acreage includes the Pettet limestone and Travis Peak sands, which have produced from vertical wells adjacent to our acreage at depths ranging from 6,500 to 8,000 feet, and the Haynesville Shale formation, which is located at a depth of approximately 12,000 feet. In the last several months, leasing and drilling activity in the Haynesville Shale formation has increased significantly. The Haynesville Shale (Lower Bossier) is an organic rich, thermally mature, limey siliceous shale with 20% to 30% clay content. Well data is sparse in and around our acreage, with only one well (drilled in 1946) that penetrated the Haynesville section within the boundary of our acreage block in East Texas. The nearest Haynesville Shale production to our acreage position is from vertical wells approximately 11 to 15 miles to the east, north, and west. On June 4, 2008, we entered into a binding letter agreement with Chesapeake pursuant to which Chesapeake agreed to acquire a 65% working interest in our deep rights in East Texas and adjacent areas of Louisiana located below our James Lime play to target the Haynesville Shale formation. Chesapeake will pay us approximately $350 million in cash in the transaction, subject to standard conditions to closing such as completion of customary due diligence, the negotiation of a mutually acceptable participation agreement, and a

condition that title and related contracts and agreements are acceptable to Chesapeake. We expect this transaction to close on or before July 31, 2008. We will retain all of our interest and our operating rights in the James Lime and Fredericksburg formations, as well as a 35% working interest in the deep acreage that is subject to the Chesapeake agreement. Chesapeake will become the operator of the deep rights and is obligated to drill, at its sole expense, the first five wells in the acquired interests in the initial two years, with the drilling of the first well required to be commenced within 120 days following closing. We will hold a 35% carried interest in each of the first five wells and will be responsible for 35% of the costs of subsequent wells. At present, we have no activities in and have no proved reserves or production attributable to the Haynesville Shale formation and have not drilled any wells to test the Haynesville Shale located beneath our James Lime acreage. Our James Lime wells have largely been developmental wells; however, the initial wells drilled in the Haynesville Shale will be exploratory in nature.

The majority of our drilling in East Texas will be developmental drilling. See "Prospectus Summary—Summary of Capital Expenditures" for our estimated capital expenditures in East Texas.

Hugoton Field

The Hugoton field located in southwestern Kansas was discovered in 1927 and is the largest gas field in North America with cumulative production over 31 Tcf. We believe that substantial recoverable reserves remain in the Hugoton field. Companies active in the Hugoton field include EOG Resources, Inc., Occidental Petroleum Corporation, Cimarex Energy Co., XTO Energy Inc. and BP p.l.c. The majority of gas produced to date has been from the shallower Permian formations, which produce primarily gas from 2,400 to 3,200 feet.

We believe the deeper, yet still comparatively shallow, potential of the Hugoton field has been historically underexploited due to the prolific shallow production and historically low gas prices received from 1927 to the 1980s. A majority of the 31 Tcf of gas produced from the field was sold at prices under $2.00 per Mcfe, which we believe led to the early abandonment of wells and the bypassing of deeper gas reserves that were not economic to recover in a lower price environment and without the benefit of modern drilling and completion technologies. The deeper Hugoton has produced 3.3 Tcf of gas and 323 MMBbls of oil and condensate in the nine-county area where our acreage is located.

We initially acquired our rights to develop the Hugoton's deeper potential through our acquisition of Presco Western, LLC in April 2005. We estimate that 8,000 wells have been drilled above the Heebner Shale in the nine counties where our acreage position is located. There are 13 productive horizons below the Heebner Shale (generally 4,000 feet), which we refer to as the Hugoton Deep, and we typically drill all of our Hugoton wells to the base of the deepest known producing formation in the area.

During the period we have held our Hugoton acreage, we have identified three waterfloods and we currently have 613 potential drilling locations. We have increased our Hugoton production from 2 MMcfe/d at the time of acquisition in 2005 to 10 MMcfe/d for the three months ended March 31, 2008 as a result of drilling 117 wells and participating in three farmouts. The primary targets are Morrow and Chester Valley sands which can be detected seismically. Our average well in the Hugoton costs approximately $614,000 to drill and complete, and we drilled 57 wells in the Hugoton field during 2007 and 18 wells during the three months ended March 31, 2008. Included in the wells drilled in the first quarter of 2008 are 7 injection and production wells for our Southwest Lemon Victory waterflood project, where water injection commenced during the fourth quarter of 2007. Our production in Kansas averaged approximately 2, 6 and 9 MMcfe for the years ended December 31, 2005, 2006 and 2007, respectively. Our production for the three months ended March 31, 2008 averaged approximately 10.1 MMcfe/d. Our average working interest and net revenue interest for our producing wells in the Hugoton field are 70% and 61%, respectively. The average working and net revenue interest for our proved undeveloped locations is 88% and 76%, respectively. As of March 31, 2008, the producing wells

we operate in the Hugoton Deep had produced an average of 0.8 gross Bcfe per well and had estimated proved reserves of 0.2 gross Bcfe, for a total of 1.0 gross Bcfe per well. According to our March 31, 2008 reserve report, our proved undeveloped locations in the Hugoton Deep average 0.49 Bcfe of gross reserves per well, of which 45% is oil and 55% is natural gas. The average initial rate (30-day average) for successful wells drilled in 2007 was 400 Mcfe/d gross, and we expect to achieve similar initial production rates for successful wells that we drill in proved undeveloped locations in the future. The average initial rate (30-day average) for successful wells drilled and producing during the first quarter of 2008 was 522 Mcfe/d gross.

Other

We hold interests in approximately 45,000 gross (36,000 net) acres and 45 wells in southeastern Colorado and an approximate 40-mile pipeline that transports the gas produced from such wells to an interstate pipeline. We operate the pipeline and each of the wells in which we own an interest. We transport gas on behalf of our company as well as for others. We also own small interests in approximately 300 wells in Kansas, Oklahoma and Texas.

On an aggregate basis, these interests produce 1 MMcf of gas per day. We do not expect significant development or exploration in these areas in the foreseeable future.

Estimated Proved Reserves

		Estimated Proved Reserves at March 31, 2008								Production for the Three Months Ended March 31, 2008
		Developed (Bcfe)	Undeveloped (Bcfe)	Total (Bcfe)	Percent of Total Reserves		PV-10(1) ($ Millions)		Identified Drilling Locations(2)	Net Average MMcfe/d	Percent of Total
East Texas		54	83	137	60	%	$	388	263	20.1	65	%
Hugoton (Kansas)		28	59	87	38			414	613	10.1	33
Other (primarily Colorado)		3	2	5	2			18	15	0.9	2

	Total	85	144	229	100	%	$	820	891	31.1	100	%

(1): Based on March 31, 2008 average wellhead prices of $9.28 per MMBtu of gas and $97.41 per Bbl of oil held flat for the life of the reserves.
(2): Represents total gross drilling locations identified by management as of March 31, 2008, of which 207 locations are classified as proved. Based on fluctuations in commodity prices, the number of drilling locations will change.

Operating Data

The following table presents certain information with respect to our historical operating data for the years ended December 31, 2005, 2006 and 2007 and for the three months ended March 31, 2007 and 2008.

			Year Ended December 31,						Three Months Ended March 31,
			2005		2006		2007		2007		2008
Gross wells
	Drilled			29		40		74				21
	Completed			25		34		64				19
Net wells
	Drilled			24.4		38.6		72.8				20.7
	Completed			21.1		32.6		62.9				18.8
Operating Data
	Net production:
		Natural gas (MMcf)		5,348		6,348		7,459		1,514		2,308
		Oil (MBbl)		125		218		354		51		87
		Total (MMcfe)		6,096		7,656		9,584		1,820		2,830
	Average sales price:
		Natural gas (per Mcf)(1)	$	7.58	$	6.21	$	6.29	$	6.49	$	7.74
		Oil (per Bbl)(1)		56.50		58.36		68.44		52.06		91.75
		Total (per Mcfe)(1)		7.81		6.80		7.42		6.86		9.14
Expenses (per Mcfe)
	Lease operating		$	1.01	$	1.31	$	1.48		1.35		1.65
	Production taxes			0.30		0.26		0.26		0.10		0.41
	General and administrative			1.93		1.54		1.93		1.62		2.15
	Depreciation, depletion and amortization			1.34		1.53		2.18		2.16		2.58

(1): Before consideration of hedging transactions.

Estimated Proved Reserves

The estimates in the table below of net proved reserves as of March 31, 2008 are based on a reserve report prepared by Ryder Scott. Please read "Risk Factors—Risks Related to Our Business—We face uncertainties in estimating proved oil and gas reserves and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of proved reserves" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in evaluating the material presented below.

			As of March 31, 2008
Estimated Proved Reserves
	Gas (Bcf)			179.4
	Oil (MMBbls)			8.3

		Total proved reserves (Bcfe)(1)		229.2

	Total proved developed reserves (Bcfe)			84.9

PV-10 value (millions)(2)
	Proved developed reserves		$	329
	Proved undeveloped reserves			491

		Total PV-10 value	$	820

(1): Based on a conversion of 6 Mcfe of gas per Bbl of oil/condensate.

(2): Based on March 31, 2008 average wellhead prices of $9.28 per MMBtu of gas and $97.41 per Bbl of oil held flat for the life of the reserves. See "Selected Combined and Consolidated Historical Financial Data—Reconciliation of Non-GAAP Financial Measures" for a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

Oil and Gas Estimated Reserves

As stated in the notes to financial statements, we had significant revisions to previous estimates of reserves in each of the years ended December 31, 2005, 2006 and 2007. The large majority of these adjustments were a result of us adjusting original estimates of reserves that we obtained through acquisitions made in 2002 through 2005 in Shelby County James Lime wells for a variety of reasons, including, but not limited to, results condemning certain offset locations and performance of producing wells not meeting the estimations we made at the time we acquired the properties. These adjustments resulted in a reduction of the proved reserves of the wells acquired and their proved undeveloped offset wells.

From December 31, 2006 to March 31, 2008, our reserves increased as a result of our increased drilling activity and the positive results therefrom.

Development and Exploration Projects

The following table summarizes information regarding our historical 2006 and 2007 and our estimated 2008 capital expenditures. The estimated 2008 capital expenditures shown are preliminary full year estimates (excluding acquisitions and pipeline construction or additions). The estimated capital expenditures are subject to change depending upon a number of factors, including availability of capital, drilling results, oil and gas prices, costs of drilling and completion and availability of drilling rigs, equipment and labor.

		Historical				Estimated
		Year Ended December 31,
		Year Ended December 31,				Year Ending December 31, 2008
		2006		2007		Year Ending December 31, 2008
		(In thousands)
Capital expenditures:
	East Texas	$	39,600	$	48,000	$	55,000
	Hugoton		17,500		39,000		40,000
	Other		1,400		—		2,000

	Total capital expenditures	$	58,500	$	87,000	$	97,000
Geological and geophysical			2,100		4,000		7,000
Total capital and geological and geophysical expenditures		$	60,600	$	91,000	$	104,000

Historical Finding and Development Costs

From our inception in April 2002 to March 31, 2008, our acquisition, finding and development costs have averaged $1.98 per Mcfe. The cost of finding and developing reserves is expressed in dollars per Mcfe and is calculated for this time period by taking the sum of the cost incurred for exploration, development and acquisition of approximately $330 million, plus future development costs attributable to proved undeveloped reserves, adjusted for the balance of unproved oil and gas properties not subject to amortization, and dividing such amount by our total proved reserves of 229 Bcfe as of March 31, 2008, plus our cumulative production of 34.4 Bcfe. Estimated future development costs at March 31, 2008 totaled $190 million. Management believes that this information is useful to an investor in evaluating us because it measures the efficiency of a company in adding proved reserves as compared to others in the industry; however, other companies may calculate finding and development costs differently than us and, therefore, their finding and development costs may not be comparable to ours.

Acquisitions

We have invested $123 million for acquisitions of proved oil and gas properties from our inception in 2002 to March 31, 2008. The following is a summary of the significant acquisitions during that period:

	Year	Acquisition Price	Acquired Proved Reserves*	Daily Production at Acquisition
		(Millions)	(Bcfe)	(MMcfe/day)
East Texas producing properties and leases from an independent producer	2002	15	10	5
East Texas producing properties and leases from a major oil company	2003	9	22	2
Hugoton Deep producing properties and leases from Presco Western, LLC	2005	45	60	2
East Texas producing properties and leases from a stockholder	2005	26	11	2
Hugoton Deep producing properties and leases from a major oil company	2007	28	12	2

*: Acquired reserve quantities shown are as estimated at the date of acquisition and do not reflect aggregate negative revisions of all acquired reserves since inception of approximately 37 Bcfe.

Principal Customers and Marketing Agreements

We generally sell our production on a month-to-month basis based on current market prices. For the year ended December 31, 2007, Louis Dreyfus Energy Services, Plains Marketing, L.P., Trans Louisiana Gas Pipeline, and Texon L.P. accounted for 36%, 19%, 15%, and 10%, respectively, of our oil and gas sales. For the three months ended March 31, 2008, Louis Dreyfus Energy Services and Texon L.P. accounted for 41% and 34%, respectively, of our oil and gas sales. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations.

Productive Wells

The following table sets forth the number of oil and gas wells in which we owned a working interest at March 31, 2008.

		Total Wells at March 31, 2008
		Gross	Net
Oil		110	92.2
Gas		226	150.7

	Total	336	242.9

Acreage

The following table sets forth certain information with respect to the developed and undeveloped acreage as of March 31, 2008.

		Developed		Undeveloped		Total
		Gross	Net	Gross	Net	Gross	Net
Hugoton Field		65,434	39,494	735,684	707,015	801,118	746,509
East Texas		32,099	30,792	43,022	39,810	75,121	70,602
Other		16,935	12,968	27,469	21,618	44,404	34,586

	Total	114,468	83,254	806,175	768,443	920,643	851,697

Drilling Activity

Development wells

The following table describes the development wells we drilled during the years ended December 31, 2005, 2006 and 2007 and the three months ended March 31, 2008.

		Year Ended December 31,
		Year Ended December 31,						Three Months Ended March 31, 2008
		2005		2006		2007		Three Months Ended March 31, 2008
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Producing		13	12.3	27	25.6	56	55.2	18	17.8
Dry		1	1.0	3	3.0	10	9.9	1	0.9

	Total	14	13.3	30	28.6	66	65.1	19	18.7

We were in the process of drilling four gross (3.9 net) development wells as of March 31, 2008.

Exploratory wells

The following table describes the exploratory wells we drilled during the years ended December 31, 2005, 2006 and 2007 and the three months ended March 31, 2008.

		Year Ended December 31,
		Year Ended December 31,						Three Months Ended March 31, 2008
		2005		2006		2007		Three Months Ended March 31, 2008
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Producing		12	8.8	7	7.0	8	7.7	1	1
Dry		3	2.3	3	3.0	0	0.0	1	1

	Total	15	11.1	10	10.0	8	7.7	2	2

At March 31, 2008, we were not in the process of drilling any exploratory wells.

Hedging Activity

Derivative Instruments and Hedging Activities

We enter into derivative contracts to hedge future gas and crude oil production to mitigate a portion of the risk of market price fluctuations.

ineffective portion of the hedge, if any, is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged.

It is our intent to use counterparties that participate in our credit facility to allow us maximum flexibility in contract selection and size.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.

Competition

The oil and gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining purchasers and transporters of the oil and gas we produce. There is also competition between producers of oil and gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Regulation

The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. We hold onshore federal leases involving the United States Department of Interior (the Bureau of Land Management and the Bureau of Indian Affairs). At the federal level, various federal rules, regulations and procedures apply, including those issued by the United States Department of Interior as noted above, and the United States Department of Transportation (Office of Pipeline Safety). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Varied remedies are available for enforcement of these federal,

state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines and penalties or otherwise subject us to the various remedies as are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with these federal, state and local rules, regulations and procedures.

Transportation and Sale of Gas

The Federal Energy Regulation Commission ("FERC") regulates interstate gas pipeline transportation rates and service conditions. Although the FERC does not regulate gas producers such as us, the agency's actions are intended to foster increased competition within all phases of the gas industry. To date, the FERC's pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC, the United States Congress or state regulatory agencies may consider additional proposals or proceedings that might affect the gas industry. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

Regulation of Production

Oil and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of the spacing, and plugging and abandonment of wells. Also, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, gas and gas liquids within its jurisdiction.

Environmental Regulations

The exploration for and development of oil and natural gas and the drilling and operation of wells, fields and gathering systems are subject to extensive federal, state and local laws and regulations governing environmental protection as well as discharge of materials into the environment. These laws and regulations may, among other things:

•: require the acquisition of various permits before drilling commences;
•: require the installation of expensive pollution control equipment;
•: restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling production, transportation and processing activities;
•: suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; and
•: require remedial measures to mitigate pollution from historical and ongoing operations, such as the closure of pits and plugging of abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted or re-interpreted in the future, could have a material adverse impact on our business, financial condition and results of operations. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend of compliance will continue in the future.

The following is a summary of some of the existing laws, rules, and regulations to which our business operations are subject. To date we have not incurred any material costs or penalties as a result of violating any environmental laws or regulations.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With the approval of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA's non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our operating expenses, which could have a material adverse effect on our results of operations and financial position.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for oil and natural gas exploration, production and development activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In

addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulatory programs may require us to obtain permits before commencing construction on a new source of air emissions, and may require us to reduce emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs. Additionally, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into state waters or waters of the United States, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Global Warming and Climate Control

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 14 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 inMassachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding inMassachusettsthat greenhouse gases fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our products.

Employees

At March 31, 2008, we had 76 full-time employees. None of our employees is represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Legal Proceedings

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

As of the date of this prospectus, we are not aware of any pending or overtly threatened legal actions that we believe, based on our experience to date, would have a material adverse impact on our business, financial position or results of operations.

Insurance Matters

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

MANAGEMENT

Executive Officers and Directors

The following discussion sets forth, as of the date of this prospectus, the names and ages of our executive officers and directors and the principal offices and positions they hold as of March 31, 2008. Our executive officers are appointed by our board of directors and shall serve until the expiration of their contracts, their death, resignation, or removal by our board of directors. Our directors serve one year terms or until their successors are elected and qualified or until their death, resignation or removal in the manner provided in our bylaws. The present term of each director will expire at the next annual meeting of our stockholders.

Name	Age	Position(s) Held	Since
T. Scott Martin	58	Chairman of the Board, President and Chief Executive Officer	2002
Steven R. Enger	49	Executive Vice President and Chief Financial Officer	2008
Richard F. McClure Jr.	48	Vice President of Operations and Chief Operating Officer	2002
Valerie K. Walker	48	Vice President of Exploration	2002
Jeffery S. Williams	48	Vice President of Land and Acquisition	2005
Cortlandt S. Dietler(a)	86	Director	2006
Bryan H. Lawrence	65	Director	2002
Peter A. Leidel	51	Director	2002
Sheldon B. Lubar(b)(c)	78	Director	2003
Neil L. Stenbuck(a)(c)	54	Director	2006
James B. Wallace(b)	78	Director	2006
George A. Wiegers(a)	70	Director	2006

(a): Member of Audit Committee
(b): Member of Compensation and Governance Committee
(c): Committee Chairman

T. Scott Martin has been our chief executive officer since our inception in 2002. Mr. Martin was previously the President of TPEX Exploration in 1991 and 1992 and Chief Operating Officer of Alta Energy from 1992 to 1994. Mr. Martin founded Ellora Energy LLC in 1995 and served as its president until the company ceased operations in 2002. Ellora Energy LLC had non-operated oil and gas interests in Kansas and southeastern Colorado and royalty interests primarily in west Texas. Before operating those companies, Mr. Martin was an engineer with BWAB Inc. and Amoco Production Company. Mr. Martin holds a BA from the Colorado College and a degree in Chemical Engineering from the University of Colorado. In addition to membership in the Society of Petroleum Engineers and the Independent Petroleum Association of America, Mr. Martin was a founding trustee of the Boulder Country Day School and the Martin Seamster Endowment Fund of the Sioux City Art Museum. Mr. Martin was awarded the Boulder Chamber of Commerce Entrepreneur of Distinction Award in 2005.

Steven R. Enger joined us in August 2007 as Vice President of Investor Relations and Corporate Development and was named Executive Vice President and Chief Financial Officer on March 7, 2008. Mr. Enger was most recently an analyst and Research Director with Petrie Parkman & Co. in Denver, where for nine years he covered integrated oil and exploration and production

companies and performed oil markets analysis. Prior to Mr. Enger's tenure at Petrie Parkman, he worked for 16 years at ARCO in engineering, strategic planning, and investor relations. Mr. Enger holds a B.S. in Petroleum Engineering from Colorado School of Mines and an MBA from UCLA. He is an active member of the Society of Petroleum Engineers and the National Association of Petroleum Investment Analysts, where he served on the Board of Directors and as President.

Richard F. McClure Jr. joined us in 2002 as Chief Operating Officer after 15 years with Questa Engineering in Golden, Colorado. As Vice President of Questa, Mr. McClure spent significant time as a consultant to the oil and gas industry in Southeast Asia, Russia and North America. Previous to his relationship with Questa, Mr. McClure was a drilling and reservoir engineer with ARCO. Mr. McClure earned a BS and ME degree from the Colorado School of Mines in Petroleum Engineering. In addition to being a registered professional engineer in Colorado and New Mexico, Mr. McClure is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

Valerie K. Walker has been our Vice President of Exploration since our inception in June 2002. Before her employment with us, Mrs. Walker was a senior geologist with Questar Exploration and Production in Denver, Colorado from 1991 to 1999. From 1999 to 2002, Mrs. Walker was a self-employed independent geology consultant. Mrs. Walker also served as a geologist for Amoco Production Company and Shell Exploration and Production. Mrs. Walker graduated Phi Beta Kappa from Middlebury College with a degree in Geology and earned a Masters Degree in Geology from the University of Colorado. An active member of the American Association of Petroleum Geologists, Mrs. Walker belongs also to the Rocky Mountain Association of Geologists, and Society of Economic Paleontologists and Mineralogists. Mrs. Walker is a certified geologist in the state of Wyoming.

Jeffery S. Williams joined us as Vice President of Land and Acquisitions in October of 2005. Before joining Ellora, Mr. Williams spent 25 years with Pogo Producing Company in Houston, Texas and Oklahoma City, Oklahoma in Pogo's land department ultimately serving as a Regional Land Manager. Mr. Williams has a Bachelor's Degree in Business Administration with an emphasis in Petroleum Land Management from the University of Oklahoma.

Cortlandt S. Dietler joined our board of directors in September 2006. Mr. Dietler was Chairman of TransMontaigne Inc., a refined petroleum products marketing, distribution and supply chain management company, from April 1995 until September 2006, and served as Chief Executive Officer from April 1995 to September 1999. He was the founder, Chairman and Chief Executive Officer of Associated Natural Gas Corporation, a natural gas gathering, processing and marketing company, prior to its 1994 merger with PanEnergy Corporation. From 1994 to 1997, Mr. Dietler served as an Advisory Director to PanEnergy Corporation prior to its merger with Duke Energy Corporation in March 1997. Mr. Dietler currently serves as Chairman of the Board of National Energy Resources Acquisition Co., as a Director of Hallador Petroleum Company, Cimarex Energy Co., Nytis Exploration Company, and recently founded Poison Spider Oil Company LLC. Industry affiliations include: Member, National Petroleum Council; Director, American Petroleum Institute; and past Director, Independent Petroleum Association of America.

Bryan H. Lawrence joined us as a director in June 2002. Since 1994, Mr. Lawrence has been a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as chairman and a director of Approach Resources, Inc., and as a director of Crosstex Energy, Inc. and Crosstex Energy GP, LLC; Hallador Petroleum Company; Star Gas Partners, L.P.; and Winstar Resources (a Canadian publicly traded company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University.

Peter A. Leidel joined us as a director in June 2002. Since September 1997, Mr. Leidel has been a founder and partner in Yorktown Partners LLC, and the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. From 1983 to September 1997, he was employed by Dillon, Read & Co., Inc., an investment banking firm, serving most recently as a Senior Vice President. Mr. Leidel is also a director of certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests and is a past director of the Willbros Group. Mr. Leidel holds a BBA from the University of Wisconsin and an MBA from the University of Pennsylvania.

Sheldon B. Lubar joined us as a director in September 2003. Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the Board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar has also been a director of Crosstex Energy Inc. since May 2001, Crosstex Energy GP, LLC since December 2003, Star Gas Partners, L.P., since 2006, Weatherford International, Inc. since 1995, and Approach Resources, Inc. since 2007. Mr. Lubar holds a bachelor's degree in Business Administration and a Law degree from the University of Wisconsin—Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin—Milwaukee.

Neil L. Stenbuck joined our board of directors in September 2006. Mr. Stenbuck is the Executive Vice President and Chief Financial Officer of Cirque Resources, LP, a private oil and gas firm in Denver, Colorado. Mr. Stenbuck was a Director and Executive Vice President and Chief Financial Officer of Prima Energy Corporation from May 2001 until October of 2004. He was previously with Basin Exploration, Inc., where he served as Vice President—Finance, Chief Financial Officer, Treasurer and a director from 1995 to 2001. Prior to joining Basin, Mr. Stenbuck was with United Meridian Corporation where he served as Vice President—Capital via the 1994 merger between UMC and General Atlantic Resources, Inc., where he held the same position beginning in 1989. He joined General Atlantic in 1987 as Vice President—Finance and Accounting. Mr. Stenbuck is a Certified Public Accountant not currently licensed. He received a B.S.B.A. degree in Accounting and Finance from the University of Arizona.

James B. Wallace joined us as a director in September 2006. Mr. Wallace is the past Chairman of the Board of Tom Brown Inc., a public oil and gas company until its merger with Encana in May of 2005, and currently serves on the board of directors of Delta Petroleum Corporation. Mr. Wallace held various positions, including President, CEO and Chairman of the Board of BWAB Inc., a private oil and gas company located in Denver, Colorado from 1980 to 1996. Mr. Wallace has been involved in the oil and gas business for over 40 years and has been a partner of Brownlie, Wallace, Armstrong and Bander Exploration in Denver, Colorado since 1992. Mr. Wallace joined our board of directors in September 2006. From 1980 to 1992 he was Chairman of the Board and Chief Executive Officer of BWAB Incorporated. He received a B.S. Degree in Business Administration from the University of Southern California in 1951.

George A. Wiegers joined our board of directors in September 2006. Mr. Wiegers worked at senior levels in the investment banking business for over 30 years. Mr. Wiegers joined Dillon, Read & Co. Inc. as a Managing Director in October 1983. Prior to that, he was a General Partner of Lehman Brothers. Mr. Wiegers has been active in the development and financing of industrial, natural resource and media/communications companies. Mr. Wiegers is a retired trustee of the University of Colorado Foundation, Inc., retired chairman of Trout Unlimited, and a director of several public and private industrial and media companies. Mr. Wiegers holds a B.A. from Niagara University and an M.B.A. from the Columbia University Graduate School of Business.

Board of Directors; Committees of the Board

Our board of directors is comprised of eight members, consisting of T. Scott Martin, Cortlandt S. Dietler, Brian H. Lawrence, Peter A. Leidel, Sheldon B. Lubar, Neil Stenbuck, James Wallace and George Wiegers. We expect that Messrs. Dietler, Lubar, Stenbuck, Wallace and Wiegers, being a majority of our board, will qualify as independent directors as such term is defined by the SEC and the Nasdaq Global Market. We have an audit committee and a compensation and corporate governance committee, which are each composed of independent directors. The board of directors has determined that Neil L. Stenbuck is the "audit committee financial expert" of our board of directors, as defined in the rules established by Nasdaq and the SEC.

Indemnification

Our certificate of incorporation and bylaws provide indemnification rights to the members of our board of directors. Additionally, we will enter into separate indemnification agreements with the members of our board of directors to provide additional indemnification benefits, including the right to receive in advance reimbursements for expenses incurred in connection with a defense for which the director is entitled to indemnification.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This compensation discussion describes the material elements of compensation awarded to, earned by or paid to our Chief Executive Officer, Chief Financial Officer and our three other most highly compensated executive officers, each as named in the tables below. We refer to all of these officers as "named executive officers." While this compensation discussion focuses primarily on the information contained in the following tables and related footnotes, as well as the narrative relating to the December 31, 2007 fiscal year, we also describe compensation actions taken before or after the last completed fiscal year to the extent that such discussion enhances the understanding of our executive compensation disclosure.

We believe our success depends on the continued contributions of our named executive officers. Our executive compensation programs are designed with the philosophy of attracting, motivating and retaining experienced and qualified executive officers and directors with compensation that is consistent with comparable public companies and that recognizes individual merit and overall business results. Our policies are also intended to support the attainment of our strategic objectives by tying the interests of our executive officers with those of our stockholders through operational and financial performance goals and equity-based compensation.

The principal elements of our executive compensation programs are base salary, annual cash incentives, long-term equity incentives in the form of stock options, stock awards, as well as other benefits and perquisites. The other benefits and perquisites provided to our executive officers consist of life, disability and health insurance benefits, a qualified 401(k) savings plan and paid vacation and holidays. Our salary and benefits are intended to be competitive with similarly situated companies and our objective is to position the aggregate of these elements at a level that is commensurate with our size and sustained performance.

During 2006 and 2007, the base salaries of our named executive officers were based upon their overall responsibility for our operation and growth. Mr. Martin, our President and Chief Executive Officer, earned the largest salary and bonus because of his significantly larger responsibility for our overall operation and performance. During 2007, our other named executive officers earned equal salaries, and their bonuses were determined based upon our overall performance, growth and implied value. During 2006, James R. Casperson, our former Vice President of Finance and Chief Financial Officer who retired in March 2008, earned a higher salary than Mr. McClure, Mrs. Walker, and Mr. Williams, as we tied his base earnings to his comparable responsibility in our company. Mr. Williams received an additional $100,000 bonus in 2006 for his significant efforts in negotiating the acquisition of significant properties located in Kansas that we closed in 2007. In 2007, Mr. Casperson received a larger bonus than Mr. McClure, Mrs. Walker, and Mr. Williams for his contributions related to our initial public offering. Although we did not grant any option awards to our named executive officers during 2006 and 2007 because we were in the process of conducting our initial public offering, we expect to grant stock option awards in the future based upon the overall contribution by the named executive officer towards our growth and profitability, as well as their tenure with us.

Our Compensation and Governance Committee

The Compensation and Governance Committee of our board of directors is responsible for the approval, evaluation and oversight of all of our compensation plans, policies and programs. The primary purpose of the Compensation and Governance Committee is to assist our board of directors in establishing and implementing our compensation policies and monitoring our compliance with such policies. The members of our Compensation and Governance Committee are Sheldon B. Lubar (chairman) and James B. Wallace, each of whom is an independent director in accordance with the

Nasdaq Global Market rules. From time to time, the Compensation and Governance Committee may, whenever it deems appropriate, form and delegate authority to various subcommittees.

Each of Messrs. Lubar and Wallace has served as the president of a corporation, each of them serves on the board of directors of at least one other publicly traded oil and gas company and each of them is currently serving or has served on compensation and governance committees of those firms. Both board members are experienced managers and board members.

Mr. Lubar, as chairman of the committee, is responsible for selecting the time and place of meetings and the agendas therefor.

The function of the Compensation and Governance Committee is more fully described in its charter, which our board of directors adopted effective as of September 11, 2006. The Compensation and Governance Committee reviews and assesses, on an annual basis, the adequacy of the charter and recommends any proposed changes to our board of directors for approval.

The Compensation and Governance Committee held two meetings during 2007.

Responsibilities of the Compensation and Governance Committee

Acting on behalf of the board of directors, the responsibilities of the Compensation and Governance Committee include the following:

•: reviewing and making recommendations to our board of directors with respect to our general compensation policies;
•: reviewing and approving our goals and objectives relating to the compensation of our executive officers, evaluating such officers' performance in light of these goals and recommending compensation levels to our board of directors based on these evaluations;
•: reviewing market data to assess our position with respect to the compensation of our executive officers in order to ensure we are competitive with comparable public companies;
•: administering our stock option and restricted stock plans or other similar plans including selecting to whom grants under any such plans are made and determining the terms and type of any such grant;
•: recommending to our board of directors the adoption of amendments to any of our plans and modifying or canceling any exiting grants under such plans;
•: reviewing the sufficiency of the shares available for grant under any of our plans based on our goals for hiring, bonus and retention grants and assessing our competitive position with respect to the level of our equity compensation, vesting schedules and other terms with comparable public companies; and
•: preparing the "Report of the Compensation and Governance Committee" to be included in our proxy statement.

Compensation Program Objectives

The objectives of our executive compensation programs are as follows:

•: attract and retain talented and experienced executives;
•: motivate and reward executives whose knowledge, skills and performance are critical to our success;

•: align the interests of our executive officers and stockholders by motivating executive officers to increase shareholder value and rewarding executive officers when shareholder value increases;
•: provide a competitive compensation package that is weighted heavily towards pay for performance, and in which total compensation is primarily determined by company and individual results and the creation of shareholder value;
•: insure fairness among the executive management team by recognizing the contributions each executive makes to our success;
•: foster a shared commitment among executives by coordinating their company and individual goals; and
•: compensate our executives accordingly to meet our long-term objectives.

The Compensation and Governance Committee evaluates the objectives of our executive compensation programs on a regular basis. In determining the objectives of our executive compensation programs, the Compensation and Governance Committee examines the appropriate matching of compensation to performance as an individual and as an executive group. The Committee is responsible for comparative analysis of our executive compensation plan against others in the industry to insure that the executive compensation plans are competitive.

The Compensation and Governance Committee is responsible for reviewing and making recommendations to our board of directors regarding our executive compensation programs. These programs were implemented to achieve the objectives established by the Compensation and Governance Committee for compensating our executive officers. The Compensation and Governance Committee reviews our executive compensation programs on an annual basis to determine if such programs are effective in achieving the objectives established by the Compensation and Governance Committee. Compensation objectives are established based upon various measurements of profitability, share value enhancement and specific transaction conclusion, both as individuals and as a management group.

To assist management and the Compensation and Governance Committee in assessing and determining compensation packages, the Compensation and Governance Committee may engage compensation consultants based upon the specific needs of the Compensation and Governance Committee. The Compensation and Governance Committee will contract with the consultants directly and will control and direct the work to be performed.

The Compensation and Governance Committee meets outside the presence of all of our executive officers to consider the appropriate compensation for our Chief Executive Officer. For all other named executive officers, the Compensation and Governance Committee meets outside the presence of all executive officers, except our Chief Executive Officer. Our Chief Executive Officer annually reviews the performance of each named executive officer with the Compensation and Governance Committee and makes recommendations to the Compensation and Governance Committee with respect to the appropriate base salary, payments to be made under our annual cash incentive plan and the grant of long-term equity incentive awards. Based in part on these recommendations from our Chief Executive Officer and the other considerations discussed below, the Compensation and Governance Committee approves the annual compensation package of each of our executive officers, other than our Chief Executive Officer. The Compensation and Governance Committee analyzes the performance of our Chief Executive Officer and determines the base salary, payments to be made under our annual cash incentive plan and the grants of long-term equity incentive awards. Input or suggestions applicable to group or individual compensation from other executive officers are solicited from our Chief Executive Officer by the Compensation and Governance Committee, and the Compensation and Governance Committee typically does not solicit input from our executive officers,

other than our Chief Executive Officer, in determining compensation levels of our other executive officers. The Compensation and Governance Committee may seek input from our executive officers in addition to our Chief Executive Officer when establishing future performance goals of our individual executive officers.

Compensation for each executive officer is determined by the Compensation and Governance Committee by evaluating such officer's performance, our performance, and the officer's impact on our performance. Based upon these evaluations, the Compensation and Governance Committee determines the compensation for each of our executive officers, consistent with the objectives established by the Compensation and Governance Committee. The Compensation and Governance Committee also compares the compensation (including salary, bonuses, long-term incentives, etc.) paid by us to our executive officers to similarly-positioned executive officers in our industry, specifically other publicly held oil and gas companies with headquarters in the Rocky Mountain region such as: Cimarex Energy Co., Delta Petroleum Corporation, Forest Oil Corporation, St. Mary Land & Exploration Company and Whiting Petroleum Corporation. These are our five primary Rocky Mountain publicly traded competitors, thus providing a relevant benchmark for comparing our executive officers' compensation. The competitors have operations in similar areas, require executives with similar experience, and we compete against them for employees in all areas and at all levels of expertise, experience and abilities.

The Compensation and Governance Committee establishes specific performance targets that our executive officers must achieve in order to receive certain types of compensation, including annual bonuses, base pay increases and performance awards under our Amended and Restated 2006 Long-Term Incentive Plan. These performance targets are intended to be accurate indicators of the executive officers' impact on our operational success and to provide specific standards that motivate the officers to perform in our best interest and in our stockholders best interests. These targets include performance measures that increase the value of the company including: net income, EBITDAX, reserve growth and specific major tasks that need to be accomplished to insure the financial health of the company. Each officer's individual goals are set based upon those activities that are within their control.

Specifically, compensation is based upon a competitive plan but paid based upon a combination of group and individual goals that include meeting or exceeding profitability, oil and gas reserve enhancement, cash flow from operations or other goals established by the board that is expected to enhance the value of our stock. In addition, there are certain transactional achievements that must be achieved each year to insure our financial health. For example, the Chief Financial Officer may need to renegotiate the company's lending agreement, the exploration manager may need to hire geologists, the Chief Operating Officer may need to reduce lease operating expenses to a directed level and the Vice President of Land may need to complete the acquisition of significant leases in a targeted drilling area. Each one of the financial, operational or transactional goals is weighted for each executive to match the relative importance of the goal.

Our current board of directors and the committees thereof were not established until September 2006. The salaries and bonuses of our named executive officers for fiscal 2007 were determined by our Compensation and Governance Committee. The salaries of our named executive officers for fiscal 2006 were determined in early 2006 by our board of directors, which at that time was comprised of Messrs. Lubar, Leidel, Lawrence and Martin. Mr. Martin, who also serves as our President and Chief Executive Officer, had significant input in determining the salaries and bonuses of our named executive offers. The salaries were established based upon the levels of responsibility of each named executive officer. Our Compensation and Governance Committee determined and granted employee bonuses for 2007 and 2006 based upon our achievements, performance, growth and implied value. In addition, the Compensation and Governance Committee was aware of the compensation levels in other companies that are similarly situated to us and have employees with similar responsibilities to those of our employees. For 2007 Mr. Casperson's bonus amount was higher than

amounts paid to Mr. McClure, Mrs. Walker, and Mr. Williams because of his additional responsibilities attributed to our initial public offering. In 2006, Mr. Casperson's bonus award was less than Mr. McClure, Mrs. Walker, and Mr. Williams, as part of his bonus was voluntarily allocated to the bonus pool for personnel in one of his departments.

Certain Policies of Our Executive Compensation Programs

We have adopted the following material policies relating to our executive compensation programs:

•: Allocation between long-term and currently paid out compensation. The compensation we currently pay consists of base pay and annual incentive compensation. The long-term compensation consists entirely of awards under our Amended and Restated 2006 Long-Term Incentive Plan. The allocation between long-term and currently paid out compensation is based on an analysis of how our peer companies use long-term and currently paid compensation to pay their executive officers.
•: Allocation between cash and non-cash compensation. It is our policy to allocate all currently paid compensation in the form of cash and all long-term compensation in the form of awards of options to purchase our common stock. We consider and generally follow competitive market analyses when determining the allocation between cash and non-cash consideration. Competitive market analyses allows our Compensation and Governance Committee to determine what our competitors are paying their executives and provides the Committee a basis for allocating compensation between cash and non-cash compensation.
•: Return of incentive pay. We intend to implement a policy for the adjustment or recovery of awards or payments if performance measures upon which they are based are materially restated or otherwise adjusted in a manner that will reduce the size of an award or payment. This policy will include the return by any executive officer of any compensation based upon performance measures that require material restatement because of such executive's intentional misconduct or misrepresentation.

Our Executive Compensation Programs

Overall, our executive compensation programs are designed to be consistent with the objectives and principals set forth above. The basic elements of our executive compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation program.

Element	Characteristics	Purpose
Base Salary	Competitive to industry	Attract and retain
Incentive Bonus	Based upon performance individually and as an executive group	To motivate enhanced share value, short and long term financial growth and stability of the company
Long-Term Equity Incentive Plan Awards	Based upon performance individually and as an executive group	To retain and motivate our executives over a longer term
Retirement Savings Opportunity	Competitive to the industry	Enhance overall compensation package
Health & Welfare Benefits	Competitive to industry	Attract and retain
Other Perquisites	Competitive to the industry	Attract, retain and motivate

All pay elements are cash-based except for the long-term equity incentive program, which is an equity-based award. We consider market pay practices and practices of peer companies in determining the amounts to be paid, what components should be paid in cash versus equity and how much of a named executive officer's compensation should be short-term versus long-term. Compensation opportunities for our executive officers, including our named executive officers, are designed to be competitive with peer companies. We believe that a substantial portion of each named executive officer's compensation should be in performance-based pay.

In determining whether to increase or decrease compensation to our executive officers, including our named executive officers, we take into account annually the changes (if any) in the market pay levels based on our peer group, the contributions made by the executive officer, the performance of the executive officer, the increases or decreases in responsibilities and roles of the executive officer, the business needs of the executive officer, the transferability of managerial skills to another employer, the relevance of the executive officer's experience to other potential employers and the readiness of the executive officer to assume a more significant role with another organization.

In general, compensation or amounts realized by executives from prior compensation, such as gains from previously awarded stock options or options awards, are not taken into account in setting other elements of compensation, such as base pay, incentive bonuses or awards of stock options under our long-term equity incentive program. With respect to new executive officers, we take into account their prior base salary and annual cash incentives, as well as the contributions expected to be made by the new executive officer, and the role of the executive officer with us. We believe that our executive officers should be fairly compensated each year relative to market pay levels of our peer group and the internal pay levels of our other executive officers.

Annual Cash Compensation

To attract and retain executives with the ability and the experience necessary to lead us and deliver strong performance to our stockholders, we provide a competitive total compensation package.

Base salaries are intended to be competitive with our peer group, while total compensation is intended to exceed that of our peer group, considering individual performance and experience, to ensure that each executive is appropriately compensated.

Base Salary

Annually we review salary ranges and individual salaries for our executive officers. We establish the base salary for each executive officer based in consideration of pay levels of our peer group and internal factors, such as the individual's performance and experience, and the pay of others on the executive team.

We consider market pay levels among individuals in comparable positions with transferable skills within the oil and gas industry and comparable companies in general industry. When establishing the base salary of any executive officer, we also consider business requirements for certain skills, individual experience and contributions, the roles and responsibilities of the executive and other factors. We believe competitive base salary is necessary to attract and retain an executive management team with the appropriate abilities and experience required to lead us. Approximately 25% to 45% of an executive officer's total compensation is comprised of base salary, depending on the executive's role with us.

The base salaries paid to our named executive officers are set forth below in the Summary Compensation Table. See "—Summary of Compensation."

Annual Incentive Bonuses

We provide the opportunity for our named executive officers and other executives to earn an annual cash incentive award. We provide this opportunity to attract and retain an appropriate caliber of talent for the position and to motivate executives to achieve our annual business goals. We plan to review annual cash incentive awards for our named executive officers and other executives annually at the end of each fiscal year to determine award payments for the last completed fiscal year, as well as to establish award opportunities for the next fiscal year.

There were no specific individual performance goals or profitability measures for the 2007 incentive awards, but the Compensation and Governance Committee or the board of directors may exercise discretion and take into account individual performance in determining the awards. For 2007, the incentive awards were subject to the Compensation and Governance Committee's discretion, based upon recommendations from our Chief Executive Officer, and the Compensation and Governance Committee did not target bonus payouts to those of other similarly situated companies. Bonuses were based upon our overall performance, each officer's performance, and the overall impact of each officer's performance on our performance. In 2007 and 2006 each of our Vice Presidents who are named executive officers were awarded approximately the same bonuses, except for Mr. Casperson who, in 2007, received a higher amount for his efforts related to our initial public offering and Mr. Williams who, in 2006, received an additional bonus for his performance related to our acquisition of properties in Kansas. The level of bonuses for Mr. Martin and our Vice Presidents was based upon our overall performance, growth and implied value. We may make adjustments to our overall corporate performance goals and our actual performance results that may cause differences between the numbers used for the effect of external events that are outside the control of our executives, such as natural disasters, litigation, or regulatory changes in accounting or taxation standards. These adjustments may also exclude all or a portion of both the positive or negative effect of unusual or significant strategic events that are within the control of our executives but that are undertaken with an expectation of improving our long-term financial performance, such as restructurings, acquisitions or divestitures.

Long-term Equity Incentive Compensation

We award long-term equity incentive grants to executive officers, including the named executive officers, as part of our total compensation package, under our Amended and Restated 2006 Stock Incentive Plan (the "2006 Plan").

The 2006 Plan allows for the grant of stock options, stock appreciation rights, restricted stock, stock units, unrestricted stock, dividend equivalent rights and cash awards. The primary purpose of the 2006 Plan is to enhance our ability to attract and retain highly qualified officers, directors, key employees, and other persons, and to motivate such persons to continue in our service and to expend maximum effort to improve our business results and earnings, by providing to such persons an opportunity to acquire or increase a direct proprietary interest in our operations and future success.

The Compensation and Governance Committee administers the 2006 Plan and in doing so, the Compensation and Governance Committee selects participants to receive awards, determines the types of awards, the terms and conditions of the awards, and interprets the provisions of the 2006 Plan.

Other Benefits

Retirement Savings Opportunity

All employees may participate in our 401(k) Retirement Savings Plan, or 401(k) Plan, established in 2006. Each employee may make before tax contributions of up to 60% of their base salary, subject to the current Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. We do not match any contributions made by our employees to the 401(k) Plan. However, we did make an aggregate discretionary contribution of $110,000 for the 2006 plan year. We have not yet determined either the amount or whether we will make a discretionary contribution to our employees for the 2007 plan year. We also do not provide an option for our employees to invest in our stock in the 401(k) plan.

Health and Welfare Benefits

All fulltime employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.

Other Items of Compensation

Our Chief Executive Officer participates in a plan that reimburses him for out of pocket medical costs. In addition, we pay for a life insurance policy that our Chief Executive Officer owns and directs the beneficiary. Until August 2007, our employees used credit cards issued from the personal account of our Chief Executive Officer and the award benefits of those credit cards inured to our Chief Executive Officer. For 2007 and 2006, the estimated value of the credit card awards was approximately $583 and $2,331, respectively.

Our named executive officers and key employees are provided an allowance for the use of mobile phones.

Employment Agreements and Other Arrangements

We have entered into an employment agreement with T. Scott Martin, our President and Chief Executive Officer. The agreement provides for an employment term of two years ending on July 11, 2008, although it may be terminated earlier under certain circumstances. Under the terms of the agreement, Mr. Martin will receive an annual base salary of $341,000 and is eligible to receive an annual bonus, to be determined by the Compensation and Governance Committee. The employment

agreement also provides that if Mr. Martin's employment is terminated by us without cause or by him for good reason, which includes our failure to perform under the agreement, he will be entitled to receive severance compensation consisting of the unpaid portion of his total base salary for the current year, an additional year's base salary and reimbursement for all unpaid travel and other business expenses.

Under the employment agreement, if benefits to which the executive becomes entitled are considered "excess parachute payments" under Section 280G of the Tax Code, then he will be entitled to an additional "gross-up" payment from us in an amount such that, after payment by the executive of all taxes, including any excise tax imposed upon the gross-up payment, he retains an amount equal to the excise tax imposed upon the payment.

Mr. Martin is entitled to all of the employee benefits, fringe benefits and perquisites we provide to other employees. We have not entered into an employment agreement with any other executive officer.

All of our named executive officers have executed "non-solicitation" agreements in the event of their termination of employment with us, prohibiting them from hiring any of our employees for a period of twelve months after the officer's termination.

Stock Ownership Guidelines

Stock ownership guidelines have not been implemented by the Compensation and Governance Committee for our executive officers. Until recently, our common stock was subject to a stockholders agreement that limited a stockholder's ability to transfer stock. We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines.

Securities Trading Policy

Our securities trading policy states that executive officers, including the named executive officers and directors, may not purchase or sell puts or calls to sell or buy our stock, engage in short sales with respect to our stock or buy our securities on margin. The purchase or sale of stock by our officers may only be made during a window of time established by the Compensation and Governance Committee with the aid of legal counsel.

Tax Deductibility of Executive Compensation

Limitations on deductibility of compensation may occur under Section 162(m) of the Internal Revenue Code which generally limits the tax deductibility of compensation paid by a public company to its Chief Executive Officer and certain other highly compensated executive officers to $1 million in the year the compensation becomes taxable to the executive officer. There is an exception to the limit on deductibility for performance based compensation that meets certain requirements.

Although deductibility of compensation is preferred, tax deductibility is not a primary objective of our compensation programs. We believe that achieving our compensation objectives set forth above is more important than the benefit of tax deductibility, and we reserve the right to maintain flexibility in how we compensate our executive officers that may result in limiting the deductibility of amounts of compensation from time to time. However, it is not anticipated that the compensation level will exceed the tax deductible limitations for any of our executive officers.

Conclusion

We believe the compensation we have provided to each of our executive officers is reasonable and appropriate to facilitate the achievement of our operational objectives. The compensation programs and policies that we and our Compensation and Governance Committee have designed effectively incentivize our executive officers on both a short-term and long-term basis to perform at a level necessary to achieve these objectives. The various elements of compensation combine to align the best interests of our executive officers with the best interests of our stockholders and our best interests in order to maximize shareholder value.

SUMMARY OF COMPENSATION

The following table shows information concerning the annual compensation for services provided to us by our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers during the 2007 and 2006 fiscal years.

Name and Principal Position	Year	Salary		Bonus(1)		Stock Awards		Option Awards(2)		Non-Equity Incentive Plan Compensation Earnings		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation(3)			Total
T. Scott Martin Chairman, President and Chief Executive Officer	2007 2006	$ $	341,000 341,000	$ $	294,000 —	$ $	— —	$ $	338,545 359,083	$ $	— —	$ $	— —	$ $	15,764 16,870	(4) (4)	$ $	989,309 716,953
Richard F. McClure Jr. Vice President of Operations and Chief Operating Officer	2007 2006	$ $	220,000 185,000	$ $	120,000 160,000	$ $	— —	$ $	200,916 206,606	$ $	— —	$ $	— —	$ $	2,400 10,057	(5)	$ $	543,316 561,663
James R. Casperson(6) Vice President of Finance and Chief Financial Officer	2007 2006	$ $	220,000 200,000	$ $	220,000 —	$ $	— —	$ $	165,848 165,848	$ $	— —	$ $	— —	$ $	900 900		$ $	606,748 366,748
Valerie K. Walker Vice President of Exploration	2007 2006	$ $	220,000 185,000	$ $	160,000 160,000	$ $	— —	$ $	200,916 206,606	$ $	— —	$ $	— —	$ $	2,520 9,517		$ $	583,436 561,123
Jeffery S. Williams Vice President of Land and Acquisitions	2007 2006	$ $	220,000 185,000	$ $	160,000 260,000	$ $	— —	$ $	165,848 165,848	$ $	— —	$ $	— —	$ $	1,545 7,657		$ $	547,393 618,505

(1): The level of bonuses was based upon our overall performance, growth and implied value. In connection with our private placement sale of 12,400,000 shares of common stock in 2006, Mr. Martin and Mr. Casperson forfeited bonuses of $300,000 and $155,000, respectively, as the resale shelf registration was not effective within established deadlines.
(2): Consists of grants of option awards that were made in 2004 and 2005 and which vest ratably over a three-year period. Commencing January 1, 2006, we began measuring the value and recognizing the cost of the unvested awards over the period in which the employee provides the services. Compensation expense was computed in accordance with SFAS 123(R). A discussion of the assumptions used in calculating these values may be found in Note 6 to our financial statements for the year ended December 31, 2007 included herein. There were no forfeitures of awards.
(3): Includes all other compensation including medical reimbursements, insurance reimbursements, cell phone expenses, membership dues, and company contributions to retirement and 401(k) plans.
(4): During 2006, all other compensation consists of $8,113 for out-of-pocket medical expense reimbursements, payments aggregating $5,600 for a life insurance policy owned by Mr. Martin, $826 for dues for a club membership, and credit card award benefits with an estimated value of $2,331. During 2007, all other compensation consists of $8,753 for out-of-pocket medical expense reimbursements, payments aggregating $5,600 for a life insurance policy owned by Mr. Martin, $828 for dues for a club membership, and credit card award benefits with an estimated value of $583.
(5): All other compensation consists of a cellular telephone stipend in the amount of $2,400 and a discretionary 401(k) contribution in the amount of $7,657.
(6): James R. Casperson retired March 7, 2008.

Grants of Plan-Based Awards

During the 2007 and 2006 fiscal years, we did not make any rewards under any plan to our named executive officers.

Discussion of Summary Compensation and Plan-Based Awards Tables

Our executive compensation policies and practices, pursuant to which the compensation set forth in the Summary Compensation Table was paid or awarded, are described above under

"Compensation Discussion and Analysis." A summary of certain material terms of our compensation plans and arrangements is set forth below.

Description of the Amended and Restated 2006 Stock Incentive Plan

Our Amended and Restated 2006 Stock Incentive Plan (the "2006 Plan") is the successor equity incentive program to our 2002 Stock Option Plan. We do not intend to make any additional grants under our 2002 Stock Option Plan. All outstanding awards under our 2002 Stock Option Plan have been transferred to our 2006 Plan; however, such awards will continue to be subject to their existing terms. The following is a summary of the 2006 Plan.

Administration. The 2006 Plan provides for administration by our board of directors or otherwise by a compensation committee or other committee of our board of directors. Subject to the terms of the 2006 Plan, our board of directors or the committee administering the 2006 Plan may select participants to receive awards, determine the types of awards and terms and conditions of awards and interpret provisions of the 2006 Plan. Currently, the 2006 Plan is administered by the Compensation and Governance Committee.

Common Stock Reserved for Issuance under the 2006 Plan. Our common stock issued or to be issued under the 2006 Plan consists of authorized but unissued shares and issued shares that we have reacquired. If any shares covered by an award are not purchased or are forfeited, or if an award otherwise terminates without delivery of any common stock, then the number of shares of common stock counted against the aggregate number of shares available under the 2006 Plan with respect to the award will, to the extent of any such forfeiture or termination, again be available for making awards under the 2006 Plan.

Eligibility. Awards may be made under the 2006 Plan to our employees and consultants, including any such employee who is an officer or director, and to any other individual whose participation in the 2006 Plan is determined by our board of directors to be in our best interest.

Amendment or Termination of the 2006 Plan. Our board of directors may amend, suspend or terminate the 2006 Plan at any time and for any reason. The 2006 Plan shall terminate in any event ten years after the date of its adoption by the board. Amendments to the 2006 Plan will be submitted for stockholder approval to the extent stated by the board of directors, required by the Internal Revenue Code of 1986 or other applicable law or required by applicable stock exchange listing requirements. In addition, an amendment to the 2006 Plan will be contingent on stockholder approval if the amendment would materially increase the benefits accruing to participants under the 2006 Plan, materially increase the aggregate number of shares of common stock that may be issued under the 2006 Plan or materially modify the requirements as to eligibility for participation in the 2006 Plan.

Options. The 2006 Plan permits the granting of options to purchase shares of common stock intended to qualify as incentive stock options under the Internal Revenue Code and stock options that do not qualify as incentive stock options. The exercise price of each stock option may not be less than 100% of the fair market value of the common stock on the date of grant. In the case of certain 10%

stockholders who receive incentive stock options, the exercise price may not be less than 110% of the fair market value of the common stock on the date of grant. An exception to these requirements is made for options that we grant in substitution for options held by employees of companies that we acquire. In such a case the exercise price is adjusted to preserve the economic value of the employee's stock option from his or her former employer.

The term of each stock option is fixed at the time of grant and may not exceed 10 years from the date of grant. The board of directors or committee administering the 2006 Plan determines at what time or times each option may be exercised and the period of time, if any, after retirement, death, disability or termination of employment during which options may be exercised. Options may be made exercisable in installments. The exercisability of options may be accelerated by our board of directors or committee administering the 2006 Plan.

In general, an optionee may pay the exercise price of an option in cash or in cash equivalents, by tendering shares of common stock to the extent provided in an award agreement, by means of a broker-assisted cashless exercise to the extent provided in an award agreement and permitted by applicable law or as otherwise provided in an award agreement and permitted by applicable law.

Stock options granted under the 2006 Plan may not be sold, transferred, pledged or assigned other than by will or under applicable laws of descent and distribution. However, we may permit in an award agreement the limited transfers of non-qualified options for the benefit of family members of grantees.

Other Awards. The 2006 Plan permits the granting of the following additional types of awards:

•: shares of unrestricted stock, which are shares of common stock at no cost or for a purchase price and are free from any restrictions under the 2006 Plan. Unrestricted shares of common stock may be issued to participants in recognition of past services or other valid consideration, and may be issued in lieu of cash compensation to be paid to participants;
•: shares of restricted stock, which are shares of common stock subject to restrictions;
•: stock units, which are common stock units subject to restrictions;
•: dividend equivalent rights, which are rights entitling the recipient to receive credits for dividends that would be paid if the recipient had held a specified number of shares of common stock;
•: stock appreciation rights, which are rights to receive a number of shares or, in the discretion of the administrator, an amount in cash or a combination of shares and cash, based on the increase in the fair market value of the shares underlying the rights during a specified period of time;
•: performance and annual incentive awards, ultimately payable in common stock or cash, as determined by the board or committee administering the 2006 Plan. Multi-year and annual incentive awards may be subject to achievement of specified goals tied to business criteria, as described below. The board or committee administering the 2006 Plan may specify the amount of the incentive award as a percentage of these business criteria, a percentage in excess of a threshold amount or as another amount which need not bear a strictly mathematical relationship to these business criteria. The board or committee administering the 2006 Plan may modify, amend or adjust the terms of each award and performance goal. Awards to individuals who are covered under Section 162(m) of the Internal Revenue Code, or who are likely to be covered in the future, will comply with the requirement that payments to such employees qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code to the extent that the board or committee administering the 2006 Plan so designates. Such employees include the Chief Executive

Officer and the four highest compensated executive officers (other than the Chief Executive Officer) determined at the end of each year.

Minimum Vesting for restricted stock and stock unit. The 2006 Plan provides that restricted stock and stock units that vest solely by the passage of time may vest in no less than three years from the grant date and restricted stock and stock units for which vesting may be accelerated by achieving performance targets may vest in no less than one year from the date of grant.

Section 162(m) of the Internal Revenue Code. Section 162(m) of the Internal Revenue Code limits publicly-held companies to an annual deduction for federal income tax purposes of $1 million for compensation paid to their covered employees. However, performance-based compensation is excluded from this limitation. The 2006 Plan is designed to permit us to grant awards that qualify as performance-based for purposes of satisfying the conditions of Section 162(m).

To qualify as performance-based:

(i): the compensation must be paid solely on account of the attainment of one or more pre-established, objective performance goals;
(ii): the performance goal under which compensation is paid must be established by a compensation committee comprised solely of two or more directors who qualify as "outside directors" for purposes of the exception;
(iii): the material terms under which the compensation is to be paid must be disclosed to and subsequently approved by stockholders of the corporation before payment is made in a separate vote; and
(iv): the compensation committee must certify in writing before payment of the compensation that the performance goals and any other material terms were in fact satisfied.

In the case of compensation attributable to stock options, the performance goal requirement (summarized in (i) above) is deemed satisfied, and the certification requirement (summarized in (iv) above) is inapplicable, if the grant or award is made by the compensation committee of the board of directors; the plan under which the option is granted states the maximum number of shares with respect to which options may be granted during a specified period to an employee; and under the terms of the option, the amount of compensation is based solely on an increase in the value of the common stock after the date of grant.

Under the 2006 Plan, one or more of the following business criteria, on a consolidated basis, and/or with respect to specified subsidiaries or business units, except with respect to the total stockholder return and earnings per share criteria, will be used exclusively by the compensation committee in establishing performance goals:

•: total stockholder return;
•: such total stockholder return as compared to total return (on a comparable basis) of a publicly available index such as the Standard & Poor's 500 Stock Index;
•: net income;
•: pretax earnings;
•: earnings before interest expense, taxes, depreciation and amortization;
•: pretax operating earnings after interest expense and before bonuses, service fees and extraordinary or special items;
•: value of oil and gas reserves;
•: earnings per share;

•: return on equity;
•: return on capital;
•: return on investment;
•: operating earnings;
•: working capital;
•: ratio of debt to stockholders' equity; and
•: revenue.

Business criteria may be measured on a GAAP or non-GAAP basis.

Under the Internal Revenue Code, a director is an "outside director" of a company if he or she is not a current employee of that company; is not a former employee who receives compensation for prior services (other than under a qualified retirement plan); has not been an officer of the company; and does not receive, directly or indirectly (including amounts paid to an entity that employs the director or in which the director has at least a five percent ownership interest), remuneration from the company in any capacity other than as a director.

The maximum number of shares of common stock subject to options or stock appreciation rights that can be awarded under the 2006 Plan to any person is 333,333 per year. The maximum number of shares of common stock that can be awarded under the 2006 Plan to any person, other than pursuant to an option or a stock appreciation rights, is 333,333 per year. The maximum amount that may be earned as an annual incentive award or other cash award in any calendar year by any one person is $2 million, and the maximum amount that may be earned as a performance award or other cash award in respect of a performance period by any one person is $5 million.

Adjustments for Stock Dividends and Similar Events. We may make appropriate adjustments in outstanding awards and the number of shares available for issuance under the 2006 Plan, including the individual limitations on awards, to reflect recapitalizations, reclassifications, stock spits, reverse splits, stock dividends and other similar events.

Effect of Certain Corporate Transactions. Certain change of control transactions involving us, such as the sale of our company, may cause awards granted under the 2006 Plan to vest, unless the awards are continued or substituted for in connection with the change of control transaction.

Outstanding Equity Awards at Fiscal Year-End

The following table summarizes the number of securities underlying outstanding plan awards for each named executive officer as of December 31, 2007.

	Option Awards							Stock Awards
	Number of Securities Underlying Unexercised Options	Number of Securities Underlying Unexercised Options
												Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
											Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested
									Market Value of Shares or Units of Stock That Have Not Vested
				Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options
								Number of Shares of Units of Stock That Have Not Vested
Name					Option Exercise Price		Option Expiration Date
Name	Exercisable	Unexercisable			Option Exercise Price		Option Expiration Date
T. Scott Martin Chairman, President and Chief Executive Officer	269,736 109,244 87,395 325,855	— — — 78,655	(1)	—	$ $ $ $	1.24 2.47 2.47 4.94	June 2009 September 2010 April 2011 July 2012	—	$	—	—	$	—
Richard F. McClure Jr. Vice President of Operations and Chief Operating Officer	202,304 30,265 24,212 195,513	— — — 47,193	(1)	—	$ $ $ $	1.24 2.47 2.47 4.94	June 2009 September 2010 April 2011 July 2012	—	$	—	—	$	—
James R. Casperson Vice President of Finance and Chief Financial Officer	162,928	39,327	(1)(2)	—	$	4.94	July 2012	—	$	—	—	$	—
Valerie K. Walker Vice President of Exploration	89,912 142,657 24,212 195,513	— — — 47,193	(1)	—	$ $ $ $	1.24 2.47 2.47 4.94	June 2009 September 2010 April 2011 July 2012	—	$	—	—	$	—
Jeffery S. Williams Vice President of Land and Acquisitions	162,928	39,327	(1)	—	$	$4.94	July 2012	—	$	—	—	$	—

(1): These options vest ratably on a monthly basis and will be fully vested on July 31, 2008.
(2): Mr. Casperson retired on March 7, 2008 and forfeited 26,957 options.

Option Exercises

Our named executive officers did not exercise any stock options in 2006 or 2007.

Pension Benefits

We do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.

Non-Qualified Deferred Compensation

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

Director Compensation

The following table summarizes compensation that our directors earned during the period from January 1, 2007 through December 31, 2007 for services as members of our Board.

Name	Fees Earned or Paid in Cash		Stock Awards(1)		Option Awards		Non-Equity Incentive Plan Compensation		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
T. Scott Martin	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Cortlandt S. Dietler	$	45,000	$	45,000	$	—	$	—	$	—	$	—	$	90,000
Bryan H. Lawrence	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Peter A. Leidel	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Sheldon B. Lubar	$	—	$	94,000	$	—	$	—	$	—	$	—	$	94,000
Neil L. Stenbuck	$	50,000	$	50,000	$	—	$	—	$	—	$	—	$	100,000
James B. Wallace	$	—	$	89,000	$	—	$	—	$	—	$	—	$	89,000
George A. Wiegers	$	—	$	90,000	$	—	$	—	$	—	$	—	$	90,000

(1): For the year ended December 31, 2007, our non-employee directors elected to receive an aggregate amount of restricted stock awards of approximately $368,000 as compensation for their services. Compensation expense was computed in accordance with SFAS 123(R), based on a fair value amount of $12.00 per share, which was the last executed trade of our stock on the PORTAL market prior to the date of grant. The following directors have restricted stock awards outstanding as of December 31, 2007: Mr. Dietler—3,750 shares; Mr. Lubar—7,833 shares; Mr. Stenbuck—4,167 shares; Mr. Wallace—7,417 shares; and Mr. Wiegers—7,500 shares.

Discussion of Director Compensation Table

Non-employee and non-Yorktown Energy Partners directors receive approximately $90,000 per year in shares of our common stock or cash, at the election of each director, plus meeting expenses of $2,000 per board and $1,000 per committee meeting. The chairman of the audit committee and the compensation and governance committee receive $5,000 and $2,500, respectively.

Employee directors and Yorktown Energy Partners directors do not receive compensation for service on our board of directors. All directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or committees and for other reasonable expenses incurred in connection with service on the board and any committee.

Potential Payments Upon Termination or Change in Control

We have entered into an employment agreement with T. Scott Martin, our President and Chief Executive Officer. Under the terms of the agreement, Mr. Martin receives an annual base salary of $341,000 and is eligible to receive an annual bonus, to be determined by our outside directors or otherwise by a board committee. The employment agreement also provides that if Mr. Martin's employment is terminated by us without cause or by the executive for good reason, which includes our failure to perform under the agreement, he will be entitled to receive severance compensation consisting of the unpaid portion of his total base salary for the current year, an additional year's base salary and reimbursement for all unpaid travel and other business expenses. A change of control does not affect the amount or timing of these cash severance payments.

We are not obligated to make any cash payments to any other named executive officer if their employment is terminated by us or by the executive. No severance benefits are provided for any of the named executive officers in the event of death or disability. A change of control does not affect the amount of timing of these cash severance payments.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of our common stock as of May 31, 2008, by (i) each person who, to our knowledge, beneficially owns more than 5% of our common stock; (ii) each of our directors and executive officers; and (iii) all of our executive officers and directors as a group, before this offering and after the completion of this offering. The table showing the percentage of shares beneficially owned after the offering assumes the sale of 8,000,000 shares of our common stock by us.

		Percentage of Shares Beneficially Owned(2)
	Shares of Ellora Common Stock Beneficially Owned(1)	Percentage of Shares Beneficially Owned(2)
Name and Address of Beneficial Owner	Shares of Ellora Common Stock Beneficially Owned(1)	Before Offering		After Offering
Bryan H. Lawrence(3)(4)	27,462,159	60.4	%	51.4	%
Peter A. Leidel(3)(4)	27,462,159	60.4	%	51.4	%
Yorktown Energy Partners V, L.P.(3)	21,039,278	46.3	%	39.4	%
Yorktown Energy Partners VI, L.P.(3)	6,422,881	14.1	%	12.0	%
T. Scott Martin(5)(6)	2,159,838	4.7	%	4.0	%
Sheldon B. Lubar(7)	1,822,913	4.0	%	3.4	%
Valerie K. Walker(5)(8)	761,366	1.7	%	1.4	%
Richard F. McClure Jr.(5)(9)	761,366	1.7	%	1.4	%
George A. Wiegers(5)	174,167	*	%	*	%
Jeffery S. Williams(5)(10)(11)	252,255	*	%	*	%
Steven R. Enger(5)(12)	186,667	*	%	*	%
James B. Wallace(5)(13)	24,084	*	%	*	%
Cortlandt S. Dietler(5)	12,083	*	%	*	%
Neil L. Stenbuck(5)	4,167	*	%	*	%
All officers and directors as a group (13 persons)	33,571,065	70.6	%	60.4	%

*: Less than one percent.
(1): Unless otherwise indicated, all shares of stock are held directly with sole voting and investment power.
(2): For purposes of calculating the percent of the class outstanding held by each owner shown above with a right to acquire additional shares, the total number of shares excludes the shares which all other persons have the right to acquire within 60 days, pursuant to the exercise of outstanding stock options and warrants.
(3): Has a principal business address of 410 Park Avenue, Suite 1900, New York, New York 10022.
(4): Includes attribution of shares held by Yorktown Energy Partners V, L.P. and Yorktown Energy Partners VI, L.P.
(5): Has a principal business address of c/o Ellora Energy Inc., 5665 Flatiron Parkway, Boulder, Colorado 80301.
(6): Includes options to purchase up to 870,886 shares of common stock, which are exercisable within 60 days.
(7): Has a principal business address of 700 N. Water Street, Suite 1200, Milwaukee, Wisconsin 53202.
(8): Includes options to purchase up to 499,487 shares of common stock, which are exercisable within 60 days.
(9): Includes options to purchase up to 499,487 shares of common stock, which are exercisable within 60 days.
(10): Includes options to purchase up to 202,255 shares of common stock, which are exercisable within 60 days.
(11): Includes shares of restricted stock granted on May 15, 2008 that vest ratably on an annual basis over a three-year period.
(12): Includes shares of restricted stock granted on August 13, 2007 and March 7, 2008, which vest ratably on an annual basis over a three-year period.
(13): Includes 12,500 shares of common stock held by a limited liability company under the control of Mr. Wallace and for which he holds voting and dispositive power.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We have entered into an employment agreement with T. Scott Martin, our Chairman, President and Chief Executive Officer. See "Executive Compensation—Employment Agreements and Other Arrangements" for a detailed description of this agreement. Additionally, we will enter into indemnification agreements with the members of our board of directors.

Ellora was formed in June 2002 through the issuance of approximately 16.2 million shares of common stock for cash consideration of $20 million to Yorktown Energy Partners V, L.P., our controlling stockholder, which was organized to make direct investments in the energy industry on behalf of certain institutional investors, and the issuance of approximately 4.1 million shares of common stock to certain of our executive officers for $1,167 in cash, notes receivable in the amount of $1,667,000, and certain other contributed property pursuant to the terms of a contribution agreement among us, Yorktown, certain of our executive officers, and other investors. The notes issued to us by certain of our executive officers were full recourse, earned interest at an annual rate of 6%, and matured on the earlier of June 7, 2009 or three months after the holder ceased to be employed by us. Their notes receivable are shown in our financial statements as a reduction in stockholders' equity. The note holders repaid these notes with interest upon the closing of the private equity offering in the third quarter of 2006. Ellora Oil & Gas Inc. was formed in 2005 and issued shares of its common stock for cash consideration of $40 million to Yorktown Energy Partners VI, L.P., which received approximately 8,000,000 post-split shares of our common stock upon completion of the merger.

On April 15, 2004, we purchased the interests held by Durango Connection Pipeline in English Bay for approximately $6.7 million in cash. English Bay Pipeline, L.P. is now our wholly owned subsidiary. The valuation of Durango Connection Pipeline's partnership interest in English Bay was determined by arm's length negotiations between us and Mr. Allen Born, the owner of 100% of Durango Connection Pipeline, and we believe the terms of the acquisition were commensurate with the terms of a third-party oil and gas industry arrangement. At the time of the acquisition, Mr. Born was a stockholder and member of our board of directors. The terms of the transaction were approved by all of the independent members of our board of directors.

On August 29, 2005, we acquired interests in oil and gas properties in Shelby County, Texas from Durango Connection LLLP for $26 million in cash. Durango Connection LLLP was owned 99% by Mr. Allen Born at the time of the acquisition. The valuation of the purchased Shelby County oil and gas interests held by Durango Connection LLLP was determined by arms-length negotiations between us and Mr. Born, and we believe the terms of the acquisition were commensurate with the terms of a third-party oil and gas industry arrangement. At the time of the acquisition, Mr. Born was a stockholder and member of our board of directors. The terms of the transaction were approved by all of the independent members of our board of directors.

On June 1, 2004, we entered into a joint venture agreement with Centurion Exploration Company, pursuant to which we paid Centurion $1.25 million for the right to participate in all prospects that Centurion generated through September 2007. We participated in five wells with Centurion. The joint venture agreement was negotiated at arm's length between us and Centurion. At the time we entered into the joint venture agreement and at the time the abovementioned wells were drilled, T. Scott Martin was a member of the board of directors of Centurion, in which an affiliate of Yorktown owns a controlling interest. The terms of the transaction were approved by all of the independent members of our board of directors. Mr. Martin has resigned from the board of directors of Centurion. In December 2006, we sold our interest in the Centurion Joint Venture and our interest in certain minor wells drilled by Centurion in East Texas for approximately $3,000,000, less closing adjustments, and no gain or loss was recognized.

Procedures for Approval of Related Person Transactions

In the event that a related party transaction is identified, such transaction must be reviewed and approved by our Chief Executive Officer or other members of management, our board of directors or the independent members of our board of directors, depending on the parties involved and the terms of the proposed transaction. Additionally, related party transactions cannot be approved by our Chief Executive Officer or other members of management or a member of our board of directors if they are a party to the transaction. In such instance, an unrelated party must approve that particular related party transaction.

SELLING STOCKHOLDERS

The following table and related footnotes set forth certain information regarding the selling stockholders. The number of shares in the column "Number of Shares of Common Stock Offered Hereby" represents all of the shares that each selling stockholder is offering under this prospectus. To our knowledge, each of the selling stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus or to the extent this power may be shared with a spouse. Except as noted in this prospectus, none of the selling stockholders is a director, officer, or employee of ours or an affiliate of such person.

Selling Stockholders	Number of Shares of Common Stock Owned Prior to the Offering⁽¹⁾	Number of Shares of Common Stock Offered Hereby	Number of Shares of Common Stock Owned After the Offering⁽¹⁾	Percentage of Shares of Common Stock Owned After Completion of the Offering
BBT Fund, L.P.(2)	118,000	118,000	—	*
Blue Ridge Investments, Inc.(3)	1,600	1,600	—	*
Brian & Kelly Wilmovsky	2,000	2,000	—	*
CAP Fund, L.P. (4)	58,000	58,000	—	*
Clinton Multistrategy Master Fund, Ltd.(5)	1,250,000	1,250,000	—	*
Doyle Family Trust(6)	3,000	3,000	—	*
Edward Im & Jill Im	2,000	2,000	—	*
Elizabeth Sexworth Rollover IRA(7)	840	840	—	*
Eric W. Reimers & Marcia Reimers(7)	8,000	8,000	—	*
GLG North American Opportunity Fund(8)	1,041,666	1,041,666	—	*
George R. & Elizabeth K. Hutchinson(7)	25,000	25,000	—	*
Francis E. Belmont	2,000	1,000	1,000	*
Grandview, LLC(9)	500,000	500,000	—	*
Keegan Family Trust(10)	10,000	10,000	—	*
Kenmont Special Opportunities Master, L.P.(11)	78,000	78,000	—	*
LeRoy Eakin III & Lindsay Eakin, JTBE	6,250	6,250	—	*
Man Mac Miesque(11)	52,000	52,000	—	*
Michael E. Heijer	2,000	2,000	—	*
Nadine Grelsamer	3,000	1,500	1,500	*
Neuhauser Capital, LLC(12)	40,000	40,000	—	*
Peter Helms IRA(7)	400	400	—	*
Peterson Investment Trust UAD 4/2/01(13)	333,333	83,333	250,000	*
Robert H. Smith	9,000	9,000	—	*
SRI Fund, L.P.(14)	24,000	24,000	—	*
Steven L. Harrison IRA(7)	600	600	—	*
Tivoli Partners L.P.(15)	20,000	20,000	—	*
White River Partners, L.P.(16)	115,000	25,000	90,000	*

Total	3,705,689	3,363,189	342,500	*

*: Less than 1%
(1): Ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934
(2): Sid R. Bass is the President and controlling stockholder of BBT-FW, Inc., the General Partner of BBT Genpar, L.P., the Managing General Partner of BBT Fund, L.P. By virtue of his position at BBT-FW, Inc., Mr. Bass is deemed to hold investment power and voting control over the shares held by this selling stockholder.

(3): David H. Stevenson is the President of Blue Ridge Investments, Inc. and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(4): Sid R. Bass is the President and controlling stockholder of CAP-FW, Inc., the General Partner of CAP Genpar, L.P., the Managing General Partner of CAP Fund, L.P. By virtue of his position at CAP-FW, Inc., Mr. Bass is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(5): George Hall is the Chief Investment Officer and President of Clinton Group, Inc., the Investment Manager of this selling stockholder. By virtue of his position at Clinton Group, Inc., Mr. Hall may be deemed to hold investment power and voting control over the shares held by this selling stockholder.
(6): James G. Doyle and Virginia K. Doyle are trustees of this selling stockholder and are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(7): This selling stockholder is not a broker-dealer; however, it is an affiliate of a broker-dealer. The shares held by this selling stockholder were purchased in the ordinary course of business and, at the time of purchase, this selling stockholder had no agreements or understandings, directly or indirectly, with any party to distribute the shares.
(8): Noam Gottesman, Pierre Lagrange and Emmanuel Roman are Managing Directors of GLG Partners LP, the Investment Manager of this selling stockholder. By virtue of their positions with GLG Partners LP, the above listed individuals are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(9): Israel A. Englander is the Managing Member of Millennium Management, L.L.C., the Managing Partner of Millennium Partners, L.P., the Managing Member of Grandview, LLC. By virtue of his position at Millennium Management, L.L.C., Mr. Englander is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(10): Eamon Keegan is the trustee of the Keegan Family Trust and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(11): Donald R. Kendall is the Managing Director of Kenmont Investments Management, L.P., the Investment Manager of this selling stockholder. By virtue of his position with Kenmont Investments Management, L.P., Mr. Kendall is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(12): James C. Neuhauaser is the Managing Member of Neuhauser Capital, LLC and is deemed to hold investment power and voting control over the shares held by this selling stockholder. This selling stockholder is not a broker-dealer; however, it is an affiliate of a broker-dealer. The shares held by this selling stockholder were purchased in the ordinary course of business and, at the time of purchase, this selling stockholder had no agreements or understandings, directly or indirectly, with any party to distribute the shares.
(13): Claudia M. Sensi and Nancy M. McGrath are trustees of this selling stockholder and are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(14): Sid R. Bass is the President and controlling stockholder of BBT-FW, Inc., the General Partner of SRI Genpar, L.P., the Managing General Partner of SRI Fund, L.P. By virtue of his position at BBT-FW, Inc., Mr. Bass is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(15): Peter Kenner is the General Partner of this selling stockholder and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(16): Allen C. Benello is the Managing Member of White River Investment Partners, LLC, the General Partner of this selling stockholder. By virtue of his position with White River Investment Partners, LLC, Mr. Benello is deemed to hold investment power and voting control over the shares held by this selling stockholder.

DESCRIPTION OF CAPITAL STOCK

Pursuant to our amended certificate of incorporation, we have the authority to issue an aggregate of 135,000,000 shares of capital stock, consisting of 125,000,000 shares of common stock, par value $0.001 per share, and 10,000,000 shares of preferred stock, par value $0.001 per share.

Selected provisions of our organizational documents are summarized below. Forms of our organizational documents are attached as exhibits to the registration statement of which this prospectus is a part. In addition, the summary below does not give full effect to the terms of the provisions of statutory or common law which may affect the rights of a stockholder.

Common Stock

As of May 31, 2008, we had a total of 45,436,472 shares of common stock and no shares of preferred stock outstanding. Following the completion of this offering and assuming that the underwriters exercise their option to purchase additional shares in full, we will have 55,140,950 shares of common stock outstanding based on the number of shares outstanding as of May 31, 2008. We have reserved 6,306,910 stock options for issuance to employees under our 2006 Plan. As of May 31, 2008, we had stock options to purchase 2,515,753 shares of our common stock outstanding. We have reserved 884,616 shares of restricted common stock for issuance to our employees under our 2006 Plan. As of May 31, 2008 we had 549,631 shares of restricted common stock outstanding.

Voting rights. Each share of common stock is entitled to one vote in the election of directors and on all other matters submitted to a vote of our stockholders. Our stockholders may not cumulate their votes in the election of directors. Each of our directors is elected on an annual basis by our stockholders voting as a single class.

Dividends, distributions and stock splits. Holders of our common stock are entitled to receive dividends if, as and when such dividends are declared by our board out of assets legally available therefor after payment of dividends required to be paid on shares of preferred stock, if any.

Liquidation. In the event of any dissolution, liquidation, or winding up of our affairs, whether voluntary or involuntary, after payment of our debts and other liabilities and making provision for any holders of our preferred stock who have a liquidation preference, our remaining assets will be distributed ratably among the holders of common stock.

Fully paid. All the shares of common stock to be outstanding upon completion of this offering will be fully paid and nonassessable.

Other rights. Holders of our common stock have no redemption or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock.

The rights preferences and privileges of holders of common stock are subject to, and may be adversely affected by, the rights of holders of shares of any series of preferred stock that we may designate and issue in the future.

Preferred Stock

Our restated certificate of incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.001 per share, covering up to an aggregate of 10,000,000 shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have preferences, voting powers, qualifications and special or relative rights

or privileges as is determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights.

The rights of the holders of common stock will be subject to the rights of holders of any preferred stock issued in the future. The issuance of preferred stock could adversely affect the voting power of holders of common stock and reduce the likelihood that common stockholders will receive dividend payments and payments upon liquidation. The issuance of preferred stock could also have the effect of decreasing the market price of the common stock and could delay, deter or prevent a change in control of our company. We have no present intention to issue any shares of preferred stock.

Certain Effects of Authorized But Unissued Stock

The authorized but unissued shares of common stock and preferred stock are available for future issuance without stockholder approval. These additional shares may be utilized for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans.

The ability of our board of directors to issue authorized but unissued and unreserved common stock and preferred stock could render more difficult or discourage an attempt to obtain control of our company by means of a proxy contest, tender offer, merger, or otherwise, and thereby protect the continuity of our management.

Anti-Takeover Effects of Delaware Law and Our Charter and Bylaw Provisions

A number of provisions in our restated certificate of incorporation, our restated bylaws and Delaware law may make it more difficult to acquire control of us. These provisions could deprive the stockholders of opportunities to realize a premium on the shares of common stock owned by them. In addition, these provisions may adversely affect the prevailing market price of our common stock. These provisions are intended to:

•: enhance the likelihood of continuity and stability in the composition of the board and in the policies formulated by the board;
•: discourage transactions which may involve an actual or threatened change in control of us;
•: discourage tactics that may be involved in proxy fights; and
•: encourage persons seeking to acquire control of our company to consult first with the board of directors to negotiate the terms of any proposed business combination or offer.

Advance Notice Procedures for Stockholder Proposals and Director Nominations

Our restated bylaws provide that stockholders seeking to bring business before an annual meeting of stockholders, or to nominate candidates for election as directors at an annual meeting of stockholders, must provide timely notice thereof in writing. To be timely, a stockholder's notice generally must be delivered to or mailed and received at our principal executive offices not less than 60 and no more than 90 calendar days prior to the first anniversary of the date on which we first mailed our proxy materials for the preceding year's annual meeting of stockholders. In addition, our bylaws specify requirements as to the form and content of a stockholder's notice. These provisions may preclude stockholders from bringing matters before an annual meeting of stockholders or from making nominations for directors at an annual meeting of stockholders.

Stockholder Meetings

Our restated certificate of incorporation provides that stockholders are not permitted to call special meetings of stockholders. Only our board of directors, Chairperson or Chief Executive Officer are permitted to call a meeting of stockholders.

Supermajority Vote to Amend Bylaws

Our restated certificate of incorporation requires the affirmative vote of at least two-thirds of the directors then in office or of the holders of at least two-thirds of the combined voting power of all shares of our stock then outstanding to adopt, amend or repeal any of our bylaws.

Limitation of Liability

Our restated certificate of incorporation provides that to the fullest extent permitted by Delaware law, as that law may be amended and supplemented from time to time, our directors shall not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to us or our stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware General Corporation Law (the "DGCL"), or (iv) for any transaction from which the director derived any improper personal benefit. The effect of the provision of the certificate of incorporation is to eliminate our rights and the rights of our stockholders (through stockholders' derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director (including breaches resulting from negligent behavior) except in the situations described in clauses (i) through (iv) above. Our bylaws also set forth certain indemnification provisions and provide for the advancement of expenses incurred by a director in defending a claim by reason of the fact that he was one of our directors (or was serving as a director or officer of another entity at our request), provided that the director agrees to repay the amounts advanced if the director is not entitled to be indemnified by us under the provisions of the DGCL. The indemnification provisions of our certificate of incorporation may reduce the likelihood of derivative litigation against directors and may discourage or deter stockholders or management from bringing a lawsuit against directors for breaches of their fiduciary duties, even though an action, if successful, otherwise might have benefited us and our stockholders.

The right to indemnification and advancement of expenses are not exclusive of any other rights to indemnification our directors or officers may be entitled to under any agreement, vote of stockholders or disinterested directors or otherwise. We intend to enter into indemnification agreements with each of our directors and some of our officers pursuant to which we agree to indemnify the director or officer against expenses, judgments, fines or amounts paid in settlement incurred by the director or officer and arising out of his capacity as a director, officer, employee and/or agent of our company or other enterprise of which he is a director, officer, employee or agent acting at our request to the maximum extent permitted by applicable law, subject to certain limitations. Additionally, under Delaware law, we may purchase and maintain insurance for the benefit and on behalf of our directors and officers insuring against all liabilities that may be incurred by the director or officer in or arising out of his capacity as our director, officer, employee and/or agent.

Delaware Business Combination Statute

We have elected in our restated certificate of incorporation to be subject to Section 203 of the Delaware General Corporation Law regulating corporate takeovers. This section prevents a Delaware corporation from engaging in a business combination which includes a merger or sale of more than 10% of the corporation's assets with a stockholder who owns 15% or more of the corporation's

outstanding voting stock, as well as affiliates and associates of any of those persons. That prohibition extends for three years following the date that stockholder acquired that amount of stock unless:

•: the transaction in which that stockholder acquired the stock is approved by the board of directors prior to that date;
•: upon completion of the transaction that resulted in the acquisition of the stock, the stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding those shares owned by various employee benefit plans or persons who are directors and also officers; or
•: on or after the date the stockholder acquired the stock, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders by the affirmative vote of at least two-thirds of the outstanding voting stock that is not owned by the stockholder.

A corporation may, at its option, exclude itself from Section 203 of the Delaware General Corporation Law by amending its certificate of incorporation or bylaws by action of its stockholders. The charter or bylaw amendment shall not become effective until 12 months after the date it is adopted or applies to a stockholder. Section 203 will not apply to a business combination between us and Yorktown because Yorktown held more than 15% of our stock prior to the effective date of our restated certificate of incorporation.

SHARES ELIGIBLE FOR FUTURE SALE

Prior to the date of this prospectus, there has been no public market for our common stock. The sale of a substantial amount of our common stock in the public market after we complete this offering, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. Furthermore, because some of our shares will not be available for sale shortly after this offering due to the contractual and legal restrictions on resale described below and the fact that a substantial majority of our shares of common stock are subject to registration rights held by certain of our selling stockholders, the sale of a substantial amount of common stock in the public market after these restrictions lapse or in the future by these selling stockholders could adversely affect the prevailing market price of our common stock and our ability to raise equity capital in the future.

As of March 31, 2008, we had 45,384,387 shares of common stock outstanding. All of the shares of our common stock sold in this offering will be freely tradable without restrictions or further registration under the Securities Act, unless the shares are purchased by "affiliates" as that term is defined in Rule 144 under the Securities Act and except certain shares that will be subject to the lock-up periods described under the caption "Underwriting—Lock-up Agreements," following the completion of this offering. Any shares purchased by an affiliate may not be resold except in compliance with Rule 144 volume limitations, manner of sale and notice requirements, pursuant to another applicable exemption from registration or pursuant to an effective registration statement. The shares of common stock currently held by our employees are "restricted securities" as that term is defined in Rule 144 under the Securities Act. These restricted securities may be sold in the public market by our employees only if they are registered or if they qualify for an exemption from registration under Rule 144 under the Securities Act. These rules are summarized below.

Rule 144

In general, under Rule 144 as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register approximately 3,600,000 shares of common stock issuable, with respect to options and restricted stock units that have been exercised or will be granted under our employee plans or otherwise. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Shares issued under our 2006 Plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statements, subject to Rule 144 limitations applicable to affiliates. Under

Rule 701 under the Securities Act, as currently in effect, each of our employees, officers, directors, and consultants who purchased or received shares pursuant to a written compensatory plan or contract is eligible to resell these shares 90 days after the effective date of this offering in reliance upon Rule 144, but without compliance with specific restrictions. Rule 701 provides that affiliates may sell their Rule 701 shares under Rule 144 without complying with the holding period requirement and that non-affiliates may sell their shares in reliance on Rule 144 without complying with the holding period, public information, volume limitation, or notice provisions of Rule 144.

Registration Rights

We entered into a registration rights agreement in connection with our private placement of common stock in July 2006. Pursuant to the registration rights agreement, we agreed, at our expense, to file with the SEC no later than 120 days following the closing of the private placement two shelf registration statements, one for the placement agent and its affiliates that purchased our common stock in the private placement and one for other purchasers in the private placement, collectively relating to 12,400,000 shares of common stock registering for resale the shares of our common stock sold in the private placement, plus any additional shares of common stock issued in respect thereof whether by stock dividend, stock split or otherwise.

We have filed the two shelf registration statements to satisfy our obligations under the registration rights agreement and anticipate that they will become effective contemporaneously with or immediately following this offering. Accordingly, all these shares, subject to the 60-day lockup period described below, and affiliate restrictions will be freely tradeable without restriction. As a penalty for the registration statements not being declared effective by February 7, 2007, T. Scott Martin, our Chief Executive Officer, and James R. Casperson, our Chief Financial Officer, forfeited bonuses of $300,000 and $155,000 respectively.

We will use our commercially reasonable efforts to cause the registration statements to become effective under the Securities Act as soon as practicable, subject to certain exceptions described below, to maintain continuously the effectiveness of the shelf registration statements under the Securities Act until the first to occur of:

•: the sale, transfer or other disposition of all of the shares of common stock covered by the shelf registration statement or pursuant to Rule 144 under the Securities Act;
•: such time as all of the shares of our common stock sold in this offering and covered by the shelf registration statement and not held by affiliates of us are, in the opinion of our counsel, eligible for sale pursuant to Rule 144(d) (or any successor or analogous rule) under the Securities Act; or
•: the shares have been sold to us or any of our subsidiaries.

Additionally, all holders of our common stock sold in our private placement and the other existing beneficial holders of our common stock, including members of our management, and each of their respective direct and indirect transferees, may elect to participate in this offering to resell their shares, subject to:

•: compliance with the registration rights agreement;
•: cutback rights on the part of the underwriters; and
•: other conditions and limitations that may be imposed by the underwriters.

Lock-Up Period (144A)

Upon completion of this offering, sales, offers to sell, option grants or other transfers of our common stock or any securities convertible into or exchangeable or exercisable for shares of common stock (or other transaction designed to directly or indirectly transfer any of the economic consequences of ownership of our equity securities including by shorting our equity securities or securities convertible into or exchangeable or exercisable for shares of our common stock) by beneficiaries of the registration rights agreement will not be permitted (other than to donees or partners of a stockholder that agree to be similarly bound) for 60 days following the effective date of the registration statement filed in connection with this offering. Notwithstanding the foregoing, beneficiaries of the registration rights agreement may purchase shares of our common stock in our initial public offering or on a public exchange or quotation system after they are publicly traded on a public exchange or quotation system and they may resell such purchased shares on a public exchange or quotation system.

The 60-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 60-day restricted period the company issues an earnings release or announces material news or a material event; or (2) prior to the expiration of the 60-day restricted period, the company announces that it will release earnings results during the 15-day period following the last day of the 60-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

In addition, beneficiaries of the registration rights agreement will have limited piggyback registration rights with respect to other registration statements that we may file. If we file a registration statement for an underwritten offering of securities or, at the time of a filing by us, the resale shelf is not yet effective or their shares were not and will not be included on such resale shelf, the beneficiaries of the registration rights agreement may include their shares on such registration statement, although the beneficiaries' rights will be subject to limitations similar to the rights they may be subject to in an initial public offering.

Notwithstanding the foregoing, we will be permitted, under limited circumstances, to suspend the use, from time to time, of the prospectus that is part of the shelf registration statements (and therefore suspend sales under the registration statements) for certain periods, referred to as "blackout periods," if, among other things, any of the following occurs:

•: the representative of the underwriters of an underwritten offering of primary shares by us has advised us that the sale of shares of our common stock under the shelf registration statements would have a material adverse effect on our initial public offering (in which case the blackout period cannot be more than 45 days or, in the case of the initial public offering, 60 days);
•: a majority of our board of directors, in good faith, determines that (1) the offer or sale, of any shares of our common stock would materially impede, delay or interfere with any proposed financing, offer or sale of securities, acquisition, merger, tender-offer, business combination, corporate reorganization, consolidation or other significant transaction involving us, (2) upon the advice of counsel, the sale of the shares covered by the shelf registration statements would require disclosure of non-public material information not otherwise required to be disclosed under applicable law, and (3) either (x) we have a bona fide business purposes for preserving the confidentiality of the proposed transaction, (y) disclosure would have a material adverse effect on us or our ability to consummate the proposed transaction, or (z) the proposed transaction renders us unable to comply with SEC requirements, in each case under circumstances that would make it impractical or inadvisable to cause the registration statements (or such filings) to become effective or to promptly amend or supplement the registration statements on a post-effective basis, as applicable; or

•: a majority of our board of directors, in good faith, determines, that we are required by law, rule, regulation or SEC published release or interpretation to supplement the shelf registration statements or file a post-effective amendment to the shelf registration statements to incorporate information into the shelf registration statements for the purpose of (1) including in the shelf registration statements any prospectus required under Section 10(a)(3) of the Securities Act, (2) reflecting in the prospectus included in the shelf registration statements any facts or events arising after the effective date of the shelf registration statements (or the most recent post-effective amendment) that, individually or in the aggregate, represents a fundamental change in the information set forth in the prospectus, or (3) including in the shelf registration statements any material information with respect to the plan of distribution not disclosed in the shelf registration statements or any material change to such information.

The cumulative blackout periods in any 12-month period commencing on the closing of the private placement may not exceed an aggregate of 90 days and furthermore may not exceed 60 days in any 90-day period, except as a result of a review of any post-effective amendment by the SEC prior to declaring any post-effective amendment to a registration statement effective provided we have used all commercially reasonable efforts to cause such post-effective amendment to be declared effective.

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
FOR NON-UNITED STATES HOLDERS

The following is a summary of the material U.S. federal income and, to a limited extent, estate tax considerations relating to the purchase, ownership and disposition of our common stock by persons that are non-United States holders (as defined below), but does not purport to be a complete analysis of all the potential tax considerations relating thereto. This summary is based upon provisions of the Internal Revenue Code of 1986 as amended (the "Code") and Treasury regulations, administrative rulings and court decisions thereunder now in effect, all of which are subject to change, possibly on a retroactive basis or to different interpretations. This summary deals only with non-United States holders that will hold our common stock as a "capital asset" (generally, property held for investment) and does not address tax considerations applicable to investors that may be subject to special rules under the U.S. federal income tax laws, such as (without limitation):

•: certain United States expatriates;
•: stockholders that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction;
•: stockholders who hold our common stock as a result of a constructive sale;
•: stockholders whose functional currency is not the United States dollar;
•: stockholders who acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;
•: stockholders that are partnerships or entities treated as partnerships for U.S. federal income tax purposes or other pass-through entities or owners thereof;
•: financial institutions;
•: insurance companies;
•: tax-exempt entities;
•: dealers in securities or foreign currencies; and
•: traders in securities that mark-to-market.

Furthermore, this summary does not address all aspects of U.S. federal income and estate taxes and does not deal with foreign, state, local, or other tax considerations that may be relevant to non-United States holders in light of their personal circumstances, such as the alternative minimum tax provisions of the Code.

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holding our common stock, you should consult your tax advisor.

We have not sought any ruling from the Internal Revenue Service (the "IRS") with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS will agree with such statements and conclusions. INVESTORS CONSIDERING THE PURCHASE OF COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES

ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

As used in this discussion, a "non-United States holder" is a beneficial owner of common stock (other than a partnership or entity treated as a partnership for U.S. federal income tax purposes) that for U.S. federal income tax purposes is not:

•: an individual who is a citizen or resident of the United States, including an alien individual who is a lawful permanent resident of the United States or who meets the "substantial presence" test under Section 7701(b) of the Code;
•: a corporation, or other entity taxable as a corporation for U.S. federal income tax purposes, that was created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
•: an estate whose income is subject to U.S. federal income taxation regardless of its source; or
•: a trust (i) if it is subject to the primary supervision of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust or (ii) that has a valid election in effect under applicable United States Treasury Regulations to be treated as a United States person.

Dividends

We do not presently expect to declare or pay any dividends on our common stock in the foreseeable future. However, if we do make distributions on our common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of earnings and profits will constitute a return of capital that is applied against and reduces the non-United States holder's adjusted tax basis in our common stock. Any remaining excess will be treated as gain realized on the sale or other disposition of our common stock and will be treated as described under "Gain on Disposition of Common Stock" below. Any dividend paid to a non-United States holder of common stock ordinarily will be subject to withholding of U.S. federal income tax at a rate of 30%, or such lower rate as may be specified under an applicable income tax treaty. In order to receive a reduced treaty rate, a non-United States holder must provide us with IRS Form W-8BEN (or applicable substitute or successor form) properly certifying eligibility for the reduced rate.

Dividends paid to a non-United States holder that are effectively connected with the conduct of a trade or business by the non-United States holder in the United States (and, if required by an applicable income tax treaty, are attributable to a United States permanent establishment of the non-United States holder) generally will be exempt from the withholding tax described above and instead will be subject to U.S. federal income tax on a net income basis at the regular graduated U.S. federal income tax rates in the same manner as if the non-United States holder were a United States person as defined under the Code. In such cases, we will not have to withhold U.S. federal income tax if the non-United States holder complies with applicable certification and disclosure requirements. In order to obtain this exemption from withholding tax, a non-United States holder must provide us with an IRS Form W-8ECI (or applicable substitute or successor form) properly certifying eligibility for such exemption. Any such effectively connected dividends received by a foreign corporation may be subject to an additional branch profits tax at a rate of 30% or such lower rate as may be specified by an applicable tax treaty.

Gain on Disposition of Common Stock

Any gain realized on the disposition of our common stock by a non-United States holder generally will not be subject to U.S. federal income tax unless:

•: the gain is effectively connected with the conduct of a trade or business by the non-United States holder in the United States (and, if required by an applicable income tax treaty, is attributable to a United States permanent establishment of the non-United States holder);
•: the non-United States holder is an individual who is present in the United States for 183 days or more in the taxable year of that disposition, and certain other conditions are met; or
•: we are or have been a "United States real property holding corporation," or USRPHC for U.S. federal income tax purposes.

An individual non-United States holder who has gain that is described in the first bullet point immediately above will be subject to tax on the net gain derived from the disposition under regular graduated U.S. federal income tax rates. If a non-United States holder that is a foreign corporation has gain described under the first bullet point immediately above, it generally will be subject to tax on its net gain in the same manner as if it were a United States person as defined under the Code and, in addition, may be subject to the branch profits tax equal to 30% of its effectively connected earnings and profits or at such lower rate as may be specified by an applicable income tax treaty.

An individual non-United States holder who meets the requirements described in the second bullet point immediately above will be subject to a flat 30% tax on the gain derived from the disposition, which may be offset by United States source capital losses, even though the individual is not considered a resident of the United States.

As to the third bullet point, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. So long as our common stock is "regularly traded on an established securities market," a non-United States holder will be taxable on gain recognized on the disposition of our common stock only if the non-United States holder actually or constructively holds or held more than 5% of such common stock at any time during the five-year period ending on the date of disposition or, if shorter, the non-United States holder's holding period for our common stock. If our common stock were not considered to be "regularly traded on an established securities market," all non-United States holders would be subject to U.S. federal income tax on a disposition of our common stock.

Non-United States holders should consult their own tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

Federal Estate Taxes

If you are an individual, common stock owned or treated as being owned by you at the time of your death will be included in your gross estate for U.S. federal estate tax purposes and may be subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.

Information Reporting and Backup Withholding

We must report annually to the IRS and to each non-United States holder the amount of dividends paid to such holder and the tax withheld with respect to such dividends, regardless of whether withholding was required. Copies of the information returns reporting such dividends and withholding may also be made available to the tax authorities in the country in which the non-United States holder resides under the provisions of an applicable income tax treaty.

A non-United States holder will be subject to backup withholding for dividends paid to such holder unless such holder certifies under penalty of perjury that it is a non-United States holder, and the payor does not have actual knowledge or reason to know that such holder is a United States person as defined under the Code, or such holder otherwise establishes an exemption.

Information reporting and, depending on the circumstances, backup withholding will apply to the proceeds of a sale of our common stock within the United States or conducted through certain United States-related financial intermediaries, unless the beneficial owner certifies under penalty of perjury that it is a non-United States holder (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person as defined under the Code) or such owner otherwise establishes an exemption.

Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-United States holder's U.S. federal income tax liability provided the required information is furnished to the IRS.

UNDERWRITING

Subject to the terms and conditions of the underwriting agreement between us, the selling stockholders and the underwriters, the underwriters have agreed severally to purchase from us the following number of common shares at the offering price less the underwriting discount set forth on the cover page of this prospectus.

Underwriter			Number of Shares
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Raymond James & Associates, Inc.
KeyBanc Capital Markets, a division of McDonald Investments, Inc.
Tudor, Pickering, Holt & Co. Securities, Inc.
Howard Weil Incorporated
Tristone Capital Co.
Thomas Weisel Partners LLC

	Total

The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions and that the underwriters will purchase all such common shares if any of the common shares are purchased. The underwriters are obligated to take and pay for all of the common shares offered by this prospectus, other than those covered by the over-allotment option described below, if any are taken.

The underwriters have advised us that they propose to offer the common shares to the public at the offering price set forth on the cover page of this prospectus and to certain dealers at such price less a concession not in excess of $ per share. The underwriters may allow, and such dealers may re-allow, a concession not in excess of $ per share to certain other dealers. After the offering, the offering price and other selling terms may be changed by the underwriters, but any such changes will not affect the net proceeds to be received by us in the offering.

Option to Purchase Additional Shares. Pursuant to the underwriting agreement, we have granted to the underwriters an option, exercisable in whole or in part for 30 days after the date of this prospectus, to purchase up to 1,704,478 additional shares from us at the offering price, less the underwriting discount set forth on the cover page of this prospectus, solely to cover over-allotments.

To the extent the underwriters exercise such an option, the underwriters will become obligated, subject to certain conditions, to purchase approximately the same percentage of such additional shares as the number set forth next to such underwriters' name in the preceding table bears to the total number of shares in the table, and we will be obligated, pursuant to the option, to sell such shares to the underwriters.

Lock-up Agreements. We and our directors and executive officers, as well as Yorktown Energy Partners V, L.P. and Yorktown Energy Partners VI, L.P., as affiliates of two of our directors, have agreed that during the 180 days after the date of this prospectus, we and they will not, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc., directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common shares, any securities convertible into, or exercisable or exchangeable for, common shares or any other rights to acquire such common shares within the time period of the lock-up, other than (1) pursuant to employee benefit plans as in existence as of the date of this prospectus, (2) to affiliates, (3) in connection with accretive acquisitions of assets or businesses in which common shares are issued as consideration, or (4) over-allotment option;

provided, however, any such recipient of common shares will furnish to Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc. a letter agreeing to be bound by these provisions for the remainder of the 180-day period. Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc. may, in their sole discretion, allow any of these parties to offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common shares, any securities convertible into, or exercisable or exchangeable for, common shares or any other rights to acquire such common shares prior to the expiration of such 180-day period in whole or in part at anytime without notice. Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc. have informed us that in the event that consent to a waiver of these restrictions is requested by us or any other person, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc., in deciding whether to grant its consent, will consider the stockholders' reasons for requesting the release, the number of shares for which the release is being requested and market conditions at the time of the request for such release. However, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc. have informed us that as of the date of this prospectus there are no agreements between Merrill Lynch, Pierce, Fenner & Smith Incorporated and Raymond James & Associates, Inc. and any party that would allow such party to transfer any shares, nor do they have any intention of releasing any of the common shares subject to the lock-up agreements prior to the expiration of the lock-up period at this time.

The 180-day restricted period described above is subject to extension such that, in the event that either (1) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event related to us occurs or (2) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, the "lock-up" restrictions described above will continue to apply until the expiration of the 18-day period beginning on the earnings release or the occurrence of the material news or material event.

The holders of shares of our common stock that are beneficiaries of the registration rights agreement, including the selling stockholders, will not be able to sell any shares owned by them for a period of 60 days following the effective date of the registration statement, of which this prospectus is a part, subject to extensions similar to those for the 180-day restricted period noted above.

IPO Pricing. Prior to this offering, there has been no public market for the common shares. The initial public offering price was determined by negotiation between us and the underwriters. The principal factors considered in determining the public offering price include the following:

•: the information set forth in this prospectus and otherwise available to the underwriters;
•: market conditions for initial public offerings;
•: the history and the prospects for the industry in which we compete;
•: the ability of our management;
•: our prospects for future earnings;
•: the present state of our development and our current financial condition;
•: the general condition of the securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded common shares of generally comparable entities.

Discounts and Commissions. The following table summarizes the discounts that we will pay to the underwriters in connection with the offering. These amounts assume both no exercise and full exercise of the underwriters' option to purchase additional common shares.

	Per Share	Without Option	With Option
Public offering price	$	$	$
Underwriting discount	$	$	$
Proceeds, before expenses, to us	$	$	$
Proceeds, before expenses, to the selling stockholders	$	$	$

We expect that total expenses of this offering, other than underwriting discounts and commissions, will be approximately $2 million.

Indemnification. We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments that may be required with respect to these liabilities.

Stabilization. Until the distribution of the common stock is completed, rules of the SEC may limit the ability of the underwriters and certain selling group members to bid for and purchase the common shares. As an exception to these rules, the underwriters are permitted to engage in certain transactions that stabilize, maintain or otherwise affect the price of the common shares.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate-covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: Over-allotment transactions involve sales by the underwriters of the common shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common shares in the open market.
•: Syndicate-covering transactions involve purchases of the common shares in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common shares to close out the short position, the underwriters will consider, among other things, the price of common shares available for purchase in the open market as compared to the price at which they may purchase common shares through the over-allotment option. If the underwriters sell more common shares than could be covered by the over-allotment option, resulting in a naked short position, the position can only be closed out by buying common shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in the offering.
•: Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common shares originally sold by the syndicate member are purchased in a stabilizing or syndicate-covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common shares or preventing or retarding a decline in the market price of the common shares. As a result, the price of the common shares may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the Nasdaq Global Market or otherwise.

The underwriters will deliver a prospectus to all purchasers of common shares in the short sales. The purchasers of common shares in short sales are entitled to the same remedies under the federal securities laws as any other purchaser of common shares covered by this prospectus.

The underwriters are not obligated to engage in any of the transactions described above. If they do engage in any of these transactions, they may discontinue them at any time.

Directed Share Program. At our request, the underwriters have reserved up to 400,000 shares for sale to certain of our employees, directors, families of employees and directors, business associates and other third parties at the initial public offering price through a directed share program. We do not know if our employees, directors, families of employees and directors, business associates and other third parties will choose to purchase all or any portion of the reserved shares, but any purchases they do make will reduce the number of shares available to the general public. If all of these reserved shares are not purchased, the underwriters will offer the remainder to the general public on the same terms as the other shares offered by this prospectus.

No sales to accounts over which any underwriter exercises discretionary authority may be made without the prior written approval of the customer.

Electronic Prospectuses. A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters participating in this offering. Other than the prospectus in electronic format, the information on any such website, or accessible through any such website, is not part of this prospectus.

Conflicts/Affiliates Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us. They have received customary fees and commissions for these transactions.

Because an affiliate of KeyBanc Capital Markets Inc. is a lender under our credit facility and will receive more than 10% of the net proceeds of this offering when we repay our credit facility in full, KeyBanc Capital Markets Inc. may be deemed to have a "conflict of interest" with us under Financial Industry Regulatory Authority, Inc., or FINRA, Conduct Rule 2710(h)(1). When a FINRA member with a conflict of interest participates as an underwriter in a public offering, that rule requires that the initial public offering price be no higher than that recommended by a "qualified independent underwriter," as defined by the FINRA. In accordance with this rule, Merrill Lynch, Pierce, Fenner & Smith Incorporated has assumed the responsibilities of acting as a qualified independent underwriter. In its role as qualified independent underwriter, Merrill Lynch, Pierce, Fenner & Smith Incorporated has performed a due diligence investigation and participated in the preparation of this prospectus and the registration statement of which this prospectus is a part. Merrill Lynch, Pierce, Fenner & Smith Incorporated will not receive any additional fees for serving as qualified independent underwriter in connection with this offering. We have agreed to indemnify Merrill Lynch, Pierce, Fenner & Smith Incorporated against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

100

LEGAL MATTERS

The validity of the shares offered hereby and certain other legal matters in connection with this offering will be passed upon for us by Thompson & Knight LLP, Houston, Texas. Certain legal matters in connection with the shares of common stock offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of Ellora Energy Inc. as of December 31, 2006 and 2007, and for each of the three years in the period ended December 31, 2007 included in this prospectus have been audited by Hein & Associates LLP, independent registered public accountants, as stated in their report appearing in this registration statement, and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on our estimates of the proved reserves and present values of proved reserves as of March 31, 2008 prepared by Ryder Scott Company, L.P., independent petroleum engineers. The summary pages of their report in respect of our reserves as of March 31, 2008 are included in this prospectus as Appendix "A." These estimates are included in this prospectus in reliance upon the authority of Ryder Scott as experts in these matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC, under the Securities Act, a registration statement on Form S-1 with respect to the common stock offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected without charge at the public reference facilities of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of all or any portion of the registration statement may also be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements, and other information that is filed electronically with the SEC. The web site can be accessed atwww.sec.gov.

After effectiveness of the registration statement, which includes this prospectus, we will be required to comply with the requirements of the Exchange Act, and, accordingly, will file current reports on Form 8-K, quarterly reports on Form 10-Q, annual reports on Form 10-K, and other information with the SEC. Those reports and other information will be available for inspection and copying at the public reference facilities and internet site of the SEC referred to above.

101

GLOSSARY OF SELECTED OIL AND GAS TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this prospectus.

3-D seismic. (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or gas.

Development well. A well drilled within the proved boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Dry hole costs. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

Exploitation. Ordinarily considered to be a form of development within a known reservoir.

Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Farmout. An agreement whereby the owner of a leasehold or working interest agrees to assign an interest in certain specific acreage to the assignees, retaining an interest such as an overriding royalty interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and development costs. Capital costs incurred in the acquisition, exploration, development and revisions of proved oil and gas reserves divided by proved reserve additions.

Fracing or Fracture stimulation technology. The technique of improving a well's production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or gases may more easily flow through the formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

102

Injection well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas. The energy value of natural gas is approximately 1.031 MMBtu at standard temperature and pressure for dry natural gas and approximately 1.103 MMBtu per Mcf at standard temperature and pressure for rich natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

MMBbls. Million barrels of oil or other liquid hydrocarbons.

MMBtu. Million British thermal units. The energy value of natural gas is approximately 1.031 MMBtu at standard temperature and pressure for dry natural gas and approximately 1.103 MMBtu per Mcf at standard temperature and pressure for rich natural gas.

MMcf. Million cubic feet of gas.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Multilateral drilling. A method of drilling whereby a well has more than one branch radiating from the main wellbore.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

NYMEX. New York Mercantile Exchange.

Open hole. Uncased portion of a well.

Open-hole completion. A method of preparing a well for production in which no production casing or liner is set opposite the producing formation. Reservoir fluids flow unrestricted into the open wellbore. An open-hole completion has limited use in rather special situations.

PV-10 or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission's practice, to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

103

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed non-producing reserves. Proved reserves that are shut-in reserves or behind-pipe reserves. Shut-in reserves are reserves expected to be recovered from completion intervals which are open at the time of the estimate, but which have not started producing, wells which were shut-in for market conditions or pipeline connections, or wells not capable of production for mechanical reasons. Behind-pipe reserves are reserves expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to the start of production.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, gas and gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reserve life index. This index is calculated by dividing period-end reserves by the average production during the period (annualized) to estimate the number of years of remaining production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.

Tcf. Trillion cubic feet of gas.

Tcfe. Trillion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Underbalanced drilling. Drilling under conditions where the pressure being exerted inside the wellbore (from the drilling fluids) is less than the pressure of the oil or gas in the formation.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

Waterflooding. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

/d. "Per day" when used with volumetric units or dollars.

104

ELLORA ENERGY INC.
Index To Financial Statements

Annual Financial Statements
	Report of Independent Registered Public Accounting Firm	F-2
	Balance Sheets—December 31, 2006 (consolidated) and 2007 (consolidated)	F-3
	Statements of Income—For the Years Ended December 31, 2005 (combined), 2006 (consolidated) and 2007 (consolidated)	F-4
	Statements of Comprehensive Income—For the Years Ended December 31, 2005 (combined), 2006 (consolidated) and 2007 (consolidated)	F-5
	Statements of Stockholders' Equity and Comprehensive Income—For the Years Ended December 31, 2005 (combined), 2006 (consolidated) and 2007 (consolidated)	F-6
	Statements of Cash Flows—For the Years Ended December 31, 2005 (combined), 2006 (consolidated) and 2007 (consolidated)	F-7
	Notes to Financial Statements	F-8
Interim Financial Statements
	Balance Sheets—December 31, 2007 (consolidated) and March 31, 2008 (consolidated) (unaudited)	F-29
	Statements of Income—For the Three Months Ended March 31, 2007 (consolidated) (unaudited) and 2008 (consolidated) (unaudited)	F-30
	Statements of Comprehensive Income (Loss)—For the Three Months Ended March 31, 2007 (consolidated) (unaudited) and 2008 (consolidated) (unaudited)	F-31
	Statements of Stockholders' Equity and Comprehensive Income—For the Three Months Ended March 31, 2008 (consolidated) (unaudited)	F-32
	Statements of Cash Flows—For the Three Months Ended March 31, 2007 (consolidated) (unaudited) and 2008 (consolidated) (unaudited)	F-33
	Notes to Condensed Unaudited Consolidated Financial Statements	F-34

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors
Ellora Energy Inc.
Boulder, Colorado

We have audited the consolidated balance sheets of Ellora Energy Inc. and affiliated entities as of December 31, 2007 and 2006, and the related statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ellora Energy Inc. and affiliated entities as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 6 to the accompanying consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R),Share-Based Payment.

HEIN & ASSOCIATES LLP
Denver, Colorado

March 19, 2008

F-2

ELLORA ENERGY INC. AND SUBSIDIARIES
BALANCE SHEETS

				December 31,
				2006 Consolidated			2007 Consolidated
*ASSETS*
CURRENT ASSETS:
	Cash			$	4,329,000		$	4,651,000
	Accounts receivable:
		Oil and gas sales			6,057,000			9,529,000
		Joint interest billings			615,000			676,000
	Derivative asset				388,000			797,000
	Oil and gas equipment inventory				1,046,000			705,000
	Prepaids and other current assets				1,723,000			2,662,000

			Total current assets		14,158,000			19,020,000

PROPERTY AND EQUIPMENT:
	Oil and gas properties, successful efforts method:
		Proved properties			194,899,000			299,847,000
		Unproved properties			33,456,000			47,154,000
	Pipeline properties				12,266,000			19,667,000
	Furniture and equipment				1,829,000			5,959,000

			Total property and equipment		242,450,000			372,627,000
	Less accumulated depletion and depreciation				(26,211,000	)		(46,623,000	)

			Net property and equipment		216,239,000			326,004,000
OTHER LONG-TERM ASSETS					1,516,000			854,000

TOTAL ASSETS				$	231,913,000		$	345,878,000

*LIABILITIES AND STOCKHOLDERS' EQUITY*
CURRENT LIABILITIES:
	Accounts payable			$	9,407,000		$	20,772,000
	Accrued expenses				291,000			384,000
	Production taxes payable				396,000			283,000
	Oil and gas revenues payable				4,984,000			5,565,000
	Derivative liability				—			831,000

			Total current liabilities		15,078,000			27,835,000
LONG-TERM DEBT					16,000,000			110,000,000
DEFERRED INCOME TAXES, NET					23,347,000			24,677,000
ASSET RETIREMENT OBLIGATIONS					1,322,000			2,172,000
COMMITMENTS (Note 10)
STOCKHOLDERS' EQUITY:
	Ellora Energy Inc. preferred stock, $.001 par value, 10,000,000 shares authorized, -0- outstanding				—			—
	Ellora Energy Inc. common stock, $.001 par value, 125,000,000 shares authorized, 44,807,697 and 45,277,220 issued and outstanding, respectively				45,000			45,000
	Additional paid-in capital				144,923,000			147,120,000
	Retained earnings				31,029,000			34,052,000
	Accumulated other comprehensive income (loss)				169,000			(23,000	)

			Total stockholders' equity		176,166,000			181,194,000

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY				$	231,913,000		$	345,878,000

See accompanying notes to these consolidated financial statements.

F-3

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF INCOME

			For the Years Ended December 31,
			2005 Combined			2006 Consolidated		2007 Consolidated
REVENUE:
	Oil and gas sales		$	47,595,000		$	52,050,000	$	71,138,000
	Gas aggregation and pipeline sales			5,586,000			4,506,000		11,018,000
	(Loss) gain on oil and gas hedging activities			(115,000	)		6,077,000		(1,381,000	)
	Loss on sale of unproved oil and gas properties			—			—		(20,000	)
	Interest income and other			16,000			55,000		98,000

		Total revenue		53,082,000			62,688,000		80,853,000

COSTS AND EXPENSES:
	Lease operating expense			6,141,000			10,091,000		14,200,000
	Production taxes			1,813,000			1,973,000		2,467,000
	Gas aggregation and pipeline cost of sales			4,020,000			5,247,000		11,009,000
	Depreciation, depletion and amortization			8,189,000			11,770,000		20,883,000
	Exploration			422,000			3,441,000		4,016,000
	General and administrative (including $4,857,000, $1,380,000, and $2,092,000 of stock compensation for the years ended December 31, 2005, 2006, and 2007)			11,766,000			11,889,000		18,381,000
	Interest expense			716,000			1,642,000		5,042,000

		Total costs and expenses		33,067,000			46,053,000		75,998,000

INCOME BEFORE TAXES				20,015,000			16,635,000		4,855,000
INCOME TAXES:
	Current income tax expense			692,000			—		—
	Deferred income tax expense			8,542,000			6,424,000		1,832,000

		Total income tax expense		9,234,000			6,424,000		1,832,000

NET INCOME			$	10,781,000		$	10,211,000	$	3,023,000

BASIC INCOME PER SHARE			$	.28		$	.23	$	.07

DILUTED INCOME PER SHARE			$	.27		$	.23	$	.07

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC				38,753,063			43,485,783		44,976,810

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—DILUTED				40,209,654			45,339,821		45,754,270

See accompanying notes to these consolidated financial statements.

F-4

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF COMPREHENSIVE INCOME

		For the Years Ended December 31,
		2005 Combined		2006 Consolidated			2007 Consolidated
NET INCOME		$	10,781,000	$	10,211,000		$	3,023,000
OTHER COMPREHENSIVE INCOME (LOSS):
	Change in derivative instrument fair value, net of tax		24,000		(53,000	)		(192,000	)

COMPREHENSIVE INCOME		$	10,805,000	$	10,158,000		$	2,831,000

See accompanying notes to these consolidated financial statements.

F-5

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2005 (COMBINED), 2006 (CONSOLIDATED), AND 2007 (CONSOLIDATED)

		Common Stock										Accumulated Other Comprehensive Loss
		Common Stock			Additional Paid-In Capital		Subscription Receivable			Retained Earnings
		Shares	Amount		Additional Paid-In Capital		Subscription Receivable			Retained Earnings					Total
BALANCES, January 1, 2005		28,699,966	$	29,000	$	46,142,000	$	(4,649,000	)	$	10,037,000	$	198,000		$	51,757,000
	Sale of stock	12,994,879		13,000		64,237,000		—			—		—			64,250,000
	Stock issued for notes	612,860		—		1,265,000		(1,265,000	)		—		—			—
	Accrued interest on notes	—		—		310,000		(310,000	)		—		—			—
	Non-cash compensation	—		—		4,857,000		—			—		—			4,857,000
	Net income	—		—		—		—			10,781,000		—			10,781,000
	Change in derivative instrument fair value	—		—		—		—			—		24,000			24,000

BALANCES, December 31, 2005		42,307,705		42,000		116,811,000		(6,224,000	)		20,818,000		222,000			131,669,000
	Sale of stock	2,499,992		3,000		26,531,000		—			—		—			26,534,000
	Accrued interest on notes	—		—		201,000		(201,000	)		—		—			—
	Repayment of subscription receivable	—		—		—		6,425,000			—		—			6,425,000
	Non-cash compensation	—		—		1,380,000		—			—		—			1,380,000
	Net income	—		—		—		—			10,211,000		—			10,211,000
	Change in derivative instrument fair value	—		—		—		—			—		(53,000	)		(53,000	)

BALANCES, December 31, 2006		44,807,697		45,000		144,923,000		—			31,029,000		169,000			176,166,000

	Exercise of stock options	48,477		—		105,000		—			—		—			105,000
	Issuance of common stock to directors for services	30,667		—		368,000		—			—		—			368,000
	Issuance of restricted common stock to employees for services	390,379		—		475,000		—			—		—			475,000
	Other non-cash compensation	—		—		1,249,000		—			—		—			1,249,000
	Net income	—		—		—		—			3,023,000		—			3,023,000
	Change in derivative instrument fair value	—		—		—		—			—		(192,000	)		(192,000	)

BALANCES, December 31, 2007		45,277,220	$	45,000	$	147,120,000	$	—		$	34,052,000	$	(23,000	)	$	181,194,000

See accompany notes to these consolidated financial statements.

F-6

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF CASH FLOWS

				For the Years Ended December 31,
				2005 Combined			2006 Consolidated			2007 Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	10,781,000		$	10,211,000		$	3,023,000
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			8,189,000			11,770,000			20,883,000
		Amortization of derivative asset			128,000			2,470,000			604,000
		Amortization of debt issue costs			—			187,000			222,000
		Deferred income taxes			8,542,000			6,424,000			1,832,000
		Exploration			387,000			1,629,000			1,697,000
		Non-cash compensation expense for employees			4,857,000			1,380,000			1,724,000
		Non-cash compensation expense for non employee directors			—			—			368,000
		Loss on sale of unproved oil and gas properties			—			—			20,000
	Changes in operating assets and liabilities:
		Accounts receivable			(7,289,000	)		5,092,000			(3,533,000	)
		Prepaid and other current assets			(2,428,000	)		(1,595,000	)		(5,936,000	)
		Income taxes payable			692,000			—			—
		Other long-term assets			(56,000	)		(837,000	)		440,000
		Accounts payable and accrued expenses			(1,065,000	)		(3,080,000	)		(2,441,000	)
		Oil and gas revenues payable			7,428,000			(4,493,000	)		581,000

			Net cash provided by operating activities		30,166,000			29,158,000			19,484,000

CASH FLOWS FROM INVESTING ACTIVITIES:
	Oil and gas property acquisition				—			—			(27,257,000	)
	Acquisition of Shelby County Properties				(25,795,000	)		—			—
	Acquisition of Presco Western, net of working capital of $285,000				(45,424,000	)		—			—
	Acquisition of Shelby Pipeline, Ltd.				—			—			(6,696,000	)
	Proceeds from sale of oil and gas properties				—			2,602,000			331,000
	Drilling capital expenditures				(32,779,000	)		(51,746,000	)		(73,916,000	)
	Pipeline capital expenditures				(1,717,000	)		(388,000	)		(705,000	)
	Purchase of other property and equipment				(640,000	)		(677,000	)		(4,538,000	)

		Net cash used in investing activities			(106,355,000	)		(50,209,000	)		(112,781,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from sale of Ellora Energy Inc. common stock				64,250,000			26,534,000			—
	Proceeds from repayment of subscription receivable				—			6,425,000			—
	Proceeds from long-term debt under credit agreement				26,750,000			47,940,000			94,000,000
	Principal payments of long-term debt under credit agreement				(11,683,000	)		(57,690,000	)		—
	Loan origination fees				—			(990,000	)		—
	Cash received for exercise of stock options				—			—			105,000
	Cash paid for derivative asset				(2,715,000	)		—			(486,000	)

		Net cash provided by financing activities			76,602,000			22,219,000			93,619,000

INCREASE IN CASH					413,000			1,168,000			322,000
CASH, beginning of year					2,748,000			3,161,000			4,329,000

CASH, end of year				$	3,161,000		$	4,329,000		$	4,651,000

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest			$	702,000		$	1,250,000		$	4,418,000

	Cash paid for taxes			$	—		$	—		$	—

NON CASH INVESTING ACTIVITIES:
	Changes in working capital related to drilling expenditures			$	1,156,000		$	4,150,000		$	12,307,000

	Transfers from inventory to oil and gas properties			$	—		$	2,166,000		$	4,747,000

NON CASH FINANCING ACTIVITIES:
	Stock issued for subscription agreement			$	1,265,000		$	—		$	—

	Accrued interest on subscription notes			$	310,000		$	201,000		$	—

See accompany notes to these consolidated financial statements.

F-7

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Organization—Ellora Energy Inc. was incorporated on June 1, 2002 in the State of Delaware to engage in the acquisition, exploration, development and production of oil and gas properties. During April 2005, Ellora's management established Ellora Oil and Gas Inc. to acquire Presco Western, LLC, which is a party to a farmout agreement in the Hugoton field in Kansas. Subsequently, Presco Western LLC acquired the underlying lease interests and this farmout position. Ellora Oil and Gas Inc. also acquired Ellora Energy Inc.'s assets in Colorado. Ellora Energy Inc. and Ellora Oil and Gas Inc. operated as separate legal entities, but under common management and control until July 2006, when Ellora Energy Inc. and Ellora Oil and Gas Inc. merged with Ellora Energy Inc. as the surviving entity. Together they operate oil and gas properties in Texas, Louisiana, Colorado and Kansas and, when consolidated, have five wholly owned subsidiaries. Ellora Energy Inc., Ellora Oil and Gas Inc. and their respective subsidiaries are collectively referred to herein as "Ellora."

Basis of Presentation of Consolidated and Combined Financial Statements—The accompanying consolidated financial statements as of and for the years ended December 31, 2006 and 2007 include the accounts of Ellora Energy Inc. and its subsidiaries, all of which are wholly owned. All significant intercompany transactions have been eliminated in consolidation. The accompanying combined financial statements as of and for the year ended December 31, 2005 include all accounts of Ellora Energy Inc. and Ellora Oil and Gas Inc. These entities were related due to their common ownership. On July 12, 2006, Ellora completed the private placement of 2,499,992 shares of its common stock pursuant to Rule 144A and Section 4(2) under the Securities Act of 1933, as amended. Immediately prior to the private placement, the shares of Ellora Oil and Gas Inc. were exchanged for shares of Ellora Energy Inc. Each share of Ellora Oil and Gas Inc. was exchanged for 2.499391 shares of Ellora Energy Inc. The exchange factor was determined by the management and approved by the Board of Directors of Ellora Oil and Gas Inc. and Ellora Energy Inc. based upon an analysis of management's estimates of the relative equity value of each of Ellora Oil and Gas Inc. and Ellora Energy Inc. These estimates of equity value were based on an analysis of estimated cash flow and net asset value for both Ellora Energy Inc. and Ellora Oil and Gas Inc. relative to comparable public companies' cash flow, net asset valuations and equity valuations. The shares were then allocated based on each company's respective value. Immediately after the exchange of the shares, all shares of Ellora Energy Inc.'s common stock were split 8.09216-for-1. All shares and earnings per share calculations for all periods in these financial statements have been restated to reflect the effect of the stock split.

Use of Estimates and Certain Significant Estimates—The preparation of Ellora's financial statements in conformity with accounting principles generally accepted in the United States of America requires Ellora's management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates. These estimates include realizability of receivables, selection of the useful lives for property and equipment and timing and costs associated with its retirement obligations. Significant assumptions are also required in the valuation of proved oil and gas reserves, which will affect the depletion calculation and possibly any impairment of oil and gas properties. It is at least reasonably possible those estimates could be revised in the near term and those revisions could be material.

Fair Value of Financial Instruments—Ellora's financial instruments, including cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value

F-8

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

because of the short-term maturity of these instruments. The credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates. Ellora's derivative instruments are marked-to-market with changes in value being recorded in accumulated other comprehensive income.

Cash and Cash Equivalents—Cash equivalents consist of money market accounts and investments which have an original maturity of three months or less. At December 31, 2006 and 2007, the Company maintained cash balances with a commercial bank in excess of FDIC insurance limits.

Oil and Gas Sales Receivable—Oil and gas sales, and aggregation and pipeline revenues are recognized as income when the oil or gas is produced and sold. Monthly, Ellora makes estimates of the amount of production delivered to the purchaser and the price to be received.

Joint Interest Billings Receivable—Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that Ellora operates. The receivable is recognized when the cost is incurred and Ellora's share of the cost is recorded. Most receivables are due within 30 days of receipt. The receivables are reviewed periodically and appropriate actions are taken on past due amounts, if any.

Concentration of Credit Risk—Substantially all of Ellora's receivables are within the oil and gas industry, primarily from the sale of oil and gas products and billings to working interest owners. Collectibility is affected by the general economic conditions of the industry. Most of the receivables are not collateralized and to date, Ellora has had minimal bad debts.

Oil and Gas Equipment Inventory—Oil and gas equipment inventory consists primarily of tubular goods and production equipment, stated at the lower of weighted-average cost or market.

Oil and Gas Producing Operations—Ellora follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, 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. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. During 2005, 2006 and 2007, the Company recorded charges to exploration expense in the amount of $387,000, $1,352,000 and $0, respectively, for exploratory wells that did not find proved reserves. The costs of development wells are capitalized whether productive or nonproductive. Interest cost is capitalized as a component of property cost for capital development projects exceeding $1,000,000 that require greater than six months to be readied for their intended use. For the years ended December 31, 2005, 2006, and 2007, the Company capitalized interest expense of $0, $0, and $310,000, respectively. Costs incurred to maintain wells and related equipment and lease and well operating costs are charged to expense as incurred. Gains and losses arising from sales of properties are included in income. Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment is recorded for unproved properties if the capitalized costs are not considered to be realizable.

Depletion, depreciation and amortization ("DD&A") of capitalized costs of proved oil and gas properties is provided for on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage and Ellora's expected cost to abandon its well interests. DD&A expense

F-9

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

for oil and gas producing property and related equipment was $7,562,000, $10,884,000, and $19,397,000 for the years ended December 31, 2005, 2006 and 2007, respectively.

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," Ellora assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets' net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to "fair value." Fair value for oil and natural gas properties is generally determined based on discounted future net cash flows.

English Bay Pipeline, L.P.—The pipeline aggregates natural gas through the purchase of production from properties in Shelby County, Texas in which Ellora Energy Inc. has an interest and the purchase of gas from other producers and shippers that is delivered through English Bay. The financial information of English Bay is included in Ellora's consolidated financial statements as of and for the years ended December 31, 2006 and 2007 and in the combined financial statements for the year ended December 31, 2005.

The English Bay Pipeline provides gathering services to wells operated by Ellora. For the years ended December 31, 2005, 2006, and 2007, English Bay recorded $1,137,000, $1,113,000, and $910,000, respectively, of gathering income that is eliminated in the consolidation.

Oil and Gas Revenue Payable—Oil and gas revenue payable represents amounts due to third party revenue interest owners for their share of oil and gas revenue collected on their behalf by Ellora. The payable is recorded when Ellora recognizes oil and gas sales and records the related oil and gas sales receivable.

Abandonment Liability—Effective January 1, 2003, Ellora adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires Ellora to recognize the fair value of asset retirement obligations in the financial statements by capitalizing that cost as a part of the cost of the related asset. In regard to Ellora, this Statement applies directly to the plug and abandonment liabilities associated with Ellora's net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to depreciation, depletion and amortization expense. If the obligation is settled for other than the carrying amount, then a gain or loss is recognized on settlement.

Income Taxes—Ellora accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

F-10

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

Revenue Recognition—Ellora recognizes oil and gas revenues for only its ownership percentage of total production under the entitlement method. Purchase, sale and transportation of natural gas are recognized upon completion of the sale, and when transported, volumes are delivered according to the terms of the contract.

Derivative Instruments—Ellora enters into derivative contracts to hedge future natural gas and crude oil production in order to mitigate the risk of market price fluctuations. Ellora does not enter into derivative instruments for speculative trading purposes.

All derivatives are recognized on the balance sheet and measured at fair value. Realized gains and losses as well as the ineffective portion of hedge derivatives, if any, are recorded as a derivative fair value gain or loss in the consolidated statements of income. Unrealized gains and losses on effective cash flow hedge derivatives are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss on the hedge derivative is transferred from accumulated other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivatives are recognized as "gain (loss) on oil and gas hedging activities."

Ellora has formally documented all relationships between hedging instruments and hedged items, as well as the risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument's effectiveness will be assessed.

To designate a derivative as a cash flow hedge, Ellora documents at the hedge's inception its assessment as to whether the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge, if any, is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative's term, Ellora determines the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses on the effective portion of the derivative are reclassified to earnings when the underlying transaction occurs. If it is determined that the designated hedge transaction is not likely to occur, any unrealized gains or losses are recognized immediately in the consolidated statements of income as a derivative fair value gain or loss.

At December 31, 2007, accumulated other comprehensive income consisted of $37,000 ($23,000 after tax) of unrealized loss, representing the mark-to-market value of Ellora's open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2006, accumulated other comprehensive income consisted of $272,000 ($169,000 after tax) of unrealized gains on Ellora's open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2005, accumulated other comprehensive loss consisted of $358,000 ($222,000 after tax) of unrealized gains on Ellora's open commodity contracts, designated as cash flow hedges, as of the balance sheet date.

Per Share Amounts—Basic income per share is computed using the weighted average number of shares outstanding. Diluted income per share reflects the potential dilution that would occur if

F-11

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

stock options were exercised using the average market price for Ellora's stock for the period. Total potential dilutive shares based on options outstanding at December 31, 2007 were 2,542,710.

Ellora's calculation of earnings per share of common stock is as follows:

	2005						2006					2007
	Net Income		Shares	Net Income Per Share			Net Income		Shares	Net Income Per Share		Net Income		Shares	Net Income Per Share
Basic earnings per share	$	10,781,000	38,753,063	$	.28		$	10,211,000	43,485,783	$	.23	$	3,023,000	44,976,810	$	.07
Effect of dilutive shares of common stock from stock options			1,456,591		(.01	)			1,854,038		—			777,460		—

Diluted earnings per share	$	10,781,000	40,209,654	$	.27		$	10,211,000	45,339,821	$	.23	$	3,023,000	45,754,270	$	.07

Prior Year Reclassifications—Certain prior period balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on net income or stockholders' equity previously reported.

Change in Accounting Principle—On December 16, 2004, the Financial Accounting Standards Board ("FASB") published Statement of Financial Accounting Standards No. 123 (Revised 2004), "Share Based Payment" ("SFAS No. 123(R)"). Share based payment transactions within the scope of SFAS No. 123(R) include stock options, restricted stock plans, performance based awards, stock appreciation rights, and employee share purchase plans. This statement supersedes Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25). SFAS No. 123(R) requires a company to measure the grant date fair value of equity awards given to employees in exchange for services and recognize that cost, less estimated forfeitures, over the period that such services are performed. The fair value of stock options is determined using the Black-Scholes valuation model. Ellora adopted SFAS No. 123(R) on January 1, 2006 using the modified prospective transition method.

Prior to adopting SFAS No. 123(R), Ellora followed the provisions of SFAS No. 123, "Accounting for Stock Based Compensation," for all issuances of stock options to non-employees of Ellora. Ellora followed the provisions of APB Opinion No. 25 (Opinion 25), "Accounting for Stock Issued to Employees" for all issuances of stock options to their employees. In accordance with APB 25, prior to January 1, 2006, no compensation cost has been recognized for stock options granted to employees under the 2002 Plan. Under the modified prospective method of adopting SFAS No. 123(R), compensation cost recognized for the years ended December 31, 2006 and 2007 includes compensation cost for all stock option awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value, less estimated forfeitures. In accordance with the modified prospective method, prior period results have not been restated. Refer to further disclosure related to Ellora's adoption of SFAS No. 123(R) in Note 6, "Stockholders' Equity."

In July 2006, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 ("FIN 48"). The interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or

F-12

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition on certain tax positions.

The Company adopted the provisions of FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company's consolidated financial position or results of operations. Subsequent to adoption, there have been no changes to the Company's assessment of uncertain tax positions.

The Company files income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. The Company is in the process of completing its 2006 Federal tax returns. The following is a listing of tax years that remain subject to examination by major jurisdiction:

U.S. Federal		December 31, 2003-December 31, 2005
U.S. States		December 31, 2003-December 31, 2005

The Company's policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the year ended December 31, 2007, the Company did not recognize any interest or penalties in the consolidated statements of income, nor did the Company have any interest or penalties accrued in its consolidated balance sheet at December 31, 2007 relating to unrecognized tax benefits.

New Accounting Pronouncements—In September 2006, the FASB issued FASB No. 157, "Fair Value Measurements." FASB No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. FASB No. 157 is effective for fiscal years beginning after November 15, 2007. While the Company is currently evaluating the impact of FASB No. 157, the Company does not believe the impact will be material to its financial condition or results of operations.

In February 2007, the FASB issued FASB No. 159, "Fair Value Option for Financial Assets and Financial Liabilities. FASB No. 159 permits an entity to irrevocably elect fair value on a contract-by-contract basis as the initial and subsequent measurement attribute for many financial assets and liabilities and certain other items including insurance contracts. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with the item for which the fair value option is elected. FASB No. 159 is effective for fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of FASB No. 157, "Fair Value Measurements." The Company is currently evaluating the impact, if any, of adopting FASB No. 159 on its financial condition or results of operations.

2. ACQUISITIONS AND DIVESTURES:

F-13

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. ACQUISITIONS AND DIVESTURES: (Continued)

gas properties. Revenues and operating income from the developed properties acquired were not significant to the Company's operations for 2007.

On February 22, 2007, English Bay Pipeline, L.P. (a wholly owned subsidiary of Ellora) acquired a 100% interest in the 20 mile long Shelby Pipeline in Shelby County, Texas for approximately $6.7 million in cash. The pipeline transports gas from the southern portion of the Huxley Field for Ellora and other independent producers to an interstate pipeline. In addition, this line was connected to Ellora's English Bay Pipeline during March of 2007.

In December of 2006, the Company sold its interest in non-core producing wells and non-producing acreage in East Texas and Louisiana to a related party at its fair market value of $3 million, less closing adjustments. No gain or loss was recognized on the transaction.

Ellora completed two acquisitions during 2005:

•: On April 29, 2005, Ellora acquired Presco Western, LLC for approximately $45 million in cash. The acquisition was accounted for using the purchase method of accounting and the purchase price was allocated primarily to oil and gas properties and net working capital acquired.
•: On August 31, 2005, Ellora acquired additional interests in existing properties located in Shelby County, Texas from a minority stockholder of Ellora Energy Inc. for approximately $26 million in cash. The acquisition was accounted for using the purchase method of accounting and the purchase price was allocated entirely to oil and gas properties.

The results of operations from the acquisitions are included with our results from the respective acquisition dates noted above. The table below summarizes the allocation of the purchase price for the 2005 transactions based on the acquisition date fair values of the assets acquired and liabilities assumed.

		Presco Western, LLC		Shelby County
Allocation of Purchase Price:
Working capital (including cash acquired of $285,000)		$	709,000	$	—
Oil and gas properties			44,715,000		25,795,000

	Total	$	45,424,000	$	25,795,000

The following table reflects the unaudited pro forma oil and gas sales, net income and net income per share calculations for the twelve months ended December 31, 2005 as though the Presco Western, LLC and Shelby County acquisitions had occurred on January 1, 2005.

	Pro Forma Ellora (unaudited)
Year ended December 31, 2005:
Total revenues	$	51,789,000
Net income		11,174,000
Net income per share, basic	$	.29
Net income per share, diluted	$	.28

F-14

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. ACQUISITIONS AND DIVESTURES: (Continued)

The pro forma amounts above are presented for informational purposes only and not necessarily indicative of the results that would have occurred had the Presco Western, LLC and Shelby County acquisitions been consummated on January 1, 2005, nor are the pro forma amounts necessarily indicative of the future results of operations of Ellora.

3. FURNITURE AND EQUIPMENT:

At December 31, 2006 and 2007, furniture and equipment consisted of the following:

		2006 Consolidated			2007 Consolidated
Office furniture and equipment		$	206,000		$	2,375,000
Computers			923,000			1,922,000
Leasehold			64,000			570,000
Other			636,000			1,092,000

	Total		1,829,000			5,959,000
Less accumulated depreciation			(851,000	)		(1,287,000	)

	Furniture and equipment, net	$	978,000		$	4,672,000

Total depreciation expense related to furniture and equipment amounted to $224,000, $429,000, and $801,000 for the years ended December 31, 2005, 2006, and 2007, respectively.

4. ASSET RETIREMENT OBLIGATION:

The fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by a corresponding amount of these obligations. Prospectively, the liabilities are accreted for the change in their present value and the initial capitalized costs are depleted, depreciated and amortized over the productive lives of the related assets.

At December 31, 2007, there were no assets legally restricted for purposes of settling asset retirement obligations. The following is a reconciliation of Ellora's asset retirement obligations as of December 31:

	2006 Consolidated		2007 Consolidated
Beginning of year	$	716,000	$	1,322,000
Additional liabilities incurred		134,000		540,000
Accretion expense		57,000		106,000
Revisions to estimate		415,000		204,000

End of year	$	1,322,000	$	2,172,000

F-15

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. LONG-TERM DEBT:

Notes payable consisted of the following at December 31, 2006 and 2007:

		December 31, 2006 Consolidated			December 31, 2007 Consolidated
Credit Agreement.		$	16,000,000		$	110,000,000

On February 3, 2006, Ellora entered into a $400,000,000 credit agreement with an initial borrowing base of $110,000,000 with a syndicate of banks led by JP Morgan Chase Bank, N.A. The borrowing base was raised to $150,000,000 on November 2, 2007. Commitment fees of 0.30% to 0.50% accrue on the unused portion of the borrowing base, depending on the utilization percentage, and are included as a component of interest expense. For the year ended December 31, 2007, the weighted average interest rate on the entire outstanding principal balance was 6.68% and the effective interest rate as of December 31, 2007 was 6.85%. Interest accrues at either (1) the base rate plus a margin where the base rate is defined as the higher of the prime rate or the federal funds rate plus a margin varying from 0% to 0.75% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.25% to 2.00% depending on the utilization percentage of the borrowing base. Ellora has consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. The loan is collateralized by Ellora's oil and gas properties and includes certain financial covenants, for which Ellora was in compliance for the years ended December 31, 2006 and 2007.

The credit agreement provides for interest only payments until February 3, 2010, when the entire amount borrowed is due. Ellora may, throughout the term of the credit agreement, borrow, repay and reborrow up to the borrowing base in effect from time to time.

6. STOCKHOLDERS' EQUITY:

Preferred Stock—Ellora Energy Inc. has 10,000,000 shares of $.001 par value preferred stock authorized, none issued. The preferred stock may be issued in such series and preferences as determined by Ellora Energy Inc.'s board of directors.

Issuance of Common Stock—During April 2005, Ellora Oil and Gas Inc. issued 12,994,879 shares of common stock for $64,250,000.

Subscription Agreements—For shares of common stock sold and issued to employees, Ellora Energy Inc. financed the sale of those shares and entered into full recourse promissory notes that were collateralized by Ellora Energy Inc.'s stock. The promissory notes have been reflected as a reduction of stockholders' equity and were due June 2009, with an interest rate of 6%. Interest of $928,000 on these subscriptions has been recorded as a reduction to stockholders' equity and an addition to additional paid-in capital through July 11, 2006. On July 12, 2006, Ellora completed the private placement of 2,499,992 shares of common stock pursuant to Rule 144A and Section 4(2) under the Securities Act of 1933, as amended for $26,534,000. Also, in connection with this offering, Ellora received approximately $6,425,000, including $928,000 of accrued interest, from certain of the selling stockholders for repayment of the subscription agreements.

F-16

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. STOCKHOLDERS' EQUITY: (Continued)

Ellora Oil and Gas Inc. Stock Option Plan (Converted to the 2006 Ellora Energy Inc. Stock Plan) —Ellora Oil and Gas Inc. adopted the 2005 Stock Option Plan for employees and non-employee directors to receive stock option rewards. Under the 2005 Plan, 82,000 options were outstanding as of December 31, 2005. On July 12, 2006 the options of Ellora Oil and Gas Inc. were exchanged for options of Ellora Energy Inc. Each option of Ellora Oil and Gas Inc. was exchanged for 2.499391 options of Ellora Energy Inc. Immediately after the exchange of the options, the options were split 8.092168039-for-1. Upon completion of the split, the 2005 Stock Option Plan was converted to the Ellora Energy Inc. 2006 Stock Option Plan.

A summary of non-qualified stock option activity for Ellora Oil and Gas Inc. for the three years ended December 31, 2007 is as follows:

		Number of Options		Weighted Average Exercise Price		Weighted Average Fair Value
Outstanding, January 1, 2005		—			—		—
	Granted	1,658,490		$	4.94	$	2.46
	Exercised	—			—		—
	Expired	—			—		—
	Cancelled	—			—		—

Outstanding as of, December 31, 2005		1,658,490			4.94		2.46
	Granted
	Exercised
	Expired
	Cancelled	(72,474	)		4.94		2.46
	Transferred in July 2006	(1,586,016	)		4.94		2.46

Outstanding as of, December 31, 2006 and 2007		—		$	—	$	—

Ellora Energy Inc. Stock Option Plan—Ellora Energy Inc. adopted the 2002 Stock Option Plan (the "2002 Plan") for employees and non-employee directors to receive stock option rewards. Under the 2002 Plan, 130,253 shares were outstanding as of December 31, 2005. On July 12, 2006, the 130,253 options outstanding were split 8.092168039-for-1. All amounts reflected in the accompanying table consider this stock split.

F-17

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. STOCKHOLDERS' EQUITY: (Continued)

A summary of non-qualified stock option activity for Ellora Energy Inc. for the three years ended December 31, 2007 is as follows:

		Number of Options		Weighted Average Exercise Price		Weighted Average Fair Value
Outstanding, January 1, 2005		1,310,810		$	1.71	$	.58
	Granted	—			—		—
	Exercised	—			—		—
	Expired	—			—		—
	Cancelled	(256,781	)		2.47		.94

Outstanding, December 31, 2005		1,054,029			1.53		.50
	Granted
	Exercised	—			—		—
	Expired	—			—		—
	Cancelled	(2,188	)		2.47		.94
	Transferred	1,586,016			4.94		2.46

Outstanding, December 31, 2006		2,637,857			3.58		1.68
	Granted	—			—		—
	Exercised	(48,477	)		4.94		2.46
	Expired	—			—		—
	Cancelled	(46,670	)		4.94		2.46

Outstanding, December 31, 2007		2,542,710		$	3.53	$	1.65

The above options vest as follows:

	Number of Options	Weighted Average Exercise Price		Weighted Average Fair Value
Vested as of December 31, 2007	2,255,620	$	3.49	$	1.61
Vest in 2008	287,090		4.94		2.46

	2,542,710	$	3.53	$	1.65

All options issued and outstanding under the 2002 and 2005 Plans were converted into options issued and outstanding under Ellora's 2006 Plan. If not previously exercised, the Ellora Energy Inc. options outstanding at December 31, 2007, which were issued under the 2002 Plan will expire in 2010. If not previously exercised, the Ellora Energy Inc. options outstanding at December 31, 2007, which were issued under the 2005 Plan will expire in 2012. Total estimated unrecognized compensation cost for the unvested stock options as of December 31, 2007 was approximately $719,000 which is expected to be recognized over a period of .58 years. The intrinsic value of the outstanding and vested shares, based on an estimated intrinsic value of $12.00 per share, less the weighted average exercise price was $8.47 for all options and $8.51 for vested options as of December 31, 2007.

F-18

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. STOCKHOLDERS' EQUITY: (Continued)

For the years ended December 31, 2005, the value of each option granted under the plans was estimated on the date of grant, using the minimum value method described in SFAS No. 123, with the following assumptions:

	2005
Risk-free interest rate		7	%
Expected life		7-10 years
Expected volatility		0	%
Expected dividend	$	0

	2005
Net income—as reported	$	10,781,000
Pro forma expense		(1,344,000	)

Net income—pro forma	$	9,437,000

Basic earnings per share—pro forma	$	.24

Diluted earnings per share—pro forma	$	.23

Ellora Energy Inc. Non-Cash Compensation Expense—In July of 2005, Ellora Energy Inc. sold shares of stock for less than fair value to an officer. Also during July of 2005, Ellora Energy Inc. sold shares of stock for less than fair value to an officer who retired during 2005. In connection with these transactions, Ellora recorded non-cash compensation expense of $4,857,000 in the statements of income with a corresponding credit to additional paid-in capital.

Ellora Energy Inc. Amended and Restated 2006 Stock Incentive Plan—Ellora Energy Inc. adopted the 2006 Stock Incentive Plan for employees and non-employee directors to receive restricted stock. In accordance with the plan, 458,334 shares of restricted stock have been reserved for issuance. On September 10, 2007, 390,379 shares of restricted common stock were issued to employees. All restricted stock grants to date shall vest as to one-third of the underlying shares as of the first, second, and third anniversary dates of the grant as set forth in the Restricted Stock Agreement with such employees.

F-19

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. STOCKHOLDERS' EQUITY: (Continued)

The following table shows a summary of the restricted stock grants as of December 31, 2007:

Date	Number of Shares	Weighted Average Grant Date Fair Value
Outstanding, December 31, 2006	—	$	—
Granted	390,379		12.00
Vested	—		—
Forfeited	—		—

Restricted stock awards, nonvested, December 31, 2007	390,379	$	12.00

The grant date fair value of the restricted stock was determined based on the last executed trade of our stock in the PORTAL market prior to the grant of the restricted stock which was $12.00 per share. Ellora uses historical data to estimate expected employee behaviors related to restricted stock forfeitures. SFAS 123R requires that expected forfeitures be included as part of the grant date estimate of compensation cost.

Stock compensation expense of $475,000 was recorded in 2007 related to the shares. As of December 31, 2007, there was $4,209,000 of total unrecognized compensation cost related to the unvested restricted stock granted under the plan. That cost is expected to be recognized over a period of 2.69 years.

On September 1, 2007, 30,667 shares of Ellora Energy Inc. common stock were issued to certain non-employee and non-Yorktown Energy related members of its Board of Directors in accordance with the Ellora Energy Inc. Amended and Restated 2006 Stock Incentive Plan, based upon a per share price of $12.00. These shares were issued in lieu of cash payments, which would otherwise be payable to the Board members under their compensation arrangement; therefore there were no vesting requirements. Ellora recognized compensation expense in the amount of $368,000 in connection with this issuance, which had previously been accrued.

7. INCOME TAXES:

Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax bases of assets and liabilities and amounts reported in Ellora's balance sheet. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liability determines the periodic provision for deferred taxes. The provision for income taxes consists of the following:

		2005 Combined		2006 Consolidated		2007 Consolidated
Current taxes		$	692,000	$	—	$	—
Deferred taxes			8,542,000		6,846,000		1,832,000

	Total income tax expense	$	9,234,000	$	6,846,000	$	1,832,000

F-20

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. INCOME TAXES: (Continued)

Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred tax liability result from the following components:

		2006 Consolidated			2007 Consolidated
Oil and gas and pipeline properties		$	37,284,000		$	43,213,000
Net operating loss carryforward			(12,170,000	)		(15,712,000	)
AMT credit carryforward			(692,000	)		(692,000	)
Stock compensation			—			(1,164,000	)
Accrued property tax			(152,000	)		—
Abandonment obligations			(509,000	)		(836,000	)
Deferred deductions and other			(414,000	)		(132,000	)

	Total	$	23,347,000		$	24,677,000

At December 31, 2007, Ellora Energy Inc. had net operating loss carryforwards for Federal tax purposes of approximately $40,810,000. Reconciliation of Ellora's effective tax rate to the expected federal tax rate of 35% is as follows:

Ellora is subject to the alternative minimum tax ("AMT") due to accelerated tax depreciation, deductions for intangible drilling costs, and other items of "tax preference." Ellora's net operating loss carryforward for purposes of the AMT aggregate to $16,920,000 at December 31, 2007.

	2005 Combined		2006 Consolidated		2007 Consolidated
Expected Federal tax rate	35	%	35	%	35	%
Permanent difference—stock based compensation	9	%	3	%	—
State income taxes and other	2	%	3	%	2.7	%

Effective tax rate	46	%	41	%	37.7	%

8. COMBINING FINANCIAL INFORMATION:

Presented below is the condensed combining information of Ellora Energy Inc. and Affiliated Entities for the year ended December 31, 2005 (see Note 1). Ellora Energy Inc. provided administrative services to Ellora Oil and Gas Inc. for which Ellora Energy Inc. received overhead reimbursements in the amount of $1,050,000 for the year ended December 31, 2005. The amount earned by Ellora Energy Inc. is included below as a reduction to general and administrative

F-21

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. COMBINING FINANCIAL INFORMATION: (Continued)

expense with a corresponding charge to Ellora Oil and Gas Inc.'s general and administrative expense.

	Condensed Combining Statement of Operations for the Fiscal Year Ended December 31, 2005
	Ellora Energy Inc.		Ellora Oil and Gas Inc.		Elimination			Total
Revenues	$	41,663,000	$	11,419,000	$	—		$	53,082,000
Gain on sale of property		8,400,000		—		(8,400,000	)		—
Operating expenses		8,816,000		3,158,000		—			11,974,000
Depreciation, depletion and amortization		5,846,000		2,343,000		—			8,189,000
Exploration		35,000		387,000		—			422,000
General and administrative and other expenses		11,217,000		1,265,000		—			12,482,000
Income tax expense		8,233,000		1,001,000		—			9,234,000

Net income	$	15,916,000	$	3,265,000	$	(8,400,000	)	$	10,781,000

9. MAJOR CUSTOMERS:

During 2005, Louis Dreyfus Energy Services was the only customer who accounted for greater than 10% of Ellora's oil and gas sales, accounting for approximately 63% of such oil and gas sales for the year ended December 31, 2005. During 2006, Louis Dreyfus Energy Services and Plains Marketing, L.P. accounted for 50% and 21%, respectively, of oil and gas sales. During 2007, Louis Dreyfus Energy Services, Plains Marketing, L.P., Trans Louisiana Gas Pipeline, and Texon L.P, accounted for 36%, 19%, 15%, and 10%, respectively, of oil and gas sales. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

10. COMMITMENTS:

Office Lease—Ellora leases office space with a term through December 31, 2011. Total rental expense was $196,000, $204,000, and $980,000 for the years ended December 31, 2005, 2006, and 2007, respectively. Ellora's obligation for future minimum lease payments under this agreement, a drilling agreement, and an agreement for certain well compressors in East Texas, is as follows:

2008	$	9,964,000
2009		9,701,000
2010		2,336,000
2011		973,000
2012		—

	$	22,974,000

Environmental Issues—Ellora is engaged in oil and gas exploration and production and may incur liability for environmental clean up of well sites or other environmental restoration procedures as

F-22

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS: (Continued)

they relate to the drilling of oil and gas wells and the operation thereof. In Ellora's acquisition of existing or previously drilled well bores, Ellora may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Petroleum hydrocarbons or wastes may have been disposed of or released on or under properties owned or leased by Ellora or on or under other locations where such wastes have been taken for disposal. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon Ellora. Management believes its properties are operated in conformity with local state and Federal regulations. No claim has been made, nor is Ellora aware of any uninsured liability that Ellora may have, as it relates to any environmental clean up, restoration or the violation of any rules or regulations relating thereto.

11. DERIVATIVE FINANCIAL INSTRUMENTS:

Ellora entered into various futures commitments to minimize the effect of oil and natural gas price fluctuations which are summarized in the table below. As of December 31, 2007, Ellora had the following outstanding financial oil and natural gas positions:

Contract Type	Weighted Average Strike Price		Quantity	Contract Period
Futures Swap, Oil	$	77.10	15,000 Bbls/month	January-March 2008
Futures Swap, Gas	$	8.01	100,000 MMBtu/month	January-December 2008
Futures Swap, Gas	$	8.275	100,000 MMBtu/month	January-December 2008

As of December 31, 2007, the above contracts had an unrealized loss, net of deferred tax effect, of $23,000, which is recorded in other comprehensive income.

12. OIL AND GAS ACTIVITIES:

Ellora's oil and natural gas activities are entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows:

		2005 Combined		2006 Consolidated		2007 Consolidated
Unproved property acquisition		$	25,036,000	$	5,675,000	$	17,577,000
Proved property acquisition			46,764,000		—		14,221,000
Development			18,783,000		45,057,000		79,899,000
Exploration			14,993,000		15,553,000		11,468,000

	Total	$	105,576,000	$	66,285,000	$	123,165,000

During 2005, 2006 and 2007, additions to oil and gas properties of approximately $167,000, $134,000, and $540,000 were recorded for the estimated costs of future abandonment related to new wells drilled or acquired.

F-23

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. OIL AND GAS ACTIVITIES: (Continued)

Net capitalized costs related to Ellora's oil and natural gas producing activities are summarized as follows:

		2005 Combined			2006 Consolidated			2007 Consolidated
Proved oil and gas properties		$	135,828,000		$	194,899,000		$	299,847,000
Unproved oil and gas properties			35,768,000			33,456,000			47,154,000
Accumulated depreciation, depletion and amortization			(13,587,000	)		(24,398,000	)		(43,795,000	)

	Oil and gas properties—net	$	158,009,000		$	203,957,000		$	303,206,000

In April 2005, the Financial Account Standards Board ("FASB") issued Staff Position No. FAS 19-1, "Accounting for Suspended Well Costs" ("FSP 19-1"), which amends FAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." During the third quarter of 2005, Ellora adopted the requirements of FSP 19-1. Upon adoption, Ellora evaluated all existing capitalized well costs under the provisions of FSP 19-1 and determined there was no impact to Ellora's consolidated financial statements.

Exploratory wells in progress as of each year end were not significant to the Company's financial statements.

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

The estimate of proved reserves and related valuations for the years ended December 31, 2005, 2006, and 2007 were based upon the report prepared by Ellora's engineering staff and audited by MHA Petroleum Consultants, Inc., independent petroleum engineers. The estimates of proved reserves were made in accordance with Rule 4-10(a) of Regulation S-X. Rule 4-10(a) defines proved oil and gas reserves as the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

F-24

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): (Continued)

All of Ellora's oil and natural gas reserves are attributable to properties within the United States. A summary of Ellora's changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2005, 2006 and 2007, are as follows:

		Natural Gas		Oil
		(MMcf)		(MBbl)
Balance—January 1, 2005		99,433		304
	Extensions and discoveries(1)	40,165		469
	Sales of minerals in place	—		—
	Purchases of minerals in place	22,953		8,033
	Production	(5,348	)	(125	)
	Revisions to previous estimates(2)	(10,359	)	207

Balance—December 31, 2005		146,844		8,888
	Extensions and discoveries(3)	63,385		2,649
	Sales of minerals in place	(1,201	)	(16	)
	Purchases of minerals in place	—		—
	Production	(6,348	)	(218	)
	Revisions to previous estimates(4)	(20,659	)	(5,126	)

Balance—December 31, 2006		182,021		6,177

	Extensions and discoveries(5)	49,931		2,541
	Sales of minerals in place	—		—
	Purchases of minerals in place	1,959		1,688
	Production	(7,459	)	(354	)
	Revisions to previous estimates(6)	(39,616	)	(1,721	)

Balance—December 31, 2007		186,836		8,331

Proved developed reserves:
	December 31, 2005	60,078		776

	December 31, 2006	67,950		934

	December 31, 2007	78,384		2,377

(1): The vast majority of these reserve additions were the result of positive drilling in the James Lime formation in East Texas and the E. Hall area in southwest Kansas.
(2): Water production in the Ellington, Lundy, and RE Davis areas of East Texas caused a reduction in reserves and corresponding offsetting proved undeveloped locations. Unsuccessful drilling of the Shull-10.1 James Lime well resulted in a reduction in reserves for that well and two offset locations.
(3): Following Ellora's acquisition of Presco Western, increased drilling activity in 2006 in southwest Kansas contributed to reserve increases. The 25 successful wells drilled in Kansas in the Morrow and St. Louis formations in the southeastern and southwestern portions of Ellora's acreage added significantly to production and reserves.
(4): Based on production results which were less than originally anticipated in the Fredericksburg formation of East Texas, reserves were reduced on a per well basis from 1.2 to 0.8 billion cubic feet. The reduction of Ellora's oil reserves was a result of production performance that was less than originally anticipated in the southeastern deep Hugoton area.

F-25

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): (Continued)

(5): Positive drilling in East Texas and Kansas resulted in 38 new proved developed producing wells and accounts for approximately one third of the extensions and discoveries. The results of this drilling and additional review and analysis of our Hugoton acreage resulted in reserve additions that comprised the other two-thirds of our extensions and discoveries.
(6): Production performance that was less than originally anticipated accounts for the gas and oil revisions to previous estimates. The gas revision split between East Texas and the deep Hugoton is approximately three-fourths and one-fourth, respectively.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of SFAS No. 69. Future cash inflows were computed by applying prices at year end to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of Ellora's oil and natural gas properties.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):

		2005 Combined			2006 Consolidated			2007 Consolidated
Future cash flows		$	1,609,961		$	1,337,730		$	2,175,974
Future production costs			(415,075	)		(403,856	)		(590,492	)
Future development costs			(113,183	)		(128,213	)		(195,795	)
Future income tax expense			(365,772	)		(257,667	)		(448,180	)

Future net cash flows			715,931			547,994			941,507
10% annual discount for estimated timing of cash flows			(389,749	)		(295,989	)		(482,108	)

	Standardized measure of discounted future net cash flows	$	326,182		$	252,005		$	459,399

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. The effect of hedging transactions in place as of year end on the future cash flows for the years ended December 31, 2005, 2006, and 2007 was immaterial.

F-26

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): (Continued)

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):

	2005 Combined			2006 Consolidated			2007 Consolidated
Beginning of year	$	117,127		$	326,182		$	252,005
Sale of oil and gas produced, net of production costs		(39,641	)		(39,986	)		(54,471	)
Net changes in prices and production costs		62,012			(166,387	)		259,978
Extensions, discoveries and improved recoveries		129,715			155,406			177,768
Development costs incurred		17,325			17,290			29,228
Changes in estimated development cost		(80,502	)		(32,320	)		(16,715	)
Purchases of mineral in place		214,753			—			39,484
Sales of mineral in place		—			(2,543	)		—
Revisions of previous quantity estimates		(24,821	)		(111,748	)		(163,123	)
Net change in income taxes		(105,766	)		48,155			(100,192	)
Accretion of discount		17,801			49,283			37,050
Changes in production rates and other		18,179			8,673			(1,613	)

End of year	$	326,182		$	252,005		$	459,399

Average wellhead prices in effect at December 31, 2005, 2006 and 2007 inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows:

		2005 Combined			2006 Consolidated			2007 Consolidated
Oil (per Bbl)		$	56.50		$	58.36		$	91.97
Gas (per Mcf)		$	8.12		$	6.21		$	7.54

14. SUBSEQUENT EVENT:

Subsequent to December 31, 2007, Ellora entered into various futures commitments to minimize the effect of oil and natural gas price fluctuations which are summarized in the table below:

Contract Type	Weighted Average Strike Price		Quantity	Contract Period
Futures swap, gas	$	8.24	200,000 MMBtu/month	February-December 2008
Futures swap, gas	$	9.04	50,000 MMBtu/month	March-December 2008
Futures swap, gas	$	9.025	50,000 MMBtu/month	March-December 2008
Futures swap, oil	$	100.00	15,000 BBl/month	March-December 2008
Futures swap, oil	$	102.60	5,000 BBl/month	April-December 2008
Futures swap, gas	$	10.20	50,000 MMBtu/month	April-December 2008
Futures swap, oil	$	98.05	10,000 BBl/month	January-December 2009
Futures swap, gas	$	9.50	100,000 MMBtu/month	January-December 2009

F-27

[THIS PAGE INTENTIONALLY LEFT BLANK]

F-28

ELLORA ENERGY INC. AND SUBSIDIARIES
BALANCE SHEETS

				December 31, 2007			March 31, 2008
								(unaudited)
*ASSETS*
CURRENT ASSETS:
	Cash			$	4,651,000		$	10,652,000
	Accounts receivable:
		Oil and gas sales			9,529,000			9,306,000
		Joint interest billings			676,000			1,815,000
	Derivative asset				797,000			432,000
	Oil and gas equipment inventory				705,000			724,000
	Deferred income taxes				10,000			3,295,000
	Prepaids and other current assets				2,662,000			2,664,000

			Total current assets		19,030,000			28,888,000

PROPERTY AND EQUIPMENT:
	Oil and gas properties, successful efforts method:
		Proved properties			299,847,000			320,487,000
		Unproved properties			47,154,000			48,587,000
	Pipeline properties				19,667,000			19,900,000
	Furniture and equipment				5,959,000			6,225,000

			Total property and equipment		372,627,000			395,199,000
	Less accumulated depletion and depreciation				(46,623,000	)		(53,889,000	)

			Net property and equipment		326,004,000			341,310,000
OTHER LONG-TERM ASSETS					854,000			780,000

TOTAL ASSETS				$	345,888,000		$	370,978,000

*LIABILITIES AND STOCKHOLDERS' EQUITY*
CURRENT LIABILITIES:
	Accounts payable			$	20,772,000		$	15,664,000
	Accrued expenses				394,000			657,000
	Production taxes payable				283,000			505,000
	Oil and gas revenues payable				5,565,000			6,128,000
	Derivative liability				831,000			8,991,000

			Total current liabilities		27,845,000			31,945,000
LONG-TERM DEBT					110,000,000			134,000,000
DEFERRED INCOME TAXES					24,677,000			25,054,000
ASSET RETIREMENT OBLIGATIONS					2,172,000			2,271,000
STOCKHOLDERS' EQUITY:
	Ellora Energy Inc. preferred stock, $.001 par value, 10,000,000 shares authorized, -0- issued and outstanding				—			—
	Ellora Energy Inc. common stock, $.001 par value, 125,000,000 shares authorized, 45,277,220 and 45,384,387 issued and outstanding, respectively				45,000			45,000
	Additional paid-in capital				147,120,000			147,811,000
	Retained earnings				34,052,000			35,118,000
	Accumulated other comprehensive income (loss)				(23,000	)		(5,266,000	)

			Total stockholders' equity		181,194,000			177,708,000

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY				$	345,888,000		$	370,978,000

See accompanying notes to these financial statements.

F-29

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF INCOME
(unaudited)

			For the Three Months Ended March 31,
			2007		2008
REVENUE:
	Oil and gas sales		$	12,480,000	$	25,853,000
	Gas aggregation and pipeline sales			1,141,000		3,655,000
	Realized gain (loss) on oil and gas hedging activities			271,000		(995,000	)
	Interest income and other			16,000		18,000

		Total revenue		13,908,000		28,531,000

COSTS AND EXPENSES:
	Lease operating expense			2,465,000		4,671,000
	Production taxes			188,000		1,168,000
	Gas aggregation and pipeline cost of sales			1,462,000		3,266,000
	Depreciation, depletion and amortization			3,923,000		7,306,000
	Exploration and impairment			1,784,000		2,493,000
	General and administrative (including $323,000 and $691,000, respectively, of stock compensation)			2,957,000		6,081,000
	Interest expense			574,000		1,814,000

		Total costs and expenses		13,353,000		26,799,000

INCOME BEFORE INCOME TAXES				555,000		1,732,000

INCOME TAXES:
	Deferred income tax expense			214,000		666,000

NET INCOME			$	341,000	$	1,066,000

BASIC INCOME PER SHARE			$	.01	$	.02

DILUTED INCOME PER SHARE			$	.01	$	.02

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC				44,834,644		45,304,950

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—DILUTED				45,904,921		46,334,649

See accompany notes to these financial statements.

F-30

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited)

		For the Three Months Ended March 31,
		2007			2008
NET INCOME		$	341,000		$	1,066,000
OTHER COMPREHENSIVE INCOME (LOSS):
	Change in derivative instrument fair value, net of tax		(385,000	)		(5,243,000	)

COMPREHENSIVE INCOME (LOSS)		$	(44,000	)	$	(4,177,000	)

See accompanying notes to these financial statements.

F-31

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
FOR THE THREE MONTHS ENDED MARCH 31, 2008
(unaudited)


		Common Stock
		Common Stock				Additional Paid-In Capital				Accumulated Other Comprehensive Income (loss)
		Shares		Amount		Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (loss)			Total
BALANCES, January 1, 2008		45,277,220			45,000		147,120,000		34,052,000		(23,000	)		181,194,000
	Issuance of restricted common stock to employees for services	125,000			—		33,000		—		—			33,000
	Cancellation of restricted common stock to employees for services	(17,833	)		—		—		—		—			—
	Other non-cash compensation	—			—		658,000		—		—			658,000
	Net income	—			—		—		1,066,000		—			1,066,000
	Change in derivative instrument fair value	—			—		—		—		(5,243,000	)		(5,243,000	)

BALANCES, March 31, 2008		45,384,387		$	45,000	$	147,811,000	$	35,118,000	$	(5,266,000	)	$	177,708,000

See accompanying notes to these financial statements.

F-32

ELLORA ENERGY INC. AND SUBSIDIARIES
STATEMENTS OF CASH FLOWS

				For the Three Months Ended March 31,
				2007			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	341,000		$	1,066,000
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			3,923,000			7,306,000
		Amortization of derivative asset			118,000			—
		Amortization of debt issue costs			51,000			74,000
		Deferred income taxes			214,000			666,000
		Exploration and impairment			430,000			—
		Non-cash compensation expense for employees			323,000			691,000
	Changes in operating assets and liabilities:
		Accounts receivable			(927,000	)		(916,000	)
		Prepaid and other current assets			(2,248,000	)		(151,000	)
		Income taxes payable			—			(289,000	)
		Other long-term assets			123,000			—
		Accounts payable and accrued expenses			(2,354,000	)		(10,981,000	)
		Oil and gas revenues payable			720,000			563,000

			Net cash provided (used) by operating activities		714,000			(1,971,000	)

CASH FLOWS FROM INVESTING ACTIVITIES:
	Oil and gas property acquisition				(11,676,000	)		—
	Acquisition of Shelby Pipeline, Ltd.				(6,493,000	)		—
	Drilling capital expenditures				(12,292,000	)		(15,529,000	)
	Pipeline capital expenditures				(27,000	)		(233,000	)
	Purchase of other property and equipment				(2,262,000	)		(266,000	)

		Net cash used in investing activities			(32,750,000	)		(16,028,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt under credit agreement				45,000,000			24,000,000
	Cash paid for derivative asset				(486,000	)		—

		Net cash provided by financing activities			44,514,000			24,000,000

INCREASE IN CASH					12,478,000			6,001,000
CASH, beginning of period					4,329,000			4,651,000

CASH, end of period				$	16,807,000		$	10,652,000

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest			$	239,000		$	1,221,000

	Cash paid for taxes			$	—		$	289,000

NON CASH INVESTING ACTIVITIES:
	Changes in working capital related to drilling expenditures			$	2,420,000		$	6,358,000

	Transfers from oil and gas equipment inventory to oil and gas properties			$	509,000		$	130,000

F-33

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Organization—Ellora Energy Inc. was incorporated on June 1, 2002 in the State of Delaware to engage in the acquisition, exploration, development and production of oil and gas properties. During April 2005, Ellora's management established Ellora Oil and Gas Inc. to acquire Presco Western, LLC, which was a party to a farmout agreement in the Hugoton field in Kansas. Subsequently, Presco Western LLC acquired the underlying lease interests and this farmout position. Ellora Oil and Gas Inc. also acquired Ellora Energy Inc.'s assets in Colorado. Ellora Energy Inc. and Ellora Oil and Gas Inc. operated as separate legal entities, but under common management and control until July 2006, when Ellora Energy Inc. and Ellora Oil and Gas Inc. merged with Ellora Energy Inc. as the surviving entity. Ellora Energy Inc. operates oil and gas properties in Texas, Louisiana, Colorado and Kansas and, when consolidated, has five wholly owned subsidiaries.

Basis of Presentation of Consolidated Financial Statements—The accompanying consolidated financial statements as of December 31, 2007 and March 31, 2008, and for the three month periods ended March 31, 2007 and 2008 include the accounts of Ellora Energy Inc. and it subsidiaries, all of which are wholly owned. All significant intercompany transactions have been eliminated in consolidation.

Use of Estimates and Certain Significant Estimates—The preparation of Ellora's financial statements in conformity with accounting principles generally accepted in the United States of America requires Ellora's management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates. These estimates include collection of receivables, selection of the useful lives for property and equipment and timing and costs associated with its retirement obligations. Significant assumptions are also required in the valuation of proved oil and gas reserves, which will affect the depletion calculation and possibly the impairment of oil and gas properties. It is at least reasonably possible those estimates could be revised in the near term and those revisions could be material.

Fair Value of Financial Instruments—Ellora's financial instruments, including cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates. Ellora's derivative instruments are marked-to-market with changes in value being recorded in accumulated other comprehensive income.

F-34

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)

proved reserves. The costs of development wells are capitalized whether productive or nonproductive. Interest cost is capitalized as a component of property cost for capital development projects exceeding $1,000,000 that require greater than six months to be readied for their intended use. For the three month periods ended March 31, 2007 and 2008, the Company capitalized interest expense of $0 and $203,000, respectively. Costs incurred to maintain wells and related equipment and lease and well operating costs are charged to expense as incurred. Gains and losses arising from sales of properties are included in income. Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. Impairment is recorded for unproved properties if the capitalized costs are not considered to be realizable.

English Bay Pipeline, L.P.—The pipeline aggregates natural gas through the purchase of production from properties in Shelby County, Texas in which Ellora Energy Inc. has an interest and the purchase of gas from other producers and shippers that is delivered through English Bay. The financial information of English Bay is included in Ellora's consolidated financial statements as of December 31, 2007 and March 31, 2008 and for the three month periods ended March 31, 2007 and 2008.

F-35

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)

If, during the derivative's term, Ellora determines the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses on the effective portion of the derivative are reclassified to earnings when the underlying transaction occurs. If it is determined that the designated hedge transaction is not likely to occur, any unrealized gains or losses are recognized immediately in the consolidated statements of income as a derivative fair value gain or loss.

At March 31, 2008, accumulated other comprehensive income consisted of $8,563,000 ($5,266,000 after tax) of unrealized loss, representing the mark-to-market value of Ellora's open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2007, accumulated other comprehensive loss consisted of $37,000 ($23,000 after tax) of unrealized loss representing the mark-to-market value of Ellora's open commodity contracts, designated as cash flow hedges, as of the balance sheet date.

Per Share Amounts—Basic income per share is computed using the weighted average number of shares outstanding. Diluted income per share reflects the potential dilution that would occur if stock options were exercised using the average market price for Ellora's stock for the period. Total potential dilutive shares based on options outstanding at March 31, 2008 were 2,515,753.

Ellora's calculation of earnings per share for common stock for the three month periods ended March 31, 2007 and 2008 is as follows:

	Three Months Ended March 31, 2007					Three Months Ended March 31, 2008
	Net Income		Shares	Net Income Per Share		Net Income		Shares	Net Income Per Share
Basic earnings per share	$	341,000	44,834,644	$	.01	$	1,066,000	45,304,950	$	.02
Effect of dilutive shares of common stock from stock options			1,070,277		—			1,029,699		—

Diluted earnings per share	$	341,000	45,904,921	$	.01	$	1,066,000	46,334,649	$	.02

Change in Accounting Principle—Effective January 1, 2008, the Company adopted FASB No. 157, "Fair Value Measurements", which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of FASB 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating a measure of the Company's own nonperformance risk or that of its counterparties as appropriate, which was not material. The primary impact from adoption was additional disclosures.

The Company elected to implement FASB 157 with the one-year deferral permitted by FASB Staff Position No. 157-2, "Effective Date of FASB Statement No. 157" ("FSP 157-2"), issued February 2008, which defers the effective date of FASB 157 for one year for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financials statements on a recurring basis. As it relates to the Company, the deferral

F-36

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)

applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and gas property assessments; and the initial recognition of asset retirement obligations for which fair value is used.

FASB 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•: Level 1—inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•: Level 2—inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•: Level 3—inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The following table presents information about the Company's assets and liabilities measured at fair value on a recurring basis as of March 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)	Balance as of March 31, 2008
Assets:
	Derivative asset	—	$	432,000	—	$	432,000
Liabilities:
	Derivative liability	—	$	8,991,000	—	$	8,991,000

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

Derivative Instruments—Derivative instruments consist of crude oil and natural gas swaps. The Company's swaps are valued based on the counterparty's marked-to-market statements, which are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk.

The Company has no assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 3, which is significant unobservable inputs.

In February 2007, the Financial Accounting Standards Board ("FASB") issued Statement No. 159, "Fair Value Option for Financial Assets and Financial Liabilities." FASB No. 159 permits an entity to irrevocably elect fair value on a contract-by-contract basis as the initial and subsequent

F-37

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)

measurement attribute for many financial assets and liabilities and certain other items including insurance contracts. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. The adoption of FASB No. 159 did not have a material impact on the Company's consolidated financial position or results of operations.

New Accounting Pronouncements—In December 2007, the FASB issued Statement No. 141R, Business Combinations ("FASB 141R"). FASB 141R may have an impact on the Company's consolidated financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions the Company consummates after the effective date. FASB 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in business combinations and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. FASB 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008.

In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 ("SFAS 160"). As Ellora owns 100% of its consolidated subsidiaries and it does not currently have any minority interests, the Company does not expect the adoption of FASB 160 to have an impact on its consolidated financial statements. This statement amends ARB No. 51 and intends to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards of the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. FASB 160 is effective for fiscal years, and interim periods, beginning on or after December 15, 2008.

In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment to FASB Statement No. 133 ("FASB 161"). The adoption of FASB 161 is not expected to have an impact on the Company's consolidated financial statements, other than additional disclosures. FASB 161 expands interim and annual disclosures about derivative and hedging activities that are intended to better convey the purpose of derivative use and the risks managed. FASB 161 is effective for fiscal years and interim periods beginning after November 15, 2008.

Unaudited Information—The accompanying interim financial information as of March 31, 2008 and for the three month periods ended March 31, 2007 and 2008 was taken from Ellora's books and records without audit. However, in the opinion of management, such information includes all adjustments (consisting only of normal recurring accruals), which are necessary to properly reflect the financial position of Ellora as of March 31, 2008 and the results of operations for the three month periods ended March 31, 2007 and 2008. The results of operations for the three month period ended March 31, 2008 are not necessarily indicative of those to be expected for the year ended December 31, 2008.

F-38

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

2. ACQUISITIONS AND DIVESTURES:

During 2007, Presco Western LLC (a wholly owned subsidiary of Ellora) purchased for approximately $27.3 million in cash, developed and undeveloped leasehold mineral interests in the Hugoton Field of Southwestern Kansas. Included were producing properties and leasehold mineral interests underlying the Presco Western farmout agreement. Presco had closed on approximately $11,676,000 of the purchase as of March 31, 2007. The acquisition was accounted for using the purchase method of accounting and the purchase price was allocated entirely to oil and gas properties. Revenues and operating income from the developed properties acquired were not significant to the Company's operations for the three month period ended March 31, 2007.

3. ASSET RETIREMENT OBLIGATION:

At March 31, 2008, there were no assets legally restricted for purposes of settling asset retirement obligations. The following is a reconciliation of Ellora's asset retirement obligations as of December 31, 2007 and March 31, 2008:

	December 31, 2007		March 31, 2008
Beginning of year	$	1,322,000	$	2,172,000
Additional liabilities incurred		540,000		56,000
Accretion expense		106,000		43,000
Revisions to estimate		204,000		—

End of year	$	2,172,000	$	2,271,000

4. NOTES PAYABLE:

Notes payable consisted of the following at December 31, 2007 and March 31, 2008:

		December 31, 2007			March 31, 2008
Credit Agreement.		$	110,000,000		$	134,000,000

F-39

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

4. NOTES PAYABLE: (CONTINUED)

included as a component of interest expense. For the three months ended March 31, 2008 the weighted average interest rate on the entire outstanding principal balance was 5.95% and the effective interest rate as of March 31, 2008 was 5.29%. Interest accrues at either (1) the base rate plus a margin where the base rate is defined as the higher of the prime rate or the federal funds rate plus a margin varying from 0% to 0.75% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.25% to 2.00% depending on the utilization percentage of the borrowing base. Ellora has consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. The loan is collateralized by Ellora's oil and gas properties and includes certain financial covenants, for which Ellora was in compliance for the three months ended March 31, 2008.

The credit agreement provides for interest only payments until February 3, 2010, when the entire amount borrowed is due. Ellora may, throughout the term of the credit agreement, borrow and repay up to the borrowing base in effect from time to time.

5. STOCKHOLDERS' EQUITY:

Ellora Energy Inc. Stock Option Plan—Ellora Energy Inc. adopted the 2006 Stock Option Plan (the "2006 Plan") for employees and non-employee directors to receive stock option rewards.

The following table shows a summary of the non-qualified options as of March 31, 2008:

		Number of Options		Weighted Average Exercise Price		Weighted Average Fair Value
Outstanding, December 31, 2007		2,542,710		$	3.53	$	1.65
	Granted	—			—		—
	Exercised	—			—		—
	Expired	—			—		—
	Cancelled	(26,957	)		4.94		2.46

Outstanding, March 31, 2008		2,515,753		$	3.51	$	1.64

The above options vest as follows:

	Number of Options	Weighted Average Exercise Price		Weighted Average Fair Value Price
Vested as of March 31, 2008	2,366,757	$	3.55	$	1.65
Vest during the remainder of 2008	148,996		4.94		2.46

	2,515,753	$	3.51	$	1.64

Total estimated unrecognized compensation cost for the unvested stock options as of March 31, 2008 was approximately $403,000, which is expected to be recognized in 2008. The intrinsic value of the outstanding and vested shares, based on an estimated intrinsic value of $12.00 per share, less

F-40

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

5. STOCKHOLDERS' EQUITY: (CONTINUED)

the weighted average exercise price was $8.49 for all options and $8.45 for vested options as of March 31, 2008.

Ellora Energy Inc. Amended and Restated 2006 Stock Incentive Plan—Ellora Energy Inc. adopted the 2006 Stock Incentive Plan for employees and non-employee directors to receive restricted stock. In accordance with the plan, 884,616 shares of restricted stock have been reserved for issuance. All restricted stock grants to date shall vest as to one-third of the underlying shares as of the first, second, and third anniversary dates of the grant as set forth in the Restricted Stock Agreement with such employees.

The following table shows a summary of the restricted stock grants as of March 31, 2008:

Date	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding, December 31, 2007	390,379		$	12.00
Granted	125,000		$	12.00
Forfeited	(17,833	)	$	12.00

Restricted stock awards, nonvested, March 31, 2008	497,546		$	12.00

Stock compensation expense of $0 and $384,000 was recorded for the three month periods ended March 31, 2007 and 2008 related to these shares. As of March 31, 2008, there was $4,819,000 of total unrecognized compensation cost related to the unvested restricted stock granted under the plan. That costs is expected to be recognized over a period of approximately three years.

6. INCOME TAXES:

The provision for income taxes for the three month periods ended March 31, 2007 and 2008 consists of the following:

		March 31, 2007		March 31, 2008
Current taxes		$	—	$	—
Deferred taxes			214,000		666,000

	Total income tax expense	$	214,000	$	666,000

The deferred income tax liability of $25,054,000 at March 31, 2008 is composed of future taxable temporary differences related to Ellora's oil and gas properties, including amounts previously recorded in connection with the acquisition of properties and subsequent differences between financial and tax reporting for oil and gas properties and is partially offset by Ellora's net operating loss carryforwards. The deferred tax asset of $3,295,000 is related to net unrealized hedging losses

F-41

ELLORA ENERGY INC. AND SUBSIDIARIES
NOTES TO CONDENSED UNAUDITED FINANCIAL STATEMENTS (Continued)

6. INCOME TAXES: (CONTINUED)

at March 31, 2008. At December 31, 2007, Ellora Energy Inc. had net operating loss carryforwards for Federal tax purposes of approximately $40,810,000 for regular income tax purposes.

Ellora is subject to the alternative minimum tax ("AMT") due to accelerated tax depreciation, deductions for intangible drilling costs and other items of "tax preference." Ellora's net operating loss carryforward for purposes of the AMT aggregated to $16,920,000 at December 31, 2007.

7. MAJOR CUSTOMERS:

For the three months ended March 31, 2007, Louis Dreyfus Energy Services and Plains Marketing, L.P. accounted for 54% and 19%, respectively, of our oil and gas sales. For the three months ended March 31, 2008, Louis Dreyfus Energy Services and Texon L.P. accounted for 41% and 34%, respectively, of our oil and gas sales. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

8. DERIVATIVE FINANCIAL INSTRUMENTS:

Ellora entered into various futures commitments to minimize the effect of oil price fluctuations summarized in the table below. As of March 31, 2007, Ellora had the following outstanding financial oil positions:

Contract Type	Weighted Average Strike Price		Quantity	Contract Period
Futures Swap, Gas	$	8.01	100,000 MMBtu/month	01/01/2008-12/31/2008
Futures Swap, Gas	$	8.275	100,000 MMBtu/month	01/01/2008-12/31/2008
Futures Swap, Gas	$	8.24	200,000 MMBtu/month	02/01/2008-12/31/2008
Futures Swap, Gas	$	9.04	50,000 MMBtu/month	03/01/2008-12/31/2008
Futures Swap, Gas	$	9.025	50,000 MMBtu/month	03/01/2008-12/31/2008
Futures Swap, Oil	$	100.00	15,000 Bbls/month	03/01/2008-12/31/2008
Futures Swap, Oil	$	102.60	5,000 Bbls/month	04/01/2008-12/31/2008
Futures Swap, Gas	$	10.20	50,000 MMBtu/month	04/01/2008-12/31/2008
Futures Swap, Oil	$	98.05	10,000 Bbls/month	01/01/2009-12/31/2009
Futures Swap, Gas	$	9.50	100,000 MMBtu/month	01/01/2009-12/31/2009
Futures Swap, Gas	$	9.725	100,000 MMBtu/month	01/01/2009-12/31/2009

As of March 31, 2008, the above contracts had an unrealized loss, net of deferred tax effect, of ($5,266,000), which is recorded in other comprehensive income.

9. SUBSEQUENT EVENTS:

On May 1, 2008 Ellora entered into an amended and restated $400,000,000 credit agreement with an initial borrowing base of $190,000,000 with a consortium of banks led by JP Morgan Chase Bank, N.A.

On June 4, 2008, we entered into a binding letter agreement to sell a 65% working interest in our deep rights in East Texas for approximately $350 million in a transaction that we expect to close on or before July 31, 2008, subject to standard conditions to closing such as the completion of customary due diligence, the negotiation of a mutually acceptable participation agreement, and a condition that title and related contracts and agreements are acceptable to Chesapeake.

F-42

Appendix A

May 23, 2008

Ellora Energy Inc.
5665 Flatiron Parkway
Boulder, Colorado 80301

Gentlemen:

At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain lease hold interests of Ellora Energy Inc. as of March 31, 2008. The subject properties are located in the States of Colorado, Kansas, Louisiana and Texas. The income data were estimated using the Securities and Exchange Commission (SEC) guidelines for future cost and price parameters.

The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. March 31, 2008 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from March 31, 2008 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. A summary of the results of this study is shown below.

SEC PARAMETERS
Estimated Net Reserves and Income Data*
Certain Leasehold Interests of
Ellora Energy Inc.
As of March 31, 2008

		Proved
		Developed Producing		Undeveloped		Total Proved*
*Net Remaining Reserves*
	Oil/Condensate—Barrels		2,336,166		5,963,363		8,299,530
	Gas—MMCF		70,913		108,457		179,370
*Income Data M$*
	Future Gross Revenue	$	826,401	$	1,484,537	$	2,310,938
	Deductions		201,076		462,151		663,227

	Future Net Income (FNI)	$	625,325	$	1,022,386	$	1,647,711
	Discounted FNI @ 10%	$	328,810	$	491,431	$	820,241

*: From Landmark Graphics Corporation's "ARIES".

At Ellora Energy Inc's request, all economic evaluations were made using the Aries program, which is developed and licensed by Landmark Graphics Corporation (Landmark). Due to rounding anomalies, the total value for some of the data items may not be exactly the same as the sum of the components represented in the total.

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The various producing status categories are defined under the tab "Reserve Definitions" in this report.

1100 LOUISIANA SUITE 3800
1100, 530 8^th AVENUE S.W.

HOUSTON, TEXAS 77002-5218
CALGARY, ALBERTA T2P 3S8

TEL (713) 651-9191
TEL (403) 262-2799

FAX (713) 651-0849
FAX (403) 262-2790

A-1

The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development costs. The future net income is before the deduction of state and federal income taxes and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 33 percent and gas reserves account for 67 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below.

Discounted Future Net Income As of March 31, 2008
Discount Rate Percent	Total Proved M$
5	$	1,091,105
15	$	654,940
20	$	544,580
25	$	465,558

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

Theproved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The definitions of proved reserves are included under the tab "Petroleum Reserves Definitions" in this report. The reserves and income quantities attributable to the different reserve classifications that are included herein have not been adjusted to reflect the varying degrees of risk associated with them and thus are not comparable.

Estimates of Reserves

In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such other methods were more appropriate in our opinion. The reserves estimated by the performance method utilized extrapolations of various historical data in those cases where such data were definitive in our opinion. Reserves were estimated by the volumetric method or analogy in those cases where there were inadequate historical performance data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Future Production Rates

Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

A-2

production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Ellora Energy Inc.

The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.

Hydrocarbon Prices

Ellora Energy Inc. furnished us with oil and condensate prices in effect at March 31, 2008 and these prices were held constant except for known and determinable escalations. In accordance with Securities and Exchange Commission guidelines, changes in liquid and gas prices subsequent to March 31, 2008 were not taken into account in this report.

Ellora Energy Inc. furnished us with gas prices in effect at March 31, 2008 and with its forecasts of future gas prices which take into account SEC guidelines, current spot market prices, contract prices, and fixed and determinable price escalations where applicable. In accordance with SEC guidelines, the future gas prices used in this report make no allowances for future gas price increases which may occur as a result of inflation nor do they make any allowance for seasonal variations in gas prices which may cause future yearly average gas prices to be some what different than March 31, 2008 gas prices. For gas sold under contract, the contract gas price including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves.

Current oil and gas hedging contracts are not associated with specific properties and therefore are not incorporated into this report. Any oil and gas hedging contracts currently in place may be material and should be accounted for by Ellora Energy Inc. outside of this report.

Costs

Operating costs for the leases and wells in this report were supplied by Ellora Energy Inc. and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, this includes an appropriate level of corporate general administrative and overhead costs and for non-operated properties include the COPAS overhead costs allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells. Development costs were furnished to us by Ellora Energy Inc. and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. At the request of Ellora Energy Inc., their estimate of zero abandonment costs after salvage value for onshore properties was used in this report. Ryder Scott has not performed a detailed study of the abandonment costs nor the salvage value and makes no warranty for Ellora Energy Inc.'s estimate. This study does not consider abandonment costs or salvage value of the lease equipment.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

A-3

General

Ryder Scott Company, L.P. (Ryder Scott) performed the reserve analysis and generated the projection of future production represented in this report. At the request of Ellora Energy Inc., the economic analyses were performed using Landmark's ARIES program. Ryder Scott has confirmed that the scheduling of production is correct. Other data such as prices, operating costs, taxes and interests were input by Ellora Energy Inc. and not subject to independent verification. The internal calculations of the ARIES program were accepted without verification, and use of the results is subject to the Limitation of Liability established by the software purchase agreement between Ryder Scott and Landmark, which can be provided upon request. Further, Ryder Scott does not accept any liability with respect to the program results beyond that accepted by Landmark. Therefore, in no event will Ryder Scott be liable for consequential, incidental, punitive or exemplary damages resulting from the use of the ARIES program.

The tables presented in this report are generated by ARIES. It should be noted that the values on the various tables do not always add to exactly the same values on the summary tables. These very small differences are the result of internal rounding by the program. Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Individual forecasts present our estimated projection of production and income by years beginning March 31, 2008, by state, field, and lease or well.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Ellora Energy Inc. owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Ellora Energy Inc. has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by Ellora Energy Inc. were accepted without independent verification.

Neither we, nor any of our employees, have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.

This report was prepared for the exclusive use of Ellora Energy Inc. and may not be put to other use without our prior written consent for such use.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

A-4

The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

		Very truly yours,
		RYDER SCOTT COMPANY, L.P.
		Scott J. Wilson P.E., MBA Senior Vice President

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

A-5

PETROLEUM RESERVES DEFINITIONS
SECURITIES AND EXCHANGE COMMISSION

INTRODUCTION

Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It should be noted that Securities and Exchange Commission Regulation S-K prohibits the disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A): that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B): the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii)

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

A-6

(iii)

Estimates of proved reserves do not include the following:

(A): oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
(B): crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C): crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D): crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff's view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

A-7

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e. that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission's official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS)

In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing.

Producing. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Non-Producing. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompilation prior to the start of production.

A-8

Until , 2008 (25 days after the commencement of this offering), all dealers that buy, sell or trade the common stock may be required to deliver a prospectus, regardless of whether they are participating in this offering. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

11,363,189 Shares

Common Stock

P R O S P E C T U S

Merrill Lynch & Co.
Raymond James
KeyBanc Capital Markets
Tudor, Pickering, Holt & Co.
Howard Weil Incorporated
Tristone Capital
Thomas Weisel Partners LLC

, 2008

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.

SEC registration fee		$	11,649
Legal fees and expenses			500,000
FINRA filing fee			9,125
Nasdaq Global Market listing fee			105,000
Printing and engraving expenses			500,000
Engineering fees and expenses			100,000
Transfer agent's and registrar's fees			50,000
Accounting fees and expenses			100,000
Miscellaneous			644,226

	Total	$	2,020,000

Item 14. Indemnification of Officers and Directors

Our certificate of incorporation provides that a director will not be liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (1) for any breach of the director's duty of loyalty to the corporation or its stockholders, (2) for acts or omissions not in good faith or which involved intentional misconduct or a knowing violation of the law, (3) under section 174 of the Delaware General Corporate Law ("DGCL") for unlawful payment of dividends or improper redemption of stock or (4) for any transaction from which the director derived an improper personal benefit. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our charter, will be limited to the fullest extent permitted by the amended DGCL. Our bylaws provide that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys' fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys' fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation's charter, bylaws, disinterested director vote, stockholder vote, agreement, or otherwise.

Our charter also contains indemnification rights for our directors and our officers. Specifically, the charter provides that we shall indemnify our officers and directors to the fullest extent authorized

II-1

by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

We have obtained directors' and officers' insurance to cover our directors, officers and some of our employees for certain liabilities.

We will enter into written indemnification agreements with our directors and executive officers. Under these proposed agreements, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director.

The registration rights agreement and purchase agreement we entered into in connection with our earlier financings provide for the indemnification by the investors in those financings of our officers and directors for certain liabilities.

Item 15. Recent Sales of Unregistered Securities

During the last three years, we have sold the following unregistered shares of common stock:

1. On July 8, 2005, we sold 364,171 shares of common stock to James R. Casperson, our former Vice President of Finance and Chief Financial Officer who retired in March 2008, for a purchase price consisting of (i) a full recourse promissory note issued by the purchaser in the principal amount of $899,955 and (ii) $45.00 in cash. No underwriters were used in the foregoing issuances of securities. We relied upon the exemption under Section 4(2) of the Securities Act in connection with the offer and sale of those shares, as Mr. Casperson was an executive officer at the time of purchase and this transaction was not a public offering.

2. On July 12, 2006 we completed a private placement of 12,400,000 shares of common stock, 2,500,000 shares of which were issued and sold by us and 9,900,000 shares of which were sold by certain of our stockholders. All of the shares sold by the selling stockholders offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The shares issued by us were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to accredited investors pursuant to Section 4(2) of the Securities Act. Friedman, Billings & Ramsey Co. Inc. ("FBR") acted as the initial purchaser of all of the shares issued pursuant to Rule 144A and as placement agent for all of the shares issued pursuant to Section 4(2) of the Securities Act. We sold the shares issued pursuant to Rule 144A to FBR at a price of $11.16 per share, which was an $0.84 per share discount to the gross offering price to the investors of $12.00 per share. Aggregate net proceeds to us for the total offering, after deducting discounts of $2,100,000, was $27,900,000. We did not receive any proceeds from the shares sold by the selling stockholders. All net proceeds of the above offering that we received were used for paying down our existing debt and for general corporate purposes.

3. Additionally from April 1, 2002 (inception) through March 31, 2008, we have granted to our employees, including executive officers, and others providing services to us options to purchase 2,969,300 shares of our common stock at exercise prices ranging from $1.24 per share to $4.95 per share. During that same period an executive officer exercised options to purchase an aggregate of 248,713 shares of our common stock. All such issuances were made in reliance on Rule 701 as promulgated under the Securities Act relating to issuances of securities under compensatory plans.

II-2

Item 16. Exhibits and Financial Statement Schedules

(a): Exhibits.

The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K:

	Exhibit No.		Description
	1.1**		Form of Underwriting Agreement.
	3.1**		Amended and Restated Certificate of Incorporation of Ellora Energy Inc.
	3.2**		Bylaws of Ellora Energy Inc. dated as of May 17, 2002.
	3.3**		Amendment to the Bylaws of Ellora Energy Inc. dated as of August 27, 2002.
	3.4**		Amendment No. 2 to the Bylaws of Ellora Energy Inc. dated as of September 11, 2006.
	4.1**		Registration Rights Agreement between Ellora Energy Inc. and Friedman, Billings, Ramsey & Co., Inc., dated as of July 12, 2006.
	4.2**		Registration Rights Agreement among Ellora Energy Inc., Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., and the participating stockholders who have executed the signature pages thereto or are listed on Schedule I thereto, dated as of July 12, 2006.
	4.3**		Specimen of Ellora Energy Inc. Common Stock Certificate.
	5.1**		Opinion of Thompson & Knight LLP.
	10.1**		Ellora Energy Inc. Amended and Restated 2006 Stock Incentive Plan dated July 11, 2006.
	10.2**		Employment Agreement dated as of July 12, 2006 between Ellora Energy Inc. and T. Scott Martin.
	10.3**		Farmout Contract dated as of November 14, 1997 between Amoco Production Company and Ellora Energy Inc. (as successor in interest to Presco, Inc.).
	10.4*		Amended and Restated Credit Agreement dated as of May 1, 2008 among Ellora Energy Inc., JPMorgan Chase Bank, N.A., Key Bank, N.A., Guaranty Bank, FSB, Fortis Capital Corp., Compass Bank, and the Lenders party thereto.
	10.5**		Joint Venture Agreement dated as of June 1, 2004 by and between Centurion Exploration Company, Centurion Exploration Company, LLC, and Ellora Energy Inc.
	10.6**		Confirmation Letter for Contract for Sale and Purchase of Natural Gas dated November 29, 2006 between Louis Dreyfus Energy Services LP and Ellora Operating, LP.
	10.7**		Confirmation Letter for Contract for Sale and Purchase of Natural Gas dated November 30, 2006 between Louis Dreyfus Energy Services LP and Ellora Operating, LP.
	10.8**		Crude Oil Purchase Contract dated June 1, 2002 between Presco Western, LLC and Plains Marketing, L.P.
	10.9**		Crude Oil Purchase Contract dated May 5, 2005 between Ellora Operating, L.P. and Plains Marketing, L.P.
	10.10**		Amendment to Crude Oil Purchase Contract (June 1, 2002) dated October 4, 2006 between Presco Western, LLC. and Plains Marketing, L.P.

II-3

	10.11***		Letter Agreement dated June 3, 2008 between Chesapeake Exploration, L.L.C. and Ellora Energy Inc.
	21.1**		List of Subsidiaries of Ellora Energy Inc.
	23.1*		Consent of Hein & Associates LLP.
	23.2*		Consent of Ryder Scott Company, L.P.
	23.3**		Consent of Thompson & Knight LLP (included in Exhibit 5.1).
	24**		Power of Attorney.

*: Filed herewith
**: Previously filed
***: To be filed by amendment.
(b): Financial Statements Schedules

All schedules have been omitted because they are not required, are not applicable, or the information is included in the Financial Statements or Notes thereto.

Item 17. Undertakings

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(1): For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and
(2): For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Amendment No. 11 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Boulder, State of Colorado, on June 20, 2008.

	ELLORA ENERGY INC.
	By:		/s/ T. SCOTT MARTIN
	Name:		T. Scott Martin
	Title:		President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 11 to the Registration Statement has been signed by the following persons in the capacities indicated below on June 20, 2008.

Signature		Capacity

/s/ T. SCOTT MARTIN T. Scott Martin		Chairman of the Board President and Chief Executive Officer (Principal Executive Officer)
/s/ STEVEN R. ENGER Steven R. Enger		Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
* Cortlandt S. Dietler		Director
* Bryan H. Lawrence		Director
* Peter A. Leidel		Director
* Sheldon B. Lubar		Director
* Neil L. Stenbuck		Director
* James B. Wallace		Director
* George A. Wiegers		Director
* /s/ T. SCOTT MARTIN Attorney-In-Fact

II-5

INDEX TO EXHIBITS

	Exhibit No.		Description
	1.1**		Form of Underwriting Agreement.
	3.1**		Amended and Restated Certificate of Incorporation of Ellora Energy Inc.
	3.2**		Bylaws of Ellora Energy Inc. dated as of May 17, 2002.
	3.3**		Amendment to the Bylaws of Ellora Energy Inc. dated as of August 27, 2002.
	3.4**		Amendment No. 2 to the Bylaws of Ellora Energy Inc. dated as of September 11, 2006.
	4.1**		Registration Rights Agreement between Ellora Energy Inc. and Friedman, Billings, Ramsey & Co., Inc., dated as of July 12, 2006.
	4.2**		Registration Rights Agreement among Ellora Energy Inc., Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., and the participating stockholders who have executed the signature pages thereto or are listed on Schedule I thereto, dated as of July 12, 2006.
	4.3**		Specimen of Ellora Energy Inc. Common Stock Certificate.
	5.1**		Opinion of Thompson & Knight LLP.
	10.1**		Ellora Energy Inc. Amended and Restated 2006 Stock Incentive Plan dated July 11, 2006.
	10.2**		Employment Agreement dated as of July 12, 2006 between Ellora Energy Inc. and T. Scott Martin.
	10.3**		Farmout Contract dated as of November 14, 1997 between Amoco Production Company and Ellora Energy Inc. (as successor in interest to Presco, Inc.).
	10.4*		Amended and Restated Credit Agreement dated as of May 1, 2008 among Ellora Energy Inc., JPMorgan Chase Bank, N.A., Key Bank, N.A., Guaranty Bank, FSB, Fortis Capital Corp., Compass Bank, and the Lenders party thereto.
	10.5**		Joint Venture Agreement dated as of June 1, 2004 by and between Centurion Exploration Company, Centurion Exploration Company, LLC, and Ellora Energy Inc.
	10.6**		Confirmation Letter for Contract for Sale and Purchase of Natural Gas dated November 29, 2006 between Louis Dreyfus Energy Services LP and Ellora Operating, LP.
	10.7**		Confirmation Letter for Contract for Sale and Purchase of Natural Gas dated November 30, 2006 between Louis Dreyfus Energy Services LP and Ellora Operating, LP.
	10.8**		Crude Oil Purchase Contract dated June 1, 2002 between Presco Western, LLC and Plains Marketing, L.P.
	10.9**		Crude Oil Purchase Contract dated May 5, 2005 between Ellora Operating, L.P. and Plains Marketing, L.P.
	10.10**		Amendment to Crude Oil Purchase Contract (June 1, 2002) dated October 4, 2006 between Presco Western, LLC. and Plains Marketing, L.P.
	10.11***		Letter Agreement dated June 3, 2008 between Chesapeake Exploration, L.L.C. and Ellora Energy Inc.
	21.1**		List of Subsidiaries of Ellora Energy Inc.
	23.1*		Consent of Hein & Associates LLP.
	23.2*		Consent of Ryder Scott Company, L.P.
	23.3**		Consent of Thompson & Knight LLP (included in Exhibit 5.1).
	24**		Power of Attorney.

*: Filed herewith
**: Previously filed.
***: To be filed by amendment.

II-6

Ellora Energy Inactive S-1/AIPO registration (amended)