Ellora Energy S1 IPO registration

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TABLE OF CONTENTS
Index to Financial Statements of Ellora Energy Inc

As filed with the Securities and Exchange Commission on November 9, 2006

Registration No. 333-

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

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

Delaware (State or other jurisdiction of incorporation or organization)	1311 (Primary Standard Industrial Classification Code Number)	01-0717160 (I.R.S. Employer Identification Number)
5480 Valmont, Suite 350 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 5480 Valmont, Suite 350 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 Thompson & Knight LLP 333 Clay Street, Suite 3300 Houston, TX 77002 (713) 654-8111

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. ý

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

CALCULATION OF REGISTRATION FEE

Title of each class of Securities to be registered	Amount to be registered	Proposed maximum offering price per share(1)	Proposed maximum aggregate offering price(1)	Amount of registration fee


Common Stock, par value $0.001 per share	11,623,261	$12.00	$139,479,132	$14,925

(1): Estimated solely for the purpose of calculating the registration fee under Rule 457(c) under the Securities Act. No exchange or over-the-counter-market exists for registrant's common stock; however, the registrant is in the process of applying to list shares of the registrant's common stock on the Nasdaq Global Market, and the registrant's shares of common stock issued to qualified institutional buyers in connection with its July 2006 private equity placement are eligible for the PORTAL Market. There is currently no market price for the shares of the Registrant's common stock; however, the price of the shares issued in the registrant's July 2006 private placement was $12.00 per share.

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. The securities may not be sold 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, DATED NOVEMBER 9, 2006

PRELIMINARY PROSPECTUS

11,623,261 Shares

Common Stock

This prospectus relates to up to 11,623,261 shares of the common stock of Ellora Energy Inc., which may be offered and sold, from time to time, by the selling stockholders named in this prospectus. The selling stockholders acquired the shares of common stock offered by this prospectus in a private equity placement. We are registering the offer and sale of the shares of common stock to satisfy registration rights we have granted to the selling stockholders. We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders.

The shares of common stock to which this prospectus relates may be offered and sold from time to time directly by the selling stockholders or alternatively through underwriters or broker-dealers or agents. The shares of common stock may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale, or at negotiated prices. Prior to this offering, there has been no public market for the common stock. We estimate that the selling stockholders initially will sell their shares at prices between $ per share and $ per share, if any shares are sold. Future prices will likely vary from this range and initial sales may not be indicative of prices at which our common stock will trade in the future. Please read "Plan of Distribution."

We have applied to list our common stock on the Nasdaq Global Market under the symbol "LORA."

Investing in our common stock involves a high degree of risk. You should read the section entitled "Risk Factors" beginning on page 13 for a discussion of certain risks that you should consider before buying shares of our common stock.

You should rely only on the information contained in this prospectus or any prospectus supplement or amendment. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted.

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 date of this prospectus is , 2006.

Ellora Energy Inc. Areas of Operation
As of June 30, 2006

TABLE OF CONTENTS


Prospectus Summary
Risk Factors
Cautionary Statement Regarding Forward-Looking Statements
Use of Proceeds
Dividend Policy
Capitalization
Selected Combined Historical Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Business
Management
Security Ownership of Certain Beneficial Owners and Management
Certain Relationships and Related Party Transactions
Selling Stockholders
Plan of Distribution
Description of Capital Stock
Shares Eligible for Future Sale
Registration Rights
Material United States Federal Income Tax Considerations for Non-United States Holders
Legal Matters
Experts
Where You Can Find More Information
Glossary of Selected Oil and Gas Terms
Index to Financial Statements of Ellora Energy Inc.
Executive Summary Reports of MHA Petroleum Consultants, Inc.

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 13, 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." References to the number of shares of our common stock outstanding have been revised to reflect a 8.09216-for-1 stock split effected in July 2006. The estimates of our proved reserves included in this prospectus as of December 31, 2005 are based on a reserve report prepared by us and audited by MHA Petroleum Consultants, Inc., independent petroleum engineers ("MHA"), and as of June 30, 2006 are based on a reserve report prepared by MHA. Summaries of their reports with respect to these estimated proved reserves as of December 31, 2005 and June 30, 2006 are attached to this prospectus as Appendix A. We discuss sales volumes, per Mcf revenue, per Mcf 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. 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 794,000 gross (745,000 net) acres providing us with 680 identified drilling locations. At June 30, 2006 we owned interests in 232 gross (144 net) producing wells, and during June 2006 our average net production was approximately 26 MMcfe/d. At June 30, 2006, our estimated total proved oil and gas reserves were approximately 281 Bcfe. Our proved reserves are approximately 84% gas and 33% proved developed. Our total proved reserves have a reserve life index of approximately 37 years and our proved producing reserves have a reserve life index of 11 years. Using prices as of June 30, 2006, our proved reserves had an estimated pre-tax net present value, discounted at 10%, or PV-10, of approximately $487 million, of which 41% was proved developed. See "Selected Combined 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 and estimated average daily net production information as of and for the six months ended June 30, 2006.

		Estimated Proved Reserves at June 30, 2006								Production for the Six Months Ended June 30, 2006
		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		73	143	216	77	%	$	285	271	14	67	%
Hugoton (Kansas)		17	40	57	20			183	392	6	28
Other		4	4	8	3			19	17	1	5

	Total	94	187	281	100	%	$	487	680	21	100	%

(1): Based on June 30, 2006 NYMEX spot prices of $6.10 per MMBtu of gas and $73.93 per Bbl of oil, respectively, adjusted for basis and held flat for the life of the reserves and adjusted for quality differentials.
(2): Represents total gross drilling locations identified by management as of June 30, 2006. Of the total, 203 locations are classified as proved.

East Texas

James Lime

We are one of the largest producers and acreage holders in the James Lime play. We acquired our initial acreage position and wells producing 5 MMcfe/d in Shelby County, Texas in June 2002. Since then we have amassed 87,000 gross (70,000 net) acres in East Texas. From June 2002 through June 30, 2006, we invested $50 million to drill and complete 21 of 22 James Lime wells, for a 95% completion rate. At June 30, 2006, we had 58 productive wells and total proved reserves of approximately 260 Bcfe in the James Lime. During the first six months of 2006, we produced an average of 14 MMcfe/d from this region. We have identified 150 drilling locations and anticipate drilling 12 wells in the James Lime in 2006 at a budgeted cost per completed well of $2.1 million for unstimulated wells and $3.1 million for stimulated wells.

Fredericksburg

We also produce out of the shallower Fredericksburg (or Edwards) formation on our East Texas acreage. Since 2004 we have invested $16 million to drill and complete seven of eight Fredericksburg wells, an 88% completion rate. At June 30, 2006, we had seven productive wells and total proved reserves of approximately 38 Bcfe in the Fredericksburg formation, of which 4 Bcfe were proved developed producing. We have identified 110 drilling locations and anticipate drilling two wells in the Fredericksburg formation in 2006 at a budgeted cost per completed well of $1.1 million.

English Bay Pipeline, L.P.

We own and operate 80 miles of four-to-eight-inch gas gathering lines and gas pipelines and 13 compressor stations with 9,630 total compression horsepower, which gather, process and transport our gas and third party gas in our East Texas operations area. Our ownership of this pipeline system provides us with the benefit of controlling compression location and timing of connection to newly completed wells. Our system interconnects to the Texas Eastern, Centerpoint and Shelby County pipelines. During the six months ended June 30, 2006 we transported an average of approximately 27.3 MMcf/d of gas. Our pipeline activities produced third party revenues of approximately $5.6 million for the full year 2005 and $2.4 million for the six months ended June 30, 2006.

Kansas

Hugoton Field

The Hugoton field has produced over 31 Tcf of gas since its discovery in 1927, making it the most prolific gas field in North America. We acquired our Hugoton field acreage position in April 2005 through our purchase of Presco Western, LLC, which is a party to a farmout agreement with a subsidiary of BP Amoco. Our farmout covers approximately 651,000 gross (631,000 net) acres in the heart of the Hugoton field, making us one of the largest acreage holders in the field. The farmout, which terminates in 2013, grants us the mineral rights in reservoirs we develop below the Heebner Shale (located at a depth of approximately 4,000 feet) as long as we fulfill our obligation to drill a minimum of 10 exploratory wells per year. Since we acquired this position in 2005 we have invested $11.9 million to complete 25 of 30 wells, an 83% completion rate. At June 30, 2006, we had 68 productive wells and total proved reserves of approximately 57 Bcfe, of which 17 Bcfe were proved developed producing. During the first six months of 2006, we produced an average of 6 MMcfe/d, up from 2 MMcfe/d at the time of the acquisition. We have identified three waterfloods, 392 drilling locations and anticipate drilling 33 wells in 2006.

Recent Developments

Development of Multi-Stage Stimulation Frac Technology

In mid-2006 we applied a new frac technology that we believe will allow for higher initial production rates and ultimate reserve recoveries for our East Texas wells than have previously been achieved. We have drilled four wells to date using this new frac technology, and we have experienced production at significantly higher rates than has been experienced using unstimulated production techniques. Incremental capital expenditure costs for using this new technology is approximately $1 million per well. We currently anticipate using this new frac technology to drill and complete additional wells during the remainder of 2006.

Summary of Capital Expenditures

The following table summarizes information regarding our historical 2005 and our estimated 2006 and 2007 capital expenditures. The estimated 2006 capital expenditures shown are preliminary full year estimates, including approximately $27 million spent from January 1, 2006 through June 30, 2006. 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.

				Estimated
		Historical		Year Ending December 31,
		Year Ended December 31, 2005		Year Ending December 31,
		Year Ended December 31, 2005		2006		2007
		(In thousands)
Capital expenditures:
	East Texas	$	25,336	$	34,400	$	36,000
	Hugoton		4,565		18,986		21,657
Other			4,034		9,258		8,789
Geological and geophysical			35		4,000		4,000
Growth capital expenditures(1)			—		7,000		60,000

	Total capital expenditures	$	33,970	$	73,644	$	130,446

(1): Growth capital expenditures are for the acceleration of drilling and secondary recovery in addition to capital expenditures contemplated in the reserve report. We do not budget for possible acquisitions.

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 (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 over 90% since our inception and helped us improve and maximize field recoveries. We will use advanced geological and geophysical technologies, detailed petrophysical analyses, advanced reservoir engineering, and sophisticated completion and stimulation techniques, including multi-stage stimulation frac 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.

•: When we acquired the East Texas properties in June 2002, we estimated that each acquired well had average proved reserves of 2.5 Bcfe. From June 2002 to June 30, 2006, we drilled and completed 21 James Lime wells, and due to the improved geosteering, drilling and completion techniques we used in drilling them, we estimate that each of these 21 newly completed wells has average proved reserves of 3.5 Bcfe.
•: In East Texas we have begun to utilize multi-stage stimulation frac technology that we believe will allow for higher initial production rates and ultimate reserve recoveries than have previously been achieved in analogous horizontal wells. We have tested this technology on four wells, and we have experienced production at significantly higher rates than has been experienced using unstimulated production techniques. We achieved commercial production using this technology during the third quarter of 2006.
•: In the Hugoton field we are completing studies of two secondary recovery projects that will use traditional waterflood techniques. One of the areas identified has shown increased production in response to waterflood projects operated by others on contiguous properties. We expect to commence initial operations on the first of these two projects during the first quarter of 2007.
•: In the Hugoton field, we drill to the lowest known hydrocarbon producing formation in our area, then attempt completion in zones that have shown the presence of hydrocarbons during drilling. Geological evaluation through traditional logging methods is not as successful as this pragmatic test. We have found at least two economic production zones in each completed well using this method.
•: We intend to acquire an additional 350 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 350 square miles of proprietary 3-D seismic and 275 square miles of licensed 3-D seismic, providing seismic coverage of approximately two thirds of our Hugoton interest by 2011.

•

Acquisition Growth. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We will focus particularly on opportunities where we believe our reservoir management and operational expertise will enhance the value and performance of acquired properties. Initial acquisition targets are expected to be in and around our major producing and activity areas. 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. Upon the completion of our initial public offering, we expect to have approximately $ million in cash, no bank debt and at least $110 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.

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 over 22 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.
•: High Quality, Operated Asset Base. We own a high quality asset base comprised of long-lived reserves along with shorter-lived, higher return reserves. We operate over 90% of our estimated proved reserves. Approximately 84% 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 87,000 gross (70,000 net) acres and in the Hugoton field our BP Amoco farmout covers 651,000 gross (631,000 net) acres. We believe we have assembled a high quality 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 per Mcf. 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.
•: Drilling Inventory. We have identified 680 drillable, low to moderate risk locations providing us with multiple years of drilling inventory. Of these locations, 203 are classified as proved undeveloped. 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.
•: Proven Technical Team. Our technical staff includes 17 geologists, geophysicists, reservoir engineers and technicians with an average of over 16 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.
•: High Rate of 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 over 90% 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 $100 million to drill and complete 52 wells in our East Texas and Hugoton operating areas. Our average acquisition, finding and development costs from inception to June 30, 2006 was $1.27 per Mcfe.

•: Control of Low-Pressure Gas Gathering Infrastructure. We own and operate approximately 80 miles of gas gathering lines and gas pipelines that collect and transport our production and third party production in our East Texas operations area. We intend to acquire or construct additional gas gathering assets as necessary to fully develop our East Texas opportunities.
•: Gas Marketing Flexibility. 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.
•: Significant Equity Held by Management. After giving effect to our initial public offering, our management and employees will own more than % of our equity on a fully diluted basis.

East Texas

The Lower Cretaceous James Lime play extends in Texas from Angelina County through portions of Nacogdoches, San Augustine, Sabine and Shelby Counties into De Soto and Sabine Parishes of Louisiana. The James Lime is an East Texas carbonate trend that is a horizontal drilling objective. The companies currently active in the James Lime include Ellora, St. Mary Land & Exploration Company, Marathon Oil Corporation, Hunt Oil Company, Samson Lone Star, L.P. and several smaller companies.

We acquired our initial position in East Texas in June 2002. Our acreage is in the Huxley and East Bridges fields, which we believe are 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 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. The wells drilled to date have all been completed naturally with open-hole horizontal well bores. An average well costs approximately $2.1 million to drill and complete for unstimulated wells and $3.1 million for stimulated wells. The average initial flow rate of the unstimulated wells we have completed since June 2002 has been 2 MMcfe/d and the average proved reserves attributable to these wells is approximately 3.5 Bcfe. We have recently begun implementing a new stimulation technology plan in this area that is estimated by us to cost an additional $1 million per well. We believe this new stimulation technology will increase initial production rates and ultimate recovery rates above current estimates for unstimulated wells. We completed our first well using this new stimulation technology in June 2006, and to date have completed four wells using this new technology, and we have experienced production of significantly higher rates than has been experienced using unstimulated production techniques.

We have 58 productive wells with production to date of 52 Bcfe. We have completed 21 of 22 wells we have drilled in the James Lime since June 2002.

In addition to the James Lime play we started developing the lower Cretaceous Fredericksburg (or Edwards) formation using horizontal drilling. The Fredericksburg formation has a vertical depth of approximately 3,100 feet, and we drill several laterals of up to 5,000 feet in each completed well. A typical Fredericksburg well can be drilled and completed for approximately $1.1 million. Our wells in this area have average proved reserves of 1.1 Bcfe and an average initial flow of 800 Mcfe/d. Fredericksburg wells are also drilled underbalanced with water and completed with no stimulation. The productive thickness ranges from six to 38 feet with the average porosity over 20%. We have completed seven of eight wells in the Fredericksburg, and we have identified 110 additional drillable locations, of which 39 locations have been identified as proved undeveloped.

Additional deep potential on our acreage includes the Travis Peak sands, which have a vertical depth of approximately 7,200 feet. Other shallow productive horizons include the Saratoga Chalk, Annona Chalk, Blossom and Paluxy fluvial sands. The Glen Rose, Mooringsport and Pettet formations are being exploited using horizontal drilling in adjacent counties.

The majority of our drilling in East Texas will be developmental drilling. We have allocated $34 million for 2006, of which we have spent $15.2 million as of June 30, 2006, and $36 million for 2007 for developmental drilling in East Texas.

Hugoton Field

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 Amoco. 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 substantial majority of the 31 Tcf of gas produced from the field was sold at prices under $2 per Mcf, 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 acquired our rights to develop the Hugoton's deeper potential through our acquisition of Presco Western, LLC in April 2005. We are a party to a farmout agreement with a subsidiary of BP Amoco covering approximately 651,000 gross acres in the Hugoton field, which terminates in 2013. We are currently in negotiations to extend our Hugoton farmout past 2013. In the event we are unable to extend this farmout, we intend to partner with other industry participants to develop our remaining acreage before 2013. Through this farmout agreement, we have one of the largest acreage positions in the Hugoton field. The farmout grants us the right to all mineral interests that we develop below the Heebner Shale as long as we fulfill our obligation to drill a minimum of 10 exploratory wells per year. Certain expenditures we make for seismic and geophysical work can be substituted for a portion of our exploratory drilling obligations. We receive a 640-acre assignment for each gas well we complete and a 160-acre assignment for each oil well we complete. We expect to be able to downspace drilling to 320 acres per well for gas wells and 40 acres per well for oil wells. 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 drill all of our Hugoton wells to the base of the deepest known producing formation in the area.

In the 18 months we have held our Hugoton acreage, we have already identified three waterfloods, and 392 potential drilling locations, covering only 40,000 out of our total of 651,000 acres. We have increased production from 2 MMcfe/d to over 8 MMcfe/d through the drilling of 30 wells and participating in three farmouts with only five dry holes. We intend to exploit waterflood potential in the field as well as the stacked pay potential. The primary targets are Morrow and Chester Valley sands which can be detected seismically. Drilling and completion costs in the field are currently $480,000 per well. The average initial flow rate of our wells drilled in the Hugoton Deep has been 623 Mcfe/d, and the average proved reserves attributable to these wells is approximately 0.7 Bcfe. Our development budget for Kansas is $19 million for 2006, of which we have spent $4.7 million as of June 30, 2006, and $22 million for 2007.

Corporate Information

Ellora Energy Inc. 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 $800,000 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 $6.3 million from certain of the selling stockholders for repayment of loans from us, including accrued and unpaid interest thereon. 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 and 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. Third-party valuations were used to provide a valuation comparison of the two companies. 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. Information presented in the financial statement section of this prospectus, which begins on page F-1, does not reflect these new share calculations except for weighted average share calculations and earnings per share calculations.

Ellora Energy Inc., a Delaware corporation, was incorporated in June 2002. Our principal executive offices are located at 5480 Valmont, Suite 350, Boulder, Colorado 80301. Our telephone number is (303) 444-8881. Our corporate website address iswww. .

THE OFFERING

Common stock offered by the selling stockholders		11,623,261 shares.
Common stock to be outstanding after this offering(1)		shares.
Use of proceeds		We will not receive any proceeds from the sale of the shares of common stock offered in this prospectus.
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."
Proposed Nasdaq Global Market symbol		"LORA"

(1): Assumes the issuance of shares of our common stock in our initial public offering. Excludes options to purchase 2,692,293 shares of our common stock outstanding as of October 31, 2006, of which 1,914,520 were exercisable within 60 days.

SUMMARY COMBINED HISTORICAL FINANCIAL DATA

The following table shows the combined historical financial data as of and for each of the three years ended December 31, 2003, 2004 and 2005, the unaudited pro forma financial data for the year ended December 31, 2005, and the unaudited combined historical financial data as of and for each of the six-month periods ended June 30, 2005 and 2006 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 financial statements and related notes included elsewhere in this prospectus. The historical combined financial data as of December 31, 2004 and 2005 and for the three fiscal years ended December 31, 2003, 2004 and 2005 were derived from the combined audited financial statements included in this prospectus. The data for the six-month periods ended June 30, 2005 and 2006 were derived from the unaudited combined interim financial statements also included in this prospectus. The unaudited pro forma financial data for the year ended December 31, 2005 were derived from the unaudited pro forma financial statements included in this prospectus and show the pro forma effect of our acquisition of Presco Western, LLC and the Shelby County Acquisition Properties in 2005. The summary combined historical results are not necessarily indicative of results to be expected in future periods.

												Six Months Ended June 30,
			Year Ended December 31,
			Year Ended December 31,							Pro Forma Year Ended December 31, 2005
			2003			2004		2005		Pro Forma Year Ended December 31, 2005		2005		2006
												(Unaudited)
			(In thousands, except per share data)
Operating Results Data
Revenue
	Oil and gas sales		$	11,810		$	22,780	$	47,595	$	51,789	$	16,146	$	26,824
	Gas aggregation, pipeline sales and other			365			1,491		5,487		6,499		2,169		4,874

		Total revenue		12,175			24,271		53,082		57,288		18,315		31,698
Costs and expenses
	Lease operating expense			2,580			4,539		6,141		6,661		1,718		5,770
	Production taxes			473			1,291		1,813		1,944		321		602
	Gas aggregation and pipeline cost of sales			—			1,316		4,020		4,020		1,210		2,111
	Depreciation, depletion and amortization			1,432			3,479		8,189		9,732		2,688		4,543
	Exploration			—			—		422		422		—		284
	General and administrative			2,497			3,407		11,766		11,989		8,476		4,284
	Interest			219			355		716		1,778		268		1,032

		Total costs and expenses		7,201			14,387		33,067		36,546		14,681		18,626

Income before provision for income taxes				4,974			9,884		20,015		20,742		3,634		13,072
Current income tax expense				(254	)		—		—		—		—		—
Provision for deferred income taxes				2,053			3,850		9,234		9,510		3,226		5,241

Cumulative effect of accounting change				30			—		—				—		—

Net income			$	3,205		$	6,034	$	10,781	$	11,232	$	408	$	7,831

Basic income per share			$	0.15		$	0.22	$	0.28		0.29		0.01		0.19
Diluted income per share			$	0.15		$	0.22	$	0.27		0.28		0.01		0.18
Weighted average number of shares of common stock – basic				21,691,999			27,541,033		38,754,598		38,754,598		35,198,989		42,310,871
Weighted average number of shares of common stock – diluted				21,915,302			27,945,641		40,089,555		40,089,555		30,161,260		44,055,137

		Year Ended December 31,									Six Months Ended June 30,
		2003			2004			2005			2005			2006
		(In thousands, except per share data)									(Unaudited)
Balance Sheet Data
Property and equipment, net, successful efforts method		$	44,566		$	70,811		$	170,094					$	193,807
Total assets			51,681			80,206			192,300						211,187
Notes payable			6,333			10,683			25,750						30,940
Stockholders' equity			37,423			51,757			131,669						142,001
Working capital (deficiency)			96			(1,581	)		3,648						519
Other Financial Data
Net cash provided (used) by:
	Operating activities	$	6,746		$	16,313		$	31,322		$	9,666		$	24,383
	Investing activities		(19,165	)		(27,491	)		(107,511	)		(59,621	)		(27,539	)
	Financing activities		10,448			12,350			76,602			53,567			4,206
EBITDAX(1)		$	6,655		$	13,718		$	34,199		$	11,447		$	19,632

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

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, 2003, 2004 and 2005 and for the six months ended June 30, 2006:

								Six Months Ended June 30, 2006
		Year Ended December 31,
		2003		2004		2005
Gross wells
	Drilled		6		14		23		18
	Completed		6		14		20		15
Net wells
	Drilled		4.5		9.7		21.6		17.5
	Completed		4.5		9.7		18.6		14.5
Net production data
	Net volume (MMcfe)		2,872		4,449		6,098		3,762
	Average daily volume (MMcfe/d)		7.9		9.9		15.7		20.8
Average sales price (per Mcfe)
	Average sales price (without hedge)	$	4.03	$	5.12	$	7.81	$	7.13
	Average sales price (with hedge)		4.03		5.12		7.79		7.90
Expenses (per Mcfe)
	Lease operating	$	0.90	$	1.02	$	1.23	$	1.53
	Production and ad valorem taxes		0.16		0.29		0.30		0.16
	General and administrative		0.87		0.77		1.93		1.14
	Depreciation, depletion and amortization		0.50		0.78		1.34		1.21

Estimated Reserve Data

The estimates in the table below of proved reserves as of December 31, 2005 are based on a reserve report prepared by us and audited by MHA Petroleum Consultants, Inc. and on a reserve report as of June 30, 2006 prepared by MHA.

			As of December 31, 2005		As of June 30, 2006
Estimated Proved Reserves
	Gas (Bcf)			217		236
	Oil (MMBbls)			10		8

		Total proved reserves (Bcfe)		277		281

	Total proved developed reserves (Bcfe)			65		94
PV-10 value (millions)(1)
	Proved developed reserves		$	195	$	201
	Proved undeveloped reserves			470		286

		Total PV-10 value	$	665	$	487

(1): Based on June 30, 2006 NYMEX spot prices of $6.10 per MMBtu of gas and $73.93 per Bbl of oil and December 31, 2005 prices of $9.00 per MMBtu of gas and $60.00 per Bbl of oil, respectively, each adjusted for basis and held flat for the life of the reserves and adjusted for quality differentials. See "Selected Combined 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 significantly affect our financial results and impede our growth.

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 more than 84% of our estimated proved reserves as of June 30, 2006 were gas reserves, our financial results are more sensitive to movements in gas prices. In the past, the price of gas has been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2005, the NYMEX natural gas spot price ranged from a high of $15.39 per MMBtu to a low of $5.50 per MMBtu. The NYMEX natural gas spot price at December 31, 2005 was $11.23 per MMBtu and on June 30, 2006 it was $6.10 per MMBtu. At October 31, 2006, the NYMEX spot gas price was $7.53 per MMBtu. 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. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition, results of operations and cash flows.

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

Drilling and exploration are the main methods we utilize to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration 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.

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 often 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 conclusively 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.

In addition, we are utilizing a new frac technology to enhance our recoveries from our James Lime properties in East Texas. We have used a variation of this technology on four wells and there can be no assurance that it will be as effective (or effective at all) as we currently expect it to be.

In addition, higher oil and gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.

The credit default of one of our customers could have an 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 any of these customers of their contractual obligations under the various contracts. A customer's default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to the customer, or due to circumstances caused by other market participants having a direct or indirect relationship with such counterparty. We seek to mitigate the risk of default by evaluating the financial strength of potential customers and utilizing industry standard credit provisions in our contracts, however, despite our mitigation efforts, defaults by customers may occur from time to time, and this could negatively impact our results of operations, financial position and cash flows.

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. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be affected adversely. 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.

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 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.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve reports. These differences may be material.

The proved oil and gas reserve information included in this prospectus represents estimates. 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, 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:

•: 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 June 30, 2006, approximately 69% 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.

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 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 us 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, then our PV-10 as of June 30, 2006 would decrease from $487 million to $403 million.

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

At October 31, 2006 our bank debt outstanding was approximately $10.0 million. We intend to use a portion of the proceeds from our initial public offering to repay the outstanding balance under our credit facility. The borrowing base limitation under our credit facility is redetermined semi-annually. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, as is typical in the oil and gas industry, 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. Many of these factors are beyond our control. 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 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 are subject to complex government regulation which could adversely affect our operations.

Our activities are subject to complex and stringent environmental and other governmental laws and regulations. The exploration and production of oil and gas requires numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, also known as the "EPA," and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits, approvals and certificates issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective actions, and the issuance of injunctions limiting or preventing some or all of our operations. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us that could have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project.

We depend on our management and employees.

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 or of several employees with critical skills 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.

Our results are subject to quarterly and seasonal fluctuations.

Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including:

•: seasonal variations in oil and gas prices;
•: variations in levels of production; and
•: the completion of exploration and production projects.

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

Market conditions, the unavailability of satisfactory oil and gas processing and transportation may hinder our access to oil and gas markets or delay our production. Although currently we control the pipeline operations for all of our production in East Texas, we do not have such control in other areas in which we conduct operations. 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 in many cases we are 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, or may have to transport by more expensive means, the oil and gas production from wells or we may be required to shut in gas wells or delay initial production until the necessary gather 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 or 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 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. We also require capital to fund our capital budget, which is expected to be approximately $130 million for 2007. As of June 30, 2006, approximately 67% of our total estimated proved reserves were undeveloped. 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. There can be no assurance that our lender will provide this consent or as to the availability or terms of any additional financing. 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 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 has increased substantially during the last two years. We are particularly sensitive to higher rig costs and drilling rig availability, as we presently have 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.

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. 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 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;
•: explosions;
•: uncontrollable flows of oil, gas or well fluids;
•: fires;
•: pollution; and
•: releases of toxic gas.

The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties.

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. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liabilities. 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. Consistent with insurance coverage generally available to the industry, 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. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. 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, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

Environmental liabilities may expose us to significant costs and liabilities.

There is inherent risk of incurring 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. 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 production or our operations or financial position. We may not be able to recover some or any of these costs from insurance. See "Business—Environmental Matters."

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.

We engage in hedging transactions which involve risks that can harm our business.

To manage our exposure to price risks in the marketing of our oil and gas production, we enter into oil and gas price hedging agreements. While intended to reduce the effects of volatile oil and gas prices, such transactions may limit our potential gains and increase our potential losses if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than expected, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement or the counterparties to the hedging agreements fail to perform under the contracts.

The requirements of complying with the Exchange Act may strain our resources and distract management.

As a public company we will be subject to the reporting requirements of the Exchange Act and the Sarbanes-Oxley Act. In addition, The Nasdaq Global Market requires changes in corporate governance practices of public companies. These requirements may place a strain on our systems and resources and we will incur significant legal, accounting and other expenses that we did not incur in the past. The Exchange Act requires that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires that we maintain effective disclosure controls and procedures, corporate governance standards and internal controls over financial reporting. Significant resources and management oversight will be required as we may need to devote additional time and personnel to legal, financial and accounting activities to ensure our ongoing compliance with public company reporting requirements. The effort to prepare for these obligations may divert management's attention from other business concerns, which could have a material adverse affect on our business, financial condition, results of operations or cash flows.

Failure by us to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could in turn have a material adverse effect on our business and stock price.

Under current rules of the SEC, we will be required to document and test our internal control over financial reporting so that our management can certify as to the effectiveness of our internal control over financial reporting and our independent registered public accounting firm can render an opinion on management's assessment. We are in the process of documenting our internal controls systems to allow management to evaluate and report on, and our independent auditors to audit, our internal controls over financial reporting. Once the documentation is complete, we will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply with Section 404 for the year ending December 31, 2007. However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a "material weakness" or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A "material weakness" is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our consolidated financial statements, and our stock price may be adversely affected as a result. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our stock price may be adversely affected.

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 61.3% of our outstanding common stock. Contemporaneously with this offering, we are conducting an initial public offering of shares of our common stock. After

giving effect to our initial public offering, Yorktown will continue to beneficially own approximately % of our outstanding common stock. In addition, two Yorktown representatives serve on our board of directors, and our officers and their affiliates will beneficially own or control approximately % of our common stock outstanding. See "Security Ownership of Certain Beneficial Owners and Management." As a result of this ownership, Yorktown will have the ability to nominate all of 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.

Risks Related to this Offering

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.

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 million shares of common stock and 10 million 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.

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 recently filed a registration statement to register shares of our common stock in an underwritten initial public offering. The sale of the shares of common stock in this public offering 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 our initial public offering, we will have approximately million shares of common stock issued and outstanding, including approximately 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 -day lock-up period that is applicable to our executive officers, directors, and certain of our stockholders following the completion of our initial public offering. All of the shares of the common stock sold in our initial public 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 our initial public offering. Additionally, we may file one or more

registration statements with the Securities and Exchange Commission providing for the registration of up to approximately 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.

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.

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 U.S. Securities and Exchange Commission, or 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 ended December 31, 2007, we will need to document and test our internal control procedures, our management will need to assess and report on our internal control over financial reporting and our independent accountants will need to issue an opinion on that assessment and 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;
•: 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 will not receive any of the proceeds from the sale of the shares of common stock offered by the selling stockholders under this prospectus. Any proceeds from the sale of the shares pursuant to this prospectus will be received by the selling stockholders.

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 June 30, 2006 on an actual historical basis and on an as adjusted basis after giving effect to:

•: our private equity offering in July 2006; and
•: on an as adjusted basis to give effect to the issuance and sale by us of shares of common stock in our initial public offering and the application of the net proceeds therefrom.

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

			As of June 30, 2006
			Actual			As Adjusted
			(In thousands)
Cash			$	4,211		$

Notes payable			$	30,940		$

Stockholders' equity:
	Common stock		$	4		$
	Additional paid-in capital			117,751
	Subscriptions receivable and accrued interest			(6,425	)
	Retained earnings			28,649
	Accumulated other comprehensive income			2,022

		Total stockholders' equity	$	142,001		$

Total capitalization			$	172,941		$

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

On April 29, 2005, we completed our acquisition of Presco Western, LLC, which was a party to a farmout of 651,000 gross (631,000 net) acres in the Hugoton field in Kansas for approximately $45 million in cash. On August 31, 2005 we acquired additional interests in existing properties located in Shelby County, Texas (the "Shelby County Acquisition Properties") from one of our minority stockholders for $26 million in cash.

The following unaudited pro forma financial information shows the pro forma effect of the acquisition of Presco Western and the Shelby County Acquisition Properties. A pro forma balance sheet has not been presented since the acquisitions were reflected in the December 31, 2005 balance sheet of Ellora Energy Inc. and Affiliated Entities, located elsewhere in this prospectus. The unaudited pro forma statement of operations for the year ended December 31, 2005 was prepared as if the acquisitions had occurred at January 1, 2005.

The accompanying financial statements for Presco Western, LLC were derived from the historical accounting records of the sellers. The accompanying statements of revenues and direct operating expenses for the Shelby County Acquisition Properties were derived from our historical accounting records as we were the operator of these properties prior to the acquisition of the additional interest. Although the statements of revenue less direct operating expense for the Shelby County Acquisition Properties do not include depreciation, depletion and amortization, income taxes or interest expense as described in Note 1, these costs have been included on a pro forma basis. No pro forma general and administrative expenses were incurred as a result of the acquisition of the Shelby County Acquisition Properties, as Ellora was the operator of the properties prior to the Shelby County Acquisition.

The following unaudited pro forma financial statements do not purport to represent what our results of operations would have been if this acquisition had occurred on January 1, 2005. These unaudited pro forma financial statements should be read in conjunction with our historical financial statements and related notes for the periods presented.

UNAUDITED CONDENSED PRO FORMA STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2005
(in thousands, except per share data)

				Ellora Energy Inc. Combined Year Ended December 31, 2005			Presco Western, LLC Three Months Ended March 31, 2005		Shelby County Acquisition Properties Six Months Ended June 30, 2005		Pro Forma Adjustments (Note 1)			Pro Forma Combined Year Ended December 31, 2005
Revenue:
	Oil and gas sales			$	47,595		$	1,635	$	2,559	$	—		$	51,789
	Gas aggregation and pipeline sales				5,586			—		—		—			5,586
	(Loss) on oil and gas hedging activities				(115	)		—		—		—			(115	)
	Interest income and other				16			12		—		—			28

			Total revenue		53,082			1,647		2,559		—			57,288

Costs and Expenses:
	Lease operating expense				6,141			241		279		—			6,661
	Production taxes				1,813			60		71		—			1,944
	Gas aggregation and pipeline cost of sales				4,020			—		—		—			4,020
	Depreciation, depletion and amortization				8,189			81		—		1,462			9,732
	Exploration				422			—		—		—			422
	General and administrative				11,766			223		—		—			11,989
	Interest expense				716			—		—		1,062			1,778

		Total costs and expenses			33,067			605		350		2,524			36,546

Income Before Taxes					20,015			1,042		2,209		(2,524	)		20,742
	Deferred income tax expense				(9,234	)		—		—		(276	)		(9,510	)

Net Income				$	10,781		$	1,042	$	2,209	$	(2,800	)	$	11,232

Earnings (loss) per share – basic				$	0.28									$	0.29
Earnings (loss) per share – diluted				$	0.27									$	0.28

Weighted average common shares outstanding – basic					38,756										38,756

Weighted average common shares outstanding – diluted					40,090										40,090

See accompanying notes to these financial statements.

NOTES TO THE UNAUDITED FORMA STATEMENTS OF OPERATIONS

1. PRO FORMA ADJUSTMENTS FOR THE YEAR ENDED DECEMBER 31, 2005:

The accompanying unaudited pro forma statement of operations for the year ended December 31, 2005 assumes that the acquisitions of Presco Western, LLC and the Shelby County Acquisition Properties occurred as of January 1, 2005. The following adjustments have been made to the accompanying pro forma statement of operations for the year ended December 31, 2005:

Depletion, Depreciation and Amortization—To record pro forma depletion expense giving effect to the acquisitions of Presco Western, LLC and the Shelby County Acquisition Properties. The expense was calculated using estimated proved reserves as of the beginning of the period, production for the applicable periods, and the purchase price of $45,000,000 and $26,000,000, respectively. No portion of either purchase price was allocated to unproved properties.

Interest Expense—To record interest expense for additional debt and debt issuance costs incurred in connection with the Shelby County Acquisition Properties using historical rates paid during the period from January 1, 2005 through the date of acquisition, which approximated 6.13%. Each¹/8% change in the interest rate would affect income before taxes by $33,000 for the year.

Income Taxes—To record income taxes related to pre tax income from the acquisition of Presco Western, LLC and the Shelby County Acquisition Properties for the year ended December 31, 2005, based on our effective tax rate of 38%.

SELECTED COMBINED HISTORICAL FINANCIAL DATA

The following table shows the selected combined historical financial data as of and for each of the four years ended December 31, 2002, 2003, 2004 and 2005 and the unaudited selected combined historical financial data as of and for each of the six-month periods ended June 30, 2005 and 2006 for Ellora Energy Inc. You should read the following summary combined historical financial information together with the combined financial statements and related notes included elsewhere in this prospectus. The selected historical consolidated financial and operating data for the three years ended December 31, 2003, 2004 and 2005 are derived from our audited financial statements included herein. The selected historical consolidated financial and operating data for the year ended December 31, 2002 was derived from our financial statements not included herein. The data for the six-month periods ended June 30, 2005 and 2006 were derived from the unaudited combined interim financial statements also included in this prospectus. The summary combined historical results are not necessarily indicative of results to be expected in future periods.

			Period from Inception April 1, 2002 to December 31, 2002									Six Months Ended June 30,
					Year Ended December 31,							Six Months Ended June 30,
					2003		2004			2005		2005		2006
												(Unaudited)
			(In thousands, except per share data)
Operating Results Data
Revenue:
	Oil and gas sales		$	5,167	$	11,810	$	22,780		$	47,595	$	16,146	$	26,824
	Gas aggregation, pipeline sales and other			431		365		1,491			5,487		2,169		4,874

		Total revenue		5,598		12,175		24,271			53,082		18,315		31,698
Costs and expenses:
	Lease operating expense			1,260		2,580		4,539			6,141		1,718		5,770
	Production taxes			358		473		1,291			1,813		321		602
	Gas aggregation and pipeline cost of sales			—		—		1,316			4,020		1,210		2,111
	Depreciation, depletion and amortization			1,557		1,432		3,479			8,189		2,688		4,543
	Exploration			—		—		—			422		—		284
	General and administrative			929		2,497		3,407			11,766		8,476		4,284
	Interest			155		219		355			716		268		1,032

		Total costs and expenses		4,259		7,201		14,387			33,067		14,681		18,626

Income before provision for income taxes				1,339		4,974		9,884			20,015		3,634		13,072
Current income tax expense (benefit)				298		(254)		—			—		—
Provision for deferred income taxes				243		2,053		3,850			9,234		3,226		5,241

Cumulative effect of accounting change				—		30		—			—		—		—
Net income			$	798	$	3,205	$	6,034		$	10,781	$	408	$	7,831

Net income per common share:
	Basic		$	0.04	$	0.15	$	0.22		$	0.28	$	0.01	$	0.19
	Diluted		$	0.04	$	0.15	$	0.22		$	0.27	$	0.01	$	0.18
Balance Sheet Data
Property and equipment, net, successful efforts method			$	26,354	$	44,566	$	70,811		$	170,094			$	193,807
Total assets				39,805		51,681		80,206			192,300				211,187
Notes payable				5,783		6,333		10,683			25,750				30,940
Stockholders' equity				24,320		37,423		51,757			131,669				142,001
Working capital (deficiency)				2,032		96		(1,581	)		3,648				519

		Period from Inception April 1, 2002 to December 31, 2002											Six Months Ended June 30,
					Year Ended December 31,								Six Months Ended June 30,
					2003		2004			2005			2005		2006
													(Unaudited)
		(In thousands)
Other Financial Data
Net cash provided (used) by:
	Operating activities	$	3,769		$	6,746	$	16,313		$	31,322		$	9,666	$	24,383
	Investing activities		(18,511	)		(19,165)		(27,491	)		(107,511	)		(59,621)		(27,539)
	Financing activities		18,289			10,448		12,350			76,602			53,567		4,206
EBITDAX(1)		$	3,051		$	6,655	$	13,718		$	34,199		$	11,447	$	19,632

(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 PV-10 to our standardized measure of discounted future net cash flows (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 December 31, 2005
PV-10		$	664,740
	Less: Undiscounted income taxes		(540,603	)
	Plus: 10% discount factor		307,523

Discounted income taxes			233,080

Standardized measure of discounted future net cash flows		$	431,660

The following table reconciles our net income to EBITDAX. EBITDAX is defined as net income or loss excluding income tax, non-cash compensation, exploration costs, depreciation, depletion and amortization and interest expense. Although EBITDAX is not calculated in accordance with generally accepted accounting principles (GAAP), management believes that it is a widely accepted financial indicator that provides additional information about our profitability, ability to meet our future requirements for debt service, capital expenditures and working capital. EBITDAX 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. Our definition of EBITDAX may not be comparable to similarly titled measures other companies use.

		Period from Inception April 1, 2002 to December 31, 2002							Six Months Ended June 30,
			Year Ended December 31,						Six Months Ended June 30,
			2003		2004		2005		2005		2006
									(Unaudited)
		(In thousands)
Net income		798	$	3,205	$	6,034	$	10,781	$	408	$	7,831
	Income taxes	541		1,799		3,850		9,234		3,226		5,241
	Non-cash compensation	—		—		—		4,857		4,857		701
	Exploration	—		—		—		422		—		284
	Depreciation, depletion and amortization	1,557		1,432		3,479		8,189		2,688		4,543
	Interest	155		219		355		716		268		1,032

EBITDAX		3,051	$	6,655	$	13,718	$	34,199	$	11,447	$	19,632

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 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 80 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 131 Bcfe of proved reserves for approximately $113 million. During 2005, excluding acquisitions, we replaced approximately 312% of our production organically. The reserve additions were driven by the continued development and exploration of the Huxley and East Bridges fields in East Texas and by the 3-D seismic supported drilling in the Hugoton field in southwest Kansas. During 2005, we participated in the drilling of 23 wells of which 20 were successfully completed for a success rate of 87%. Additionally, during the six months ended June 30, 2006, we drilled 18 wells, 15 of which were successfully completed for a success rate of 83%.

We continually evaluate opportunities to expand our position in our core areas. Since inception, we have closed three additional East Texas acquisitions: two consisting of reserve acquisitions, and the third increasing our pipeline ownership to 100%. The total cost of these acquisitions was approximately $41.7 million.

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.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our combined financial statements, which have been prepared in accordance with accounting policies generally accepted in the United States of America. The preparation of our combined 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 financial statements. Described below are the most significant policies we apply in preparing our combined 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.
•: Dry holes for exploratory wells are expensed. Dry holes for developmental wells are 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 change the overall evaluation of reservoirs.

Our estimated proved reserves as of December 31, 2005 were prepared by us and audited by MHA Petroleum Consultants, Inc. and our estimated proved reserves as of June 30, 2006 were prepared by MHA.

Derivative Instruments and Hedging Activities

We enter into derivative contracts, primarily puts, 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

On December 16, 2004, the Financial Accounting Standards Board ("FASB") published Statement of Financial Accounting Standards No. 123 (Revised 2004), "Share Based Payment" ("SFAS 123(R)"). SFAS 123(R) requires that compensation cost related to share based payment transactions be

recognized in the financial statements. Share based payment transactions within the scope of SFAS 123(R) include stock options, restricted stock plans, performance based awards, stock appreciation rights, and employee share purchase plans. The provisions of SFAS 123(R) were effective for us as of the first annual reporting period beginning after December 15, 2005. Accordingly, we implemented the revised standard in the first quarter of 2006.

In March 2005, the Financial Accounting Standard Board (FASB) issued FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations. This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143). A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside our control. FIN 47 states that we must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This interpretation is intended to provide more information about long-lived assets, future cash outflows for these obligations, and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

In February 2006, the FASB issued FAS No. 155, "Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140" ("FAS 155"). FAS 155 eliminates the exemption from applying FASB Statement No.133 to interests in securitized financial assets. FAS 155 is effective for the first fiscal year end that begins after September 15, 2006, which for us will be January 1, 2007. We do not believe adoption of FAS 155 will have a material impact on our financial position or results of operations.

In June 2006, the FASB issued Interpretation No. 48, "Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109" ("FIN 48"). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 will become effective for us on January 1, 2007. We are currently evaluating the impact of adopting FIN 48 on our financial position and results of operations.

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.

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, 2003, 2004 or 2005 and the six months ended June 30, 2006. 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 our initial public 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 our initial public 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, together with corollary increases in related income and expenses.

In April 2004, we acquired the 75% of the English Bay pipeline in East Texas that we did not own which increased our revenue and expenses related to our gas gathering assets in subsequent periods.

Six Months Ended June 30, 2005 and 2006

		Six Months Ended June 30,
		2005		2006
Net Production (MMcfe)			2,556		3,762
Average Sales Prices (per Mcfe) (before hedging)		$	6.32	$	7.13
Costs and expenses (in thousands):
	Lease operating expenses	$	1,718	$	5,770
	Production taxes		321		602
	Depreciation, depletion and amortization		2,688		4,543
	General and administration		8,476		4,284

Oil and Gas Sales. Our oil and gas revenues increased $10.7 million to $26.8 million in the first six months of 2006 as compared to the first six months of 2005. Sales are a function of sales volumes and average sales prices. Our gas volumes increased 30% and our oil volumes increased 247% between periods. The volume increases resulted from acquisitions completed in 2005 and successful drilling activities over the past year that produced new sales volumes that more than offset natural production decline. Our average price for gas increased 5% and our average price for oil increased 25% between periods before the effects of hedging.

Gas Aggregation and Pipeline Sales. Gas aggregation and pipeline sales increased from $1.2 million to $2.1 million in the first six months of 2006 compared to the first six months of 2005 as a result of increased volumes of third party gas being transported and 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.

Gain on Oil and Gas Hedging Activities. In September 2005 we acquired puts at $11 and $10 per MMBtu for approximately 10% to 20% of our anticipated production in all months for the period October 2005 through January 2007 except April 2006. With the decline in natural gas prices, we recorded a $2.4 million gain as a result of these hedges during the six months ended June 30, 2006.

Lease Operating Expenses. Our lease operating expenses increased $3.7 million for the first six months of 2006 from the previous comparative period. The increase is primarily from costs associated with the new property acquisitions in 2005, the increased costs associated with oil field goods and services, and the expenses incurred applicable to workover operations associated with reentering a producing well to install hardware applicable to stimulation of an existing well.

Production Taxes. 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 in various taxing authorities. During both years, we applied for and received significant refunds of production taxes for wells drilled in previous years. The tax amounts reflected in the accompanying financial statements are significantly below the anticipated rates due to refunds received.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expenses increased to $4.5 million for the six months ended June 30, 2006, an increase of $1.9 million from the comparative period in 2005. Almost all of this increase is a result of increased production derived from acquisition activity in 2005 and drilling activity over the last 12 months.

Exploration. We did not drill any dry holes associated with exploratory wells during the six months ended June 30, 2006. Exploration costs were nominal for the six months ended June 30, 2006. Almost all of our leasehold positions are held by production, and thus we have nominal delay rental expenses.

General and Administrative. General and administrative costs declined from $8.5 million in 2005 to $4.3 million in 2006. In 2005, we granted shares of our common stock and modified a stock option agreement that required us to record $4.9 million as compensation expense because the shares were issued at a discount to fair market value.

We have added significant personnel over the last 12 months. General and administrative costs, not including non-cash compensation, have remained relatively the same as personnel replaced and reduced the need for outside consultants and advisors.

Interest. Interest expense increased from $0.3 million in 2005 to $1.0 million in 2006. Interest costs are a function of amounts borrowed and the effective rate for borrowing. Average borrowed amounts outstanding increased over the last 12 months, and interest rates increased over that period of time as well.

Income Taxes. Income tax expense increased from $3.2 million in 2005 to $5.2 million in 2006. Income taxes reflect the amount of taxable income calculated for financial reporting multiplied by an effective tax rate. Our tax cost increased in 2006, as our net income before tax increased dramatically from $3.6 million to $13.1 million. However, income tax did not increase proportionately due to the 2005 non-cash stock compensation of $4.9 million not being considered a tax-deductible item.

Year Ended December 31, 2004 and 2005

		Year Ended December 31,
		2004		2005
Net Production (MMcfe)			4,449		6,098
Average Sales Prices (per Mcfe) (before hedging)		$	5.12	$	7.81
Costs and expenses (in thousands):
	Lease operating expenses	$	4,539	$	6,141
	Production taxes		1,291		1,813
	Depreciation, depletion and amortization		3,479		8,189
	General and administration		3,407		11,766

Oil and Gas Sales. Oil and gas sales increased from $22.8 million to $47.6 million as a result of increased production from acquisitions made in 2005 and the success of our 2005 drilling program with 20.0 (18.6 net) successful wells out of a total of 23 wells drilled (21.6 net). In addition to a 37% increase in production, the average price for natural gas received by us increased 53% from $5.12 per Mcfe to $7.81 per Mcfe. The increase in the price of gas was the most significant factor in the increased oil and gas revenue. Natural gas sales represented 90% of total oil and gas sales in 2005 compared to 97% in 2004 as our Kansas operations acquired in 2005 have oil sales whereby our East Texas operations are almost all natural gas.

Gas Aggregation and Pipeline Sales. These revenues increased from $1.1 million in 2005 to $5.6 million in 2005 as a result of our acquisition of the remaining 75% ownership of the English Bay Pipeline in 2004. Total throughput of the pipeline increased from 8,403 MMcf in 2004 to 11,640 MMcf in 2005, with 60% of this throughput being from third parties.

Hedging Activities. We had nominal hedging activity in 2005, and the loss of $115,000 reflects the premiums paid for floors offset by nominal payments from the third party trading company providing the hedging contracts. We had no hedging activity in 2004.

Interest Income and Other. Interest income and other revenues in 2005 declined from $272,000 in 2004 to $16,000 in 2005 as a result of significantly less excess cash balances available to us. Amounts invested by stockholders in 2004 created short term investments until acquisitions in 2004 were closed.

Equity Investment Income. The equity investment income in 2004 reflects the net income of English Bay Pipeline for the period we were a 25% owner of English Bay Pipeline. In April 2004, we acquired the remaining 75% interest in the English Bay Pipeline.

Lease Operating Expense. Lease operating expense increased as production increased. Our production increased 48% and the lease operating expenses increased from $4.5 million in 2004 to $6.1 million in 2005, an increase of 35%.

Production Taxes. The increase from $1.3 million in 2004 to $1.8 million in 2005 is a function of increased production and increased pricing offset by credits received applicable to prior years. These credits amounted to $0.6 million in 2005.

Gas Aggregation and Pipeline Cost of Sales. Costs in 2005 increased with revenues as we owned and operated the pipeline for a complete year in 2005. Costs in 2004 exceeded revenues, as we incurred significant costs to upgrade our pipeline operations and incurred significant costs to reengineer and move a significant portion of our leased compressor capacity. As a result of these improvements and increased revenues, revenues exceeded expenses in 2005.

Depreciation, Depletion and Amortization. (DD&A) We had increased production in 2005 from 2004 which was reflected in an increased DD&A charge from $3.5 million in 2004 to $8.2 million in 2005. In addition, the charge per unit of production increased from $0.78 per Mcfe in 2004 to $1.34 in 2005.

Exploration. We hold almost all of our leasehold interest by production and thus incur nominal delay rentals. We had nominal charges in 2005 for geological evaluation costs and incurred no dry hole costs associated with exploratory drilling during the year. There were no exploration or geological evaluation charges in 2004.

General and Administrative. Costs increased significantly from 2004 to 2005 increasing from $3.4 million to $11.8 million in 2005. However, $4.9 million of this increase was applicable to a non-cash stock compensation charge. The increase in general and administrative expense, excluding the non-cash stock compensation charge, was principally due to the significant consulting and professional fees associated with our growth, and increased personnel and costs associated with supporting and housing employees and consultants.

Interest Expense. Interest expense increased $361,000 to $716,000 in 2005. The significant increase was a function of increased borrowings.

Income Taxes. We did not pay income taxes in 2004 or in 2005. The provision for income taxes in 2005 increased due to increased net income and because the non-cash stock expense was not a deductible item. Thus our effective income tax rate in 2005 was 46% compared to the expected 38% rate in 2004.

Year Ended December 31, 2003 and 2004

		Year Ended December 31,
		2003		2004
Net Production (MMcfe)			2,872		4,449
Average Sales Prices (per Mcfe) (before hedging)		$	4.03	$	5.12
Costs and expenses (in thousands):
	Lease operating expenses	$	2,580	$	4,539
	Production taxes		473		1,291
	Depreciation, depletion and amortization		1,432		3,479
	General and administration		2,497		3,407

Oil and Gas Sales. Oil and gas sales increased from $11.8 million in 2003 to $22.8 million in 2004 as a result of acquisitions made in 2004 and the results of our drilling activities during 2004. We drilled and completed six successful wells during the year ended December 31, 2004 in the Huxley field in East Texas. We had no hedging activity in 2003 or 2004.

Gas Aggregation, Pipeline Sales and Equity Investment Income. We acquired the remaining 75% ownership of the English Bay Pipeline in April 2004. The pipeline cost of sales of $1.3 million exceeded revenues of $1.1 million, as we had significant maintenance expenses related to bringing the operation to acceptable levels. We recorded the operations for 2003 and for the first three months of 2004 as equity investment income.

Lease Operating Expense. Lease operating expense increased as production increased. Our production increased 55% and the lease operating expenses increased from $2.6 million in 2003 to $4.5 million in 2004, an increase of 76%.

Production Taxes. The increase from $0.5 million in 2003 to $1.3 million in 2004 is a function of increased production and increased pricing.

Depreciation, Depletion and Amortization. (DD&A) We had increased production in 2004, which was reflected in an increased DD&A charge from $1.4 million in 2003 to $3.5 million in 2004 and the charge per unit of production changed from $0.50 per Mcfe in 2003 to $0.78 per Mcfe in 2004.

General and Administrative. Costs increased 36% from $2.5 million in 2003 to $3.4 million in 2004 as our growth required additional personnel, consultants and the infrastructure to support them.

Interest Expense. Interest increased to $0.4 million in 2004 from $0.2 million in 2003 as the average amount borrowed increased.

Income Taxes. We had an increased income tax expense in 2004 compared to 2003 as net income increased from 2003 to 2004.

Capital Resources and Liquidity

For the six months ended June 30, 2006, the majority of our cash was generated from cash flows from operations and used in our drilling activities. During the same six months in 2005, we raised $53 million from the sale of stock and borrowings and generated $9.6 million from operations, which we used for the acquisition of Presco Western, LLC and our drilling program.

Our primary sources of cash in 2005 were from financing and operating activities. Approximately $71 million in proceeds from the sale of stock 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.

In 2004, cash flow from operations of $16.3 million and proceeds from sale of stock of $8.0 million provided the funds to drill and acquire the remaining 75% of the English Bay Pipeline.

In 2003, operating cash flow of $6.7 million combined with $8.0 million from stock sales and $4.3 of borrowing funded our drilling activities.

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 noted:

	Year Ended December 31,									Six Months Ended June 30,
	2003			2004			2005			2005			2006
	(in thousands)
Cash flows provided by operations	$	6,746		$	16,313		$	31,322		$	9,666		$	24,383
Cash flows used in investing activities		(19,165	)		(27,491	)		(107,511	)		(59,621	)		(27,539	)
Cash flows provided by financing activities		10,448			12,350			76,602			53,567			4,206

Net increase (decrease) in cash and cash equivalents	$	(1,971	)	$	1,172		$	413		$	3,612		$	1,050

Operating Activities

For the six months ended June 30, 2005 and 2006 our cash flow from operations was used for drilling. The $24.4 million in cash flow generated from operations in the first six months of 2006 increased $14.7 million from the first six months of 2005 due to acquisitions and our successful drilling efforts.

Net cash provided by operating activities increased from $6.7 million in 2003 to $16.3 million in 2004 and to $31.3 million in 2005. The increase in 2004 resulted from a combination of increased sales volumes from the acquisitions in the Hugoton field in southwest Kansas, our successful drilling activities and increased commodity prices. Pricing, drilling and the Presco Western, LLC and the additional East Texas acquisitions resulted in the increase in 2005. Average realized prices increased from $6.34 per Mcfe in 2004 to $8.29 per Mcfe in 2005. Our production volumes increased to 5.7 Bcfe in 2005 from 3.6 Bcfe in 2004. As described elsewhere in this prospectus in more detail, we have pricing floor hedges in place for approximately 20% of our anticipated production through January 2007 at approximately $10 per MMBtu.

Investing Activities

As previously stated, the majority of our investment of $27.5 million for the six months ended June 30, 2006 was used for drilling. In the corresponding time period for 2005, we used $45 million for the acquisition of Presco Western, LLC and the remainder of the $59.6 million was used for drilling and leasehold acquisitions.

Our acquisitions, totalling $7 million in 2004 and $71 million in 2005, were the largest portions of our cash used in investment activities. Our drilling and exploration capital expenditures have increased each year from inception: $19 million in 2003, $21 million in 2004 and $34 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 with a subsidiary of BP Amoco. Under this farmout agreement, we can acquire additional mineral rights in reservoirs we develop below the Heebner Shale as long as we fulfill our obligation to drill a minimum of 10 exploratory wells per year. We estimate the cost of this exploration commitment to be approximately $5 million per year. We expect our development budget in this field to be $19 million for all of 2006 and $22 million in 2007.

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 $65 million for 2006 and $70 million in 2007 to be funded from cash flow from operations. We establish these budgets based upon expected volumes produced and commodity prices.

Financing Activities

During the six months ended June 30, 2005 we raised $53.5 million used predominately for the purchase of Presco Western, LLC. In the same period for 2006, our $4.2 million of financing activities were from net borrowing activities.

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 February 2006, we established a new $400 million credit facility with a syndication of six 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 October 31, 2006, we had an outstanding balance under this credit facility of approximately $10 million, with a borrowing base of $110 million. The borrowing base is subject to adjustment twice each year. The assessment by the bank petroleum engineers is based on their evaluation of the future cash flows from proved oil and gas reserves using the bank's pricing parameters.

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 large interest costs and possible debt reductions restricting ongoing operations.

We believe that cash flow from operations will finance all of our anticipated drilling, exploration and capital needs and we will use our credit facility for possible acquisitions, temporary working capital needs and any expansion of our drilling program.

Future Capital Expenditures for 2006 and 2007

The following table summarizes information regarding our estimated 2006 and 2007 capital expenditures. We will be required to meet our needs from our internally generated cash flow, debt financings, and equity financings. The estimated 2006 capital expenditures shown are preliminary full year estimates, including approximately $27 million spent from January 1, 2006 through June 30, 2006. 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.

				Estimated
		Historical		Year Ending December 31,
		Year Ended December 31, 2005		Year Ending December 31,
		Year Ended December 31, 2005		2006		2007
				(In thousands)
Capital expenditures:
	East Texas	$	25,336	$	34,400	$	36,000
	Hugoton		4,565		18,986		21,657
Other			4,034		9,258		8,789
Geological and geophysical			35		4,000		4,000
Growth capital expenditures(1)			—		7,000		60,000

	Total capital expenditures	$	33,970	$	73,644	$	130,446

(1): Growth capital expenditures are for the acceleration of drilling and secondary recovery in addition to capital expenditures contemplated in the reserve report and for possible acquisitions.

Credit Facility

In February 2006, we entered into a new $400 million revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders. The availability of funds under the credit facility is subject to a borrowing base which was initially set at, and currently is, $110 million. The borrowing base will be redetermined every six months or, upon our election, one additional time each calendar year.

The credit facility provides 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 0.75%; or (ii) the London Interbank Offered Rate plus a margin which ranges from 1.25% to 2.0% per annum, as applicable, as amounts outstanding under the credit facility increase as a percentage of the borrowing base. In addition, we pay an annual commitment fee which ranges from 0.3% 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.

We are subject to financial covenants requiring maintenance of a minimum current ratio and a minimum debt to income ratio. In addition, we are 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 properties.

Loans under the credit facility are secured by first priority liens on substantially all of our assets including equity interests in our subsidiaries. All outstanding amounts under the credit facility are due and payable in February 2010.

We anticipate that the proceeds to us from this offering will be used to pay off outstanding indebtedness. As of October 31, 2006, the outstanding balance under the credit facility was $10 million.

Contractual Commitments

We have the contractual obligation to explore the deep mineral interests in the Hugoton field of southwest Kansas. We estimate the minimum cost of this obligation at $5 million per year. We anticipate that we will spend in excess of this minimum amount.

We have executed a letter of intent to contract 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.

We have a lease for our current office space in Boulder, Colorado, that expires in 2010. Our obligation under this lease is approximately $220,000 per year. In October 2006, we signed a five year lease for approximately 21,000 square feet of space in Boulder, Colorado. We will initiate rent payments of approximately $36,000 per month, including common area expenses. We expect to sublet our current office space.

The following table summarizes these commitments as of September 30, 2006:

Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-Term Debt Obligations—Bank Borrowing Facility	$	10,000,000		—		—	$	10,000,000	—
Operating Lease Obligations—Office Leases		2,938,000		400,000		1,854,000		684,000	—
Drill Rig Lease		24,000,000		8,000,000		16,000,000		—	—

Total	$	36,938,000	$	8,400,000	$	17,854,000	$	10,684,000	—

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, primarily puts, to hedge future gas and crude oil production to mitigate portion of the risk of market price fluctuations.

As of June 30, 2006, we had the following outstanding financial natural gas positions:

Contract Type	Weighted Average Strike Price		Quantity	Contract Period
			(MMBtu)
Futures Put	$	10.00	300,000	July 2006
Futures Put	$	10.00	300,000	August 2006
Futures Put	$	10.00	300,000	September 2006
Futures Put	$	10.00	300,000	October 2006
Futures Put	$	10.00	100,000	November 2006
Futures Put	$	10.00	100,000	December 2006
Futures Put	$	10.00	100,000	January 2007

At June 30, 2006 and at December 31, 2005, the fair values of open derivative contracts were assets of approximately $5.0 million and $1.9 million, respectively.

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. 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 794,000 gross (745,000 net) acres providing us with 680 identified drilling locations. At June 30, 2006 we owned interests in 232 gross (144 net) producing wells, and during June 2006 our average net production was approximately 26 MMcfe/d. At June 30, 2006, our estimated total proved oil and gas reserves were approximately 281 Bcfe. Our proved reserves are approximately 84% gas and 33% proved developed. Our total proved reserves have a reserve life index of approximately 37 years, and our proved producing reserves have a reserve life index of 11 years. Using prices as of June 30, 2006, the PV-10 value of our proved reserves had an estimated pre-tax net present value, discounted at 10%, or PV-10, of approximately $487 million, of which 41% was proved developed. See "Selected Combined 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 over 22 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.
•: High Quality, Operated Asset Base. We own a high quality asset base comprised of long-lived reserves along with shorter-lived, higher return reserves. We operate over 90% of our estimated proved reserves. Approximately 84% 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 87,000 gross (70,000 net) acres and in the Hugoton field our BP Amoco farmout covers 651,000 gross (631,000 net) acres. We believe we have assembled a high quality 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 Mcf. 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.
•: Drilling Inventory. We have identified 680 drillable, low to moderate risk locations providing us with multiple years of drilling inventory. Of these locations, 203 are classified as proved undeveloped. 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.

•: Proven Technical Team. Our technical staff includes 17 geologists, geophysicists, reservoir engineers and technicians with an average of over 16 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.
•: High Rate of 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 over 90% 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 $100 million to drill and complete 52 wells in our East Texas and Hugoton operating areas. Our average acquisition, finding and development cost from inception to June 30, 2006 was $1.27 per Mcfe.
•: Control of Low-Pressure Gas Gathering Infrastructure. We own and operate approximately 80 miles of gas gathering lines and gas pipelines that collect and transport our production and third party production in our East Texas operations area. We intend to acquire or construct additional gas gathering assets as necessary to fully develop our East Texas opportunities.
•: Gas Marketing Flexibility. 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.
•: Significant Equity Held by Management. After giving effect to our initial public offering, our management and employees will own more than % of our equity on a fully diluted basis.

Strategy

•

Maintain Technological Expertise. We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of over 90% since our inception and helped us improve and maximize field recoveries. We will use advanced geological and geophysical technologies, detailed petrophysical analyses, advanced reservoir engineering, and sophisticated completion and stimulation techniques, including multi-stage stimulation frac 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.

•: When we acquired the East Texas properties in June 2002, we estimated that each acquired well had average proved reserves of 2.5 Bcfe. From June 2002 to June 30, 2006, we drilled and completed 21 James Lime wells, and due to the improved geosteering, drilling and completion techniques we used in drilling them, we estimate that each of these 21 newly completed wells has average proved reserves of 3.5 Bcfe.

•: In East Texas we have begun to utilize multi-stage stimulation frac technology that we believe will allow for higher initial production rates and ultimate reserve recoveries than have previously been achieved in analogous horizontal wells. We have tested this technology on four wells, and we have experienced production at significantly higher rates than has been experienced using unstimulated production techniques. We achieved commercial production using this technology during the third quarter of 2006.
•: In the Hugoton field we are completing studies of two secondary recovery projects that will use traditional waterflood techniques. One of the areas identified has shown increased production in response to waterflood projects operated by others on contiguous properties. We expect to commence initial operations on the first of these two projects during the first quarter of 2007.
•: In the Hugoton field, we drill to the lowest known hydrocarbon producing formation in our area, then attempt completion in zones that have shown the presence of hydrocarbons during drilling. Geological evaluation through traditional logging methods is not as successful as this pragmatic test. We have found at least two economic production zones in each completed well using this method.
•: We intend to acquire an additional 350 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 350 square miles of proprietary 3-D seismic and 275 square miles of licensed 3-D seismic, providing seismic coverage of approximately two thirds of our Hugoton interest by 2011.

•: Acquisition Growth. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We will focus particularly on opportunities where we believe our reservoir management and operational expertise will enhance the value and performance of acquired properties. Initial acquisition targets are expected to be in and around our major producing and activity areas. 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. Upon the completion of our initial public offering, we expect to have approximately $ million in cash, no bank debt and at least $110 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.

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 is in the Huxley and East Bridges fields, which we believe are 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 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. The wells drilled to date have all been completed naturally with open-hole horizontal well bores. An average well costs approximately $2.1 million to drill and complete for unstimulated wells and $3.1 million for stimulated wells. The average initial flow rate of the unstimulated wells we have completed since June 2002 has been 2 MMcfe/d and the average proved reserves attributable to these wells is approximately 3.5 Bcfe. We have recently begun implementing new stimulation plan technology in this area that is estimated by us to cost an additional $1 million per well. We believe this new stimulation technology will increase initial production rates and ultimate recovery rates above current estimates for unstimulated wells. We completed our first well using this new stimulation technology in June 2006 and to date have completed four additional wells using this new technology, and we have experienced production at significantly higher rates than has been experienced using unstimulated techniques.

We have 58 productive wells with production to date of 52 Bcfe and are one of the largest gas producers in the James Lime with net production of 17 MMcfe/d. We have completed 21 of 22 wells we have drilled in the James Lime since 2002 and have identified an additional 80 potential drillable locations in the James Lime.

In addition to the James Lime play we started developing the lower Cretaceous Fredericksburg (or Edwards) formation using horizontal drilling. The Fredericksburg formation has a vertical depth of approximately 3,100 feet, and we drill several laterals of up to 5,000 feet in each completed well. A typical Fredericksburg well can be drilled and completed for approximately $1.1 million. Our wells in the area have average proved reserves of 1.1 Bcfe and an average initial flow of 800 Mcfe/d. Fredericksburg wells are also drilled underbalanced with water and completed with no stimulation. The productive thickness ranges from six to 38 feet with the average porosity over 20%. We have completed seven of eight wells in the Fredericksburg and we have identified 110 additional drillable locations of which 39 locations have been identified as proved undeveloped.

While the majority of our prospects will be internally generated, we intend, from time to time, to participate in third party drilling opportunities. On June 1, 2004, we entered into a joint venture agreement with Centurion Exploration Company pursuant to which we paid Centurion $1.25 million to participate in certain prospects it generates. We also pay Centurion a generation fee (or a promote) for each prospect in which we elect to participate. To date, we have participated in six wells with Centurion. Three of the wells were uneconomic, one well is currently being completed, two producing wells are currently producing approximately 3.0 MMcfe/d. Our working interest is 12.5% in each of these wells.

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 Amoco. 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 per Mcf, 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 acquired our rights to develop the Hugoton's deeper potential through our acquisition of Presco Western, LLC in April 2005. We are a party to a farmout agreement with a subsidiary of BP Amoco covering approximately 651,000 gross acres in the Hugoton field which terminates in 2013. We are currently in negotiations to extend our Hugoton farmout past 2013. In the event we are unable to extend this farmout, we intend to partner with other industry participants to develop our remaining acreage before 2013. Through this farmout agreement, we have one of the largest acreage positions in the Hugoton field. The farmout grants us the right to all mineral interests that we develop below the Heebner Shale as long as we fulfill our obligation to drill a minimum of 10 exploratory wells per year. Certain expenditures we make for seismic and geophysical work can be substituted for a portion of our exploratory drilling obligations. We receive a 640-acre assignment for each gas well we complete and a 160-acre assignment for each oil well we complete. We expect to be able to downspace drilling in gas to 320 acres per well for gas wells and 40 acres per well for oil wells. 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 drill all of our Hugoton wells to the base of the deepest known producing formation in the area.

We intend to acquire an additional 350 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 350 square miles of proprietary 3-D seismic and 275 square miles of licensed 3-D seismic, providing seismic coverage of approximately two-thirds of our Hugoton interest by 2011.

In the 18 months we have held our Hugoton acreage, we have already identified three waterfloods, and 392 potential drilling locations which cover only 40,000 out of our total of 651,000 acres. We have increased production from 2 MMcfe/d to over 8 MMcfe/d through the drilling of 30 wells and participating in three farmouts with only five dry holes. We intend to exploit waterflood potential in the field as well as the stacked pay potential. The primary targets are Morrow and Chester Valley sands

which can be detected seismically. Drilling and completion costs in the field are currently $480,000 per well. The average initial flow rate of our wells drilled in the Hugoton Deep has been 623 Mcfe/d, with expected proved reserves of 0.7 Bcfe per well. Our development budget for Kansas is $19 million for 2006, of which we have spent $4.7 million as of June 30, 2006, and $22 million for 2007.

Other

We own interests in 43 wells in southeastern Colorado and a 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 June 30, 2006								Production for the Six Months Ended June 30, 2006
		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		73	143	216	77	%	$	285	271	14	67	%
Hugoton (Kansas)		17	40	57	20			183	392	6	28
Other		4	4	8	3			19	17	1	5

	Total	94	187	281	100	%	$	487	680	21	100	%

(1): Based on June 30, 2006 NYMEX spot prices of $6.10 per MMBtu of gas and $73.93 per Bbl of oil, respectively, adjusted for basis and held flat for the life of the reserves and adjusted for quality differentials.
(2): Represents total gross drilling locations identified by management as of June 30, 2006. Of the total, 203 locations are classified as proved.

Operating Data

The following table presents certain information with respect to our historical operating data for the years ended December 31, 2003, 2004 and 2005 and for the six months ended June 30, 2006:

								Six Months Ended As of June 30, 2006
		Year Ended December 31,
		2003		2004		2005
Gross wells
	Drilled		6		14		23		18
	Completed		6		14		20		15
Net wells
	Drilled		4.5		9.7		21.6		17.5
	Completed		4.5		9.7		18.6		14.5
Net production data
	Net volume (MMcfe)		2,872		4,449		6,098		3,762
	Average daily volume (MMcfe/d)		7.9		12.8		16.7		20.7
Average sales price (per Mcfe)
	Average sales price (without hedge)	$	4.03	$	5.12	$	8.17	$	7.13
	Average sales price (with hedge)		4.03		5.12		8.15		7.90
Expenses (per Mcfe)
	Lease operating	$	0.90	$	1.00	$	1.23	$	1.53
	Production and ad valorem taxes		0.16		0.29		0.30		0.16
	General and administrative		0.87		0.77		1.93		1.14
	Depreciation, depletion and amortization		0.50		0.78		1.34		1.21

Estimated Proved Reserves

			As of December 31, 2005		As of June 30, 2006(1)
Estimated Proved Reserves
	Gas (Bcf)			217		236
	Oil (MMbls)			10		8

		Total proved reserves (Bcfe)		277		281

	Total proved developed reserves (Bcfe)			65		94

PV-10 value (millions)(1)
	Proved developed reserves		$	195	$	201
	Proved undeveloped reserves			470		286

		Total PV-10 value	$	665	$	487

(1): Based on June 30, 2006 NYMEX spot prices of $6.10 per MMBtu of gas and $73.93 per Bbl of oil and December 31, 2005 NYMEX prices of $9.00 per MMBtu of gas and $60.00 per Bbl of oil, respectively, each adjusted for basis and held flat for the life of the reserves and adjusted for

quality differentials. For a discussion of PV-10, see "Selected Combined Historical Financial Data—Reconciliation of Non-GAAP Financial Measures."

Development and Exploration Projects

		Historical		Estimated
		Year Ended December 31,		Year Ending December 31,
		2005		2006		2007
		(In thousands)
Capital expenditures:
	East Texas	$	25,336	$	34,400	$	36,000
	Hugoton		4,565		18,986		21,657
	Other		4,034		9,258		8,788
Geological and geophysical			35		4,000		4,000
Growth capital expenditures(1)			—		7,000		60,000

	Total capital expenditures	$	33,970	$	73,644	$	130,446

(1): Growth capital expenditures are for the acceleration of drilling and secondary recovery in addition to capital expenditures contemplated in the reserve report and for possible acquisitions.

Historical Finding and Development Costs

From our inception in April 2002 to June 30, 2006, our acquisition, finding and development costs have averaged $1.27 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, including future development costs attributable to proved undeveloped reserves, adjusted for the balance of unevaluated gas properties not subject to amortization, and dividing such amount by the total proved reserve additions. Estimated future development costs at December 31, 2005 totaled $176.4 million. Management believes that this information is useful to an investor in evaluating Ellora because it measures the efficiency of a company in adding proved reserves as compared to others in the industry.

Principal Customers and Marketing Agreements

We generally sell our production on a month-to-month basis based on current market prices.

The production we sold to Louis Dreyfus Corporation represented 63% and 53% of our oil and gas sales for the year ended December 31, 2005 and the six months ended June 30, 2006, respectively. The production we sold to Plains Marketing, L.P. represented 19% of our oil and gas sales for the six-month period ended June 30, 2006.

Productive Wells

The following table sets forth the number of productive oil and gas wells in which we owned a working interest at December 31, 2005 and June 30, 2006.

		Total Productive Wells at
		December 31, 2005		June 30, 2006
		Gross	Net	Gross	Net
Oil		25	14	27	16
Gas		192	105	205	117

	Total	217	119	232	133

Acreage

The following table sets forth certain information with respect to the developed and undeveloped acreage as of June 30, 2006.

		Developed		Undeveloped		Total
		Gross	Net	Gross	Net	Gross	Net
East Texas		27,668	26,734	49,020	43,068	76,688	69,802
Hugoton Field(1)		39,080	11,782	633,627	619,447	650,659	631,229
Other		17,750	23,288	26,533	20,470	66,331	43,759

	Total	84,498	61,804	709,180	682,985	793,678	744,790

(1): We are a party to a farmout agreeement with BP Amoco covering the 650,659 gross (631,229 net) acres in the Hugoton Field. This farmout, which expires in 2013, grants us the mineral rights below the Heebner Shale (approximately below 4,000 feet) as long as we meet minimum drilling requirements.

Drilling Activity

Development wells

The following table describes the development wells we drilled during the years ended December 31,
2003, 2004, and 2005 and the six months ended June 30, 2006.

		Year Ended December 31,						Six Months Ended June 30,
		2003		2004		2005		2006
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Producing		6	4.5	14	9.7	20	18.6	15	14.5
Dry		—	—	—	—	3	3.0	3	3.0

	Total	6	4.5	14	9.7	23	21.6	18	17.5

We were in the process of drilling two gross (two net) development wells as of June 30, 2006.

Exploratory wells

We did not participate in the drilling of any exploratory wells during the three years ended December 31, 2003, 2004 and 2005. We participated as a non-operator in two gross (0.25 net) exploratory wells for the six months ended June 30, 2006. Both of these wells were economically successful. As of June 30, 2006, we were participating in the drilling or completing of three gross (0.38 net) exploratory wells.

Hedging Activity

Derivative Instruments and Hedging Activities

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

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 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 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.

Comprehensive Environmental Response, Compensation and Liability Act

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.

Waste Handling

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. Under the auspices 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 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.

Other Laws and Regulations

In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change entered into force. Pursuant to the Protocol, adopting countries are required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. The Bush administration has indicated it will not support ratification of the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the United States for legislation that requires reductions in greenhouse gas emissions, and some states, although not those in which we currently operate, have already adopted regulatory initiatives or legislation to reduce emissions of greenhouse gases. For example, California recently

adopted the "California Global Warming Solutions Act of 2006," which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions would likely adversely impact our future operations, results of operations and financial condition. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Employees

At September 30, 2006, we had 47 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 September 30, 2006. 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	56	Chairman of the Board, President and Chief Executive Officer	2002
Richard F. McClure Jr.	46	Vice President of Operations and Chief Operating Officer	2002
James R. Casperson	59	Vice President of Finance and Chief Financial Officer	2005
Valerie K. Walker	46	Vice President of Exploration	2002
Jeffery S. Williams	47	Vice President of Land and Acquisition	2005
John W. (Bill) Minnett	53	Vice President of Drilling	2003
Cortlandt S. Dietler(a)	85	Director	2006
Bryan H. Lawrence	64	Director	2002
Peter A. Leidel	50	Director	2002
Sheldon B. Lubar(b)(c)	77	Director	2003
Neil L. Stenbuck(a)(c)	53	Director	2006
James B. Wallace(b)	77	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 and Chief Operating Officer of Alta Energy. 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 previously served on the board of directors of Centurion Exploration Company and 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.

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.

James R. Casperson joined us as Chief Financial Officer in March 2005. Mr. Casperson spent the previous five years as the Chief Financial Officer of Whiting Petroleum Corporation of Denver, Colorado. Mr. Casperson has 27 years of experience in the oil and gas industry in public accounting, private industry and as a consultant. Before his employment with Whiting, Mr. Casperson spent 15 years as President of Casperson Incorporated, private consulting firm specializing in the oil and gas industry. Mr. Casperson has a BBA in accounting from Texas Tech University and practiced as a CPA but does not currently have an active license.

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. 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 and 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.

John W. (Bill) Minnett joined us in 2003 as drilling superintendent and was promoted to Vice President in 2005. Before his employment with us, he was an independent drilling consultant. Mr. Minnett brings significant experience in terms of length of time and exposure to drilling and supervising drilling operations for various companies in the North Sea, the Gulf of Mexico, and Saudi Arabia, on shore drilling in the Gulf Coast, Mid Continent and the Rocky Mountains. Mr. Minnett supervised the first horizontal drilling from a floating rig in the North Sea and the first horizontal well drilling in Saudi Arabia.

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 a Director of Hallador Petroleum Company, Cimarex Energy Co., Forest Oil Corporation and Nytis Exploration Company. 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 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 Willbros Group Inc. and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. 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 and Crosstex Energy GP, LLC since December 2003, Grant Prideco, Inc., an energy services company, since 2000, and Weatherford International, Inc., an energy services company, since 1995. 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 was a Director and Executive Vice President and Chief Financial Officer of Prima Oil and Gas from May 2001 until its sale in September 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. 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. Mr. Wallace was the President and Chairman of the Board of BWAB Inc., a private oil and gas company located in Denver, Colorado from 1988 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 has 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 trustee of the University of Colorado Foundation, Inc. and several other charitable organizations, and a director of several public and private 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.

Director Compensation

Historically, our directors have not received any compensation for serving on the board of Ellora, although we did reimburse directors for expenses incurred in connection with attendance at meetings of the board of directors. Following our initial public offering, each non-employee member of our board of directors will receive compensation for service on our board of directors and committees thereof. Following our initial public offering, non-employee and non-Yorktown Energy Partners associates will receive $80,000 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 will receive $5,000 and $2,500, respectively.

Employee directors will not receive compensation for service on our board of directors. All directors will be 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.

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

The following is a schedule of annual and long-term compensation paid to our five most highly compensated officers for the annual periods indicated below:

Name and Principal Position	Year	Salary		Bonus		Securities Underlying Options	Total Compensation
T. Scott Martin Chairman, President and Chief Executive Officer	2005 2004 2003	$	257,000 228,333 199,792	$	255,750 180,000 135,000	404,510 87,395 109,244	$	512,750 408,333 334,792
Richard F. McClure Jr. Vice President of Operations and Chief Operating Officer	2005 2004 2003		165,208 146,667 140,000		120,250 80,000 70,000	242,706 24,212 30,265		285,458 226,667 210,000
James R. Casperson(1) Vice President of Finance and Chief Financial Officer	2005		151,666		150,000	202,255		301,666
Valerie K. Walker Vice President of Exploration	2005 2004 2003		165,208 141,333 134,224		120,250 80,000 78,285	242,706 24,212 142,657		285,458 221,333 212,509
John W. (Bill) Minnett Vice President of Drilling	2005 2004 2003		117,416 112,000 70,307		45,000 30,000 20,000	40,451 6,474 8,092		162,417 142,000 90,307

(1): Mr. Casperson joined us in March 2005.

Option Grants in Fiscal 2005

During 2005, the named executive officers below were granted an aggregate of 1,334,963 options to purchase shares of our common stock at an exercise price of $4.95 per share as follows:

Name	Grant Date	Number of Securities Underlying Options Granted*	Percent of Total Options Granted to Employees in 2005		Exercise Price ($/Share)		Expiration Date
T. Scott Martin	May 1, 2005	404,510	25	%	$	4.95	May 1, 2012
Richard F. McClure Jr.	May 1, 2005	242,746	15			4.95	May 1, 2012
James R. Casperson	May 1, 2005	202,255	12			4.95	May 1, 2012
Valerie K. Walker	May 1, 2005	242,746	15			4.95	May 1, 2012
John W. (Bill) Minnett	May 1, 2005	40,451	2			4.95	May 1, 2012
Jeffery S. Williams	November 1, 2005	202,255	12			4.95	November 1, 2012

*: All options were granted under our 2002 Stock Option Plan and have been transferred to our 2006 Long-Term Incentive Plan as described under "Description of the Amended and Restated 2006 Long-Term Incentive Plan."

Option Exercises in Fiscal Year 2005 and Value at June 30, 2006

The following table sets forth for each of the named executive officers the number of shares subject to both exercisable and unexercisable stock options in respect of our common stock, as well as the value of unexercisable in-the-money options as of June 30, 2006.

			Number of Securities Underlying Unexercised Options at June 30, 2006		Value of Unexercised In-The-Money Options at June 30, 2006
Name	Shares Acquired on Exercise	Value Realized			Value of Unexercised In-The-Money Options at June 30, 2006
Name	Shares Acquired on Exercise	Value Realized	Exercisable	Unexercisable	Exercisable		Unexercisable
T. Scott Martin	—	—	526,687	344,199	$	5,619,308	$	2,008,809
Richard F. McClure Jr.	—	—	300,173	199,313		3,287,664		1,119,371
James R. Casperson	—	—	90,282	111,973		554,518		871,380
Valerie K. Walker	—	—	305,780	193,706		3,189,916		1,178,876
Jeffery S. Williams	—	—	51,590	150,665		316,866		1,109,031
John W. (Bill) Minnett	—	—	28,669	26,348		230,009		193,984

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, 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 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.

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.

Prior to the close of our initial public offering, all of our officers will sign "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.

Description of the Amended and Restated 2006 Long-Term 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.

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. We have reserved 3,584,616 shares of common stock for issuance under the 2006 Plan, including the 2.7 million shares of common stock subject to options outstanding prior to the adoption 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.

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 interests.

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 by 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;
•: operating margin;
•: 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.

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 September 30, 2006, 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 our initial public offering and after the completion of our initial public offering. The table showing the percentage of shares beneficially owned after the offering assumes the sale of shares of our common stock by us in our initial public offering.

		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	61.3	%		%
Peter A. Leidel(3)(4)	27,462,159	61.3	%		%
Yorktown Energy Partners V, L.P.(3)	21,039,278	47.0	%		%
Yorktown Energy Partners VI, L.P.(3)	6,422,881	14.3	%		%
T. Scott Martin(5)(6)	1,815,639	4.0	%		%
Sheldon B. Lubar(7)	1,815,080	4.1	%		%
Valerie K. Walker(5)(8)	567,659	1.3	%		%
Richard F. McClure Jr.(5)(9)	562,052	1.2	%		%
James R. Casperson(5)(10)	334,430	*	%		%
George A. Wiegers(5)	166,667	*	%		%
John W. (Bill) Minnett(5)(11)	54,880	*	%		%
Jeffery S. Williams(5)(12)	51,590	*	%		%
Cortlandt S. Dietler(5)	8,333	*	%		%
Neil L. Stenbuck(5)	—	*	%		%
All officers and directors as a group (12 persons)	32,867,181	71.3	%		%

*: 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 includes the shares which all other persons have the right to acquire within 60 days after the date of this prospectus, 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., 5480 Valmont, Suite 350, Boulder, Colorado 80301.
(6): Includes options to purchase up to 526,687 shares of common stock, which are exercisable within 60 days from the date of this prospectus.
(7): Has a principal business address of 700 N. Water Street, Suite 1200, Milwaukee, Wisconsin 53202.
(8): Includes options to purchase up to 305,780 shares of common stock, which are exercisable within 60 days from the date of this prospectus.
(9): Includes options to purchase up to 300,173 shares of common stock, which are exercisable within 60 days from the date of this prospectus.
(10): Includes options to purchase up to 90,282 shares of common stock, which are exercisable within 60 days from the date of this prospectus.
(11): Includes options to purchase up to 28,669 shares of common stock, which are exercisable within 60 days from the date of this prospectus.
(12): Includes options to purchase up to 51,590 shares of common stock, which are exercisable within 60 days from the date of this prospectus.

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 "Management—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 second 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. At the time of the acquisition, Mr. Born was a stockholder and member 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 generates through September 2007. As of October 31, 2006, we had participated in five wells with Centurion. Two of the wells were completed and are currently producing, one well was a dry hole, one well is currently being evaluated, and one well is currently being completed. Our working interest is 12.5% in each of these wells. 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. Mr. Martin has resigned from the board of directors of Centurion.

On September 1, 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. At the time of the acquisition, Mr. Born was a stockholder and member of our board of directors.

SELLING STOCKHOLDERS

This prospectus covers shares sold in our recent private equity offering to "accredited investors" as defined by Rule 501(a) under the Securities Act pursuant to an exemption from registration provided in Regulation D, Rule 506 under Section 4(2) of the Securities Act, "qualified institutional buyers," as defined by Rule 144A under the Securities Act, and to non-U.S. persons pursuant to Regulation S under the Securities Act. The selling stockholders who purchased shares from us and the initial purchaser in the private equity offering (and their transferees) may from time to time offer and sell under this prospectus any or all of the shares listed opposite each of their names below. We are required to register for resale the shares of our common stock described in the table below.

The following table sets forth information about the number of shares owned by each selling stockholder that may be offered from time to time under this prospectus. Certain selling stockholders may be deemed to be "underwriters" as defined in the Securities Act. Any profits realized by the selling stockholder may be deemed to be underwriting commissions.

The table below has been prepared based upon the information furnished to us by the selling stockholders as of November , 2006. The selling stockholders identified below may have sold, transferred, or otherwise disposed of some or all of their shares since the date on which the information in the following table is presented in transactions exempt from or not subject to the registration requirements of the Securities Act. Information concerning the selling stockholders may change from time to time and, if necessary, we will amend or supplement this prospectus accordingly. We cannot give an estimate as to the amount of shares of common stock that will be held by the selling stockholders upon termination of this offering because the selling stockholders may offer some or all of their common stock under the offering contemplated by this prospectus. The total number of shares that may be sold hereunder will not exceed the number of shares offered hereby. Please read "Plan of Distribution."

The following table sets forth the name of each selling stockholder, the nature of any position, office, or other material relationship, if any, which the selling stockholder has had with us or any of our predecessors or affiliates within the past three years, and the number of shares of our common stock owned by such stockholder prior to the offering. We have assumed all shares reflected on the table will be sold from time to time.

Selling Stockholder	Number of Shares of Common Stock That May Be Sold	Percentage of Common Stock Outstanding
A. Albinsson & M. Wahlstrom(1)	14,000	*
A. Laurence & Helayne B. Jones(1)	4,000	*
A&C Tank Sales Company, Inc.(2)	4,000	*
Adair Group, Inc.(1)	2,500	*
AGS Investments, LLC(1)	4,000	*
Allison B. Weiss Irrevocable Trust Dated 5/12/1998(3)	66,667	*
Andrea Singer Pollack 1975 Revocable Trust(1)	9,400	*
Andrea Singer Pollack Revocable Trust(1)	18,400	*
Anima SGR SA(4)	175,000	*
Anthony G. Perry IRA(1)	9,500	*
BBT Fund, L.P.(5)	118,000	*
Bear Sterns SEC Corp FBO J. Steven Emerson, IRA R/O II(6)	300,000	*
Bennett Family LLC(7)	4,166	*
Blue Ridge Investments, Inc.(8)	1,600	*
Brian & Kelly Wilmovsky	2,000	*
Brownlie Family Partnership(1)	5,000	*

Bruce E. Dines IRA(1)	12,000	*
CAP Fund, L.P.(9)	58,000	*
Celeste C. Grynberg(1)	13,000	*
Champagne Capital SAS(10)	8,000	*
Cintra Pollack 1993 Trust(1)	4,500	*
Clinton Multistrategy Master Fund, Ltd.(11)	1,250,000	2.79	%
CNF Investments II, LLC(12)	25,000	*
Coleman Family Revocable Trust(13)	4,000	*
Cortlandt S. Dietler	8,333	*
Credit Suisse Client Nominees(UK) Ltd.(14)	30,000	*
Cumber International S.A.(15)	112,850	*
Cumberland Benchmarked Partners, L.P.(15)	270,740	*
Cumberland Long Partners, L.P.(15)	1,050	*
Cumberland Partners(15)	458,570	1.02	%
David & Sharon Neenan(1)	4,000	*
David G. Neenan Keogh(1)	2,000	*
Davis Brothers Limited Partnership II(16)	4,000	*
Douglass H. & Gail D. Manuel	6,250	*
Douglass H. McCorkindale	8,333	*
Doyle Family Trust(17)	3,000	*
Drake Associates, L.P.(18)	75,000	*
Edward Im & Jill Im	2,000	*
Edward A. Fox IRA	8,333	*
Edward M. Giles	18,000	*
Epstein Combined Holdings, LLC(19)	8,300	*
Eric W. Reimers & Marcia Reimers	8,000	*
Estate of Joseph Bander(1)	1,500	*
Fidelity Advisor Series 1: Fidelity Advisor Balanced(20)	106,700	*
Fidelity Puritan Trust: Fidelity Balanced Fund(20)	1,529,700	3.41	%
Flanagan Family Limited Partnership(21)	8,333	*
Francis E. Belmont	2,000	*
Frank B. Day(1)	23,500	*
Frank B. Day CRT(1)	1,400	*
Frank Day Lead Annuity Trust(1)	1,400	*
G. Hall & Kathleen Martin	10,000	*
George Weiss Associates Profit Sharing Plan(22)	200,000	*
Georgetown Preparatory School, Inc.(23)	8,333	*
Gina R. Day(1)	10,000	*
Gina R. Day CRT(1)	14,000	*
GJ Vogel, Inc. Profit Sharing Plan(24)	1,600	*
GLG North American Opportunity Fund(25)	1,041,666	2.32	%
Global Energy Opportunity Fund Ltd.(26)	1,000	*
Global Energy Opportunity Partners LP(26)	5,333	*
Grandview, LLC(27)	500,000	1.12	%
Grey K Fund LP(28)	24,000	*
Grey K Offshore Fund Ltd.(29)	42,667	*
Harbor Advisors, LLC FBO A/C Butterfield Bermuda General Account(30)	30,000	*

Hard Assets 2X Master Fund Ltd.(26)	380,000	*
Hard Assets Partners LP(26)	39,000	*
Hard Assets Portfolio Ltd.(26)	411,000	*
Harley G. Higbie, III(1)	3,000	*
Harley G. Higbie, Jr.(1)	7,000	*
HedgEnergy Master Fund LP(31)	300,000	*
HFR HE Platinum Master Trust(15)	23,060	*
Hildreth D. Wold(1)	2,700	*
IOU Limited Partnership(32)	150,000	*
J. Anthony & Phyllis K. Syme	4,166	*
Jack Wold Family Partnership(1)	2,900	*
Jeffrey T. Neal	4,100	*
James B. Wallace	4,167	*
James Locke & Susan Locke Tenants in the Entirety	20,000	*
Jay S. Weiss	8,300	*
Jennifer B. Lynn	2,000	*
Jerry Armstrong(1)	7,000	*
John & Mary Ann Duffey(1)	5,200	*
John D. Reilly	8,300	*
John Duffey IRA(1)	3,000	*
John E. Freyer(1)	6,000	*
John M. & Marcella F. Fox(1)	7,000	*
John P. Wold(1)	7,700	*
Johnson Revocable Living Trust Dated 5/18/98(33)	7,916	*
Joseph Werner	12,500	*
John Whalen & Linda D. Rabbitt	4,166	*
Joyce Buchman & Joel Buchman JTWROS	8,000	*
Juan Piedra(1)	1,000	*
Karen Ray Shay IRA(1)	6,200	*
Keegan Family Trust(34)	10,000	*
Kenmont Special Opportunities Master, L.P.(35)	78,000	*
KO-OP XXVI Wood, LLC(1)	10,000	*
Lansing Family Trust(36)	8,000	*
Lee A. Alexander	4,100	*
LeRoy Eakin III & Lindsay Eakin, JTBE	6,250	*
Linda Stone	30,000	*
Lolita Higbie Living Trust(1)	3,300	*
Long View Partners B, L.P.(15)	93,900	*
Lubar Nominees General Partnership(37)	35,000	*
Man Mac Miesque 10B Ltd.(35)	52,000	*
Mary Ann Duffey IRA(1)	1,800	*
Michael E. Heijer	2,000	*
Michael J. & Susan Darby	4,100	*
Mutual of America Institutional Funds All America Fund(38)	3,000	*
Mutual of America Institutional Funds Aggressive Equity Fund(38)	5,400	*
Mutual of America Investment Corp. Aggressive Equity Fund(38)	94,800	*
Mutual of America Investment Corp. All America Fund(38)	21,800	*
Mutual of America Investment Corp. Small Cap Value(38)	25,000	*

Nadine Grelsamer	3,000	*
Noah S. Pollack Revocable Trust(1)	1,500	*
Noah Singer Pollack 1993 Trust(1)	4,300	*
Park West Investors LLC(39)	150,738	*
Park West Partners International, Ltd.(39)	32,562	*
Perennial Partners, LP(40)	100,000	*
Peter B. Cannell	25,000	*
Peterson Investment Trust UAD 4/2/01(41)	333,333	*
Potato Patch I LP(1)	10,000	*
R. Patrick & Shelly L. McGinley	2,400	*
Rachel S. Grynberg Trust(1)	1,000	*
Rachel S. Grynberg Trust U/A Dated 4/21/82(1)	3,500	*
Ray O. Brownlie(1)	10,000	*
Richard S. Bodman Revocable Trust, dated 9/1/1998(42)	6,250	*
Robert H. Smith	9,000	*
Sara F. Hayes	10,000	*
Shay Enterprises, LLLP(1)	4,400	*
SRI Fund, L.P.(43)	24,000	*
Steuart Investment Company(44)	33,333	*
Summer Street Cumberland Investors, LLC(15)	39,830	*
Teressa Giguere Perry(1)	7,000	*
The Neenan Family LLLP(1)	3,000	*
The Northwestern Mutual Life Insurance Company(45)	833,333	1.86	%
Timothy B. Marz & Jane F. Matz JTWROS	1,000	*
Tivoli Partners L.P.(46)	20,000	*
Trousil & Associates, Inc.(1)	24,500	*
Twin Bridges, LLC(47)	12,500	*
United Capital Management, Inc.(48)	20,833	*
UWM Foundation, Inc.(49)	20,000	*
Van Eck Global Hard Assets(50)	369,000	*
Variable Insurance Products Fund III: Balanced Portfolio(20)	30,267	*
Wallace F. Holladay, Jr.	4,166	*
Wallace Family Partnership(1)	8,700	*
White River Partners, L.P.(51)	115,000	*
Wiegers & Co.(52)	166,667	*
William Achenbach IRA(1)	5,400	*
William Garrison	10,000	*
William T. Hankinson(1)	1,300	*
Worldwide Hard Assets(50)	528,000	1.18	%

*: Less than one percent.
(1): George F. Wood is the President of Wood & Co., the Investment Advisor for this selling stockholder. By virtue of his position with Wood & Co., Mr. Wood is deemed to hold investment power and voting control over the shares held by this stockholder.
(2): Joseph C. Cattares is the President of A&C Tank Sales Company, Inc. and is deemed to hold investment power and voting control over the shares held by this selling stockholder.

(3): Steven C. Kleinman and David M. Call are Trustees of this selling stockholder and are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(4): Giordano Martinelli is the Executive Director of Fondi Anima, the Investment Advisor of this selling shareholder. By virtue of his position at Fondi Anima, Mr. Martinelli is deemed to hold investment power and voting control over this shares held by this selling shareholder.
(5): 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.
(6): J. Steven Emerson is the sole beneficiary of the Bear Sterns SEC Corp FBO J. Steven Emerson, IRA R/O II and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(7): LuAnn L. Bennett is the Managing Member of Bennett Family LLC and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(8): 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.
(9): 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.
(10): Gaetan Japy is the President of Champagne Capital SAS and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(11): Vincent Darpino is a Portfolio Manager at Clinton Group, Inc., the Investment Manager of this selling stockholder. By virtue of his position at Clinton Group, Inc., Mr. Darpino is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(12): Robert J. Flanagan is the Manager of CNF Investments II, LLC and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(13): Ron Coleman and Michelle Coleman 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): Arild Eide is a Portfolio Manager at RAB Capital PLC, the Investment Manager of RAB American Opportunities Fund Limited, the beneficial owner of this selling stockholder. By virtue of his position at RAB Capital PLC, Mr. Eide is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(15): Bruce Wilcox, Andrew Wallach and Gary Tynes are Managing Members of Cumberland Associates LLC, the Investment Manager of this selling stockholder. By virtue of their positions with Cumberland Associates LLC, Messrs. Wilcox, Wallach and Tynes are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(16): Floyd E. Davis III is the President of Davis Brothers II, Inc., the General Partner of this selling stockholder. By virtue of his position at Davis Brothers II, Inc., Mr. Davis is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(17): 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.

(18): Alexander W. Rutherford is the Portfolio Manager of Drake Asset Management LLC, the General Partner of this selling stockholder. By virtue of his position with Drake Asset Management LLC, Mr. Rutherford is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(19): James R. Epstein is the President of EFO Capital Management, the Investment Manager of this selling stockholder. By virtue of his position with EFO Capital Management, Mr. Epstein is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(20): This selling stockholder is a registered investment fund advised by Fidelity Management & Research Company, a wholly-owned subsidiary of FMR Corp. and is the beneficial owner of the shares held by this selling stockholder. Edward C. Johnson III, Chairman of FMR Corp., through it's control of Fidelity Management & Research Company, has the sole power to dispose of the shares held by this selling stockholder. Neither FMR Corp. nor Edward C. Johnson III has the sole power to vote or direct the voting of the shares owned directly by this selling stockholder, which power resides with this selling stockholder's Board of Trustees.
(21): Robert J. Flanagan is the Manager of E.O. Flanagan, LLC, the General Partner of this selling stockholder. By virtue of his position at E.O. Flanagan, LLC, Mr. Flanagan is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(22): George A. Weiss is the Trustee of the George Weiss Associates Profit Sharing Plan and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(23): Robert W. Posniewski is the Chief Financial Officer of Georgetown Preparatory School, Inc. and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(24): Greg Vogel is the President of the GJ Vogel Inc. Profit Sharing Plan and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(25): 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.
(26): Shawn Reynolds is a Portfolio Manager at Van Eck Absolute Return Advisors Corporation, the Investment Manager of this selling stockholder. By virtue of his position at Van Eck Absolute Return Advisors Corporation, Mr. Reynolds is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(27): 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.
(28): Robert Koltun is the Managing Member of Grey K GP, LLC, the General Partner of this selling stockholder. By virtue of his position with Grey K GP, LLC, Mr. Koltun is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(29): Robert Koltun is the Managing Member of RNK Capital LLC, the Investment Manager of this selling stockholder. By virtue of his position with RNK Capital LLC, Mr. Koltun is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(30): Diana Light-Rhodes is the Vice President and Robert Janecek is a Member of Harbor Advisors, LLC. By virtue of their positions with Harbor Advisors, LLC, Ms. Light-Rhodes and Mr. Janecek

are deemed to hold investment power and voting control over the shares held by this selling stockholder.

(31): B.J. Willingham is the Chief Investment Officer and Lee P. Moncrief is the Chief Executive Officer of Moncrief Willingham Energy Advisers, the Investment Adviser of this selling stockholder. By virtue of their positions with Moncrief Willingham Energy Advisers, Mr. Willingham and Mr. Moncrief are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(32): George A. Weiss 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.
(33): Richard Johnson and Clasina Johnson are Trustees of this selling stockholder and are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(34): 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.
(35): 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.
(36): Thomas H. Lansing and Susan Lansing are Trustees of this selling stockholder and are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(37): Sheldon B. Lubar is a General Partner of this selling stockholder and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(38): Stephen Rich is the Executive Vice President of Mutual of America Capital Management Corporation, which is the Investment Advisor of this selling stockholder. By virtue of his position with Mutual of America Capital Management Corporation, Mr. Rich is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(39): Peter S. Park is the Principal of Park West Asset Management LLC, the Investment Manager of this selling stockholder. By virtue of his positions with Park West Asset Management LLC, Mr. Park is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(40): Paul A. Fino III is the Chief Executive Officer and Chief Operating Officer of Perennial Investors, LLC, the General Partner of this selling stockholder. By virtue of his position with Perennial Investors, LLC, Mr. Fino is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(41): 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.
(42): Richard S. Bodman is Trustee of this selling stockholder and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(43): 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 CAP-FW, Inc., Mr. Bass is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(44): John R. Clark III is the President of this selling stockholder and is deemed to hold investment power and voting control over the shares held by this selling stockholder.

(45): Jerome R. Baier is a portfolio manager of Northwestern Investment Management Company, LLC, the Investment Manager of this selling stockholder. By virtue of his position with Northwestern Investment Management Company, LLC, Mr. Baier is deemed to hold shared investment power and voting control over the shares held by this selling stockholder.
(46): 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.
(47): Tom Wallace, Mark Wallace and Jim Wallace are Managers of Twin Bridges, LLC. By virtue of their positions with Twin Bridges, LLC, Messrs. T. Wallace, M. Wallace and J. Wallace are deemed to hold investment power and voting control over the shares held by this selling stockholder.
(48): James A. Lustig is the President of United Capital Management, Inc. and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(49): Curtis A. Stang is the Chief Operating Officer of this selling stockholder and is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(50): Shawn Reynolds is a Portfolio Manager at Van Eck Associates Corporation, the Investment Manager of this selling stockholder. By virtue of his position at Van Eck Associates Corporation, Mr. Reynolds is deemed to hold investment power and voting control over the shares held by this selling stockholder.
(51): 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.
(52): B. Deane Kreitler is the Portfolio Manager and George A. Wiegers and E. Alex Wiegers are Members of Wiegers & Co. By virtue of their positions with Wiegers & Co., Messrs. Kreitler, G. Wiegers and E. Wiegers are deemed to hold investment power and voting control over the shares held by this selling stockholder.

PLAN OF DISTRIBUTION

We are registering the common stock covered by this prospectus to permit the selling stockholders (which as used herein includes donees, pledgees, transferees or other successors-in-interest) to conduct public secondary trading of these shares from time to time after the date of this prospectus. Under the registration rights agreement we entered into for the benefit of the selling stockholders, we agreed to, among other things, bear all expenses, other than brokers' or underwriters' discounts and commissions, in connection with the registration and sale of the common stock covered by this prospectus. We will not receive any of the proceeds of the sale of the common stock offered by this prospectus. The aggregate proceeds to the selling stockholders from the sale of the common stock will be the purchase price of the common stock less any discounts and commissions. A selling stockholder reserves the right to accept and, together with their agents, to reject, any proposed purchases of common stock to be made directly or through agents.

The common stock offered by this prospectus may be sold from time to time to purchasers:

•: directly by the selling stockholders and their successors, which includes their donees, pledgees or transferees or their successors-in-interest; or
•: through underwriters, broker-dealers or agents, who may receive compensation in the form of discounts, concessions or agents' commissions from the selling stockholders or the purchasers of the common stock. These discounts, concessions, or commissions may be in excess of those customary in the types of transactions involved.

The selling stockholders and any underwriters, broker-dealers or agents who participate in the sale or distribution of the common stock may be deemed to be "underwriters" within the meaning of the Securities Act. The selling stockholders identified as registered broker-dealers in the selling stockholders table above under the heading "Selling Stockholders" are deemed to be underwriters. As a result, any profits on the sale of the common stock by such selling stockholders and any discounts, commissions or agent's commissions or concessions received by any such broker-dealer or agents may be deemed to be underwriting discounts and commissions under the Securities Act. Selling stockholders who are deemed to be "underwriters" with the meaning of Section 2(11) of the Securities Act will be subject to prospectus delivery requirements of the Securities Act. In addition, underwriters are subject to certain statutory liabilities, including, but not limited to, Sections 11, 12, and 17 of the Securities Act.

The common stock may be sold in one or more transactions at:

•: fixed prices;
•: prevailing market prices at the time of sale;
•: prices related to such prevailing market prices;
•: varying prices determined at the time of sale; or
•: negotiated prices.

These sales may be effected in one or more transactions:

•: on any national securities exchange or quotation on which the common stock may be listed or quoted at the time of the sale;
•: in the over-the-counter market;
•: in transactions on such exchanges or services or in the over-the-counter market;

•: through the writing of options (including the issuance by the selling stockholders of derivative securities), whether the options or such other derivative securities are listed on an options exchange or otherwise;
•: through the settlement of short sales (only after the initial effectiveness of the registration statement to which this prospectus is a part); or
•: through any combination of the foregoing.

These transactions may include block transactions or crosses. Crosses are transactions in which the same broker acts as an agent on both sides of the trade.

In connection with the sales of the common stock, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions that in turn may:

•: engage in short sales of the common stock (only after the initial effectiveness of the registration statement to which this prospectus is a part) in the course of hedging their positions;
•: sell the common stock short and deliver the common stock to close out short positions;
•: loan or pledge the common stock to broker-dealers or other financial institutions that in turn may sell the common stock;
•: enter into option or other transactions with broker-dealers or other financial institutions that require the delivery to the broker-dealer or other financial institution of the common stock, which the broker-dealer or other financial institution may resell under the prospectus; or
•: enter into transactions in which a broker-dealer makes purchases as a principal for resale for its own account or through other types of transactions.

To our knowledge, there are currently no plans, arrangements or understandings between any selling stockholders and any underwriter, broker-dealer or agent regarding the sale of the common stock by the selling stockholders.

We have applied for listing of our common stock on The Nasdaq Global Market once we meet its eligibility requirements. However, we can give no assurances as to the development of liquidity or any trading market for the common stock or that we will meet the listing requirements of The Nasdaq Global Market.

There can be no assurance that any selling stockholder will sell any or all of the common stock under this prospectus. Further, we cannot assure you that any such selling stockholder will not transfer, devise or gift the common stock by other means not described in this prospectus. In addition, any common stock covered by this prospectus that qualifies for sale under Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A rather than under this prospectus. The common stock covered by this prospectus may also be sold to non-U.S. persons outside the U.S. in accordance with Regulation S under the Securities Act rather than under this prospectus. The common stock may be sold in some states only through registered or licensed brokers or dealers. In addition, in some states the common stock may not be sold unless it has been registered or qualified for sale or an exemption from registration or qualification is available and complied with.

The selling stockholders and any other person participating in the sale of the common stock will be subject to the applicable provisions of the Exchange Act and the rules and regulations promulgated thereunder. The Exchange Act rules include, without limitation, Regulation M, which may limit the timing of purchases and sales of any of the common stock by the selling stockholders and any other participating person. In addition, Regulation M may restrict the ability of any person engaged in the distribution of the common stock to engage in market-making activities with respect to the particular

common stock being distributed. This may affect the marketability of the common stock and the ability of any person or entity to engage in market-making activities with respect to the common stock.

We have agreed to indemnify the selling stockholders against certain liabilities, including liabilities under the Securities Act.

We have agreed to pay substantially all of the expenses incidental to the registration, offering, and sale of the common stock to the public, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any brokerage or underwriting discounts or commissions or transfer taxes relating to the sale of shares of our common stock.

If required, at the time of a particular offering of shares of common stock by a selling stockholder, a supplement to this prospectus will be circulated setting forth the name or names of any underwriters, broker-dealers or agents, any discounts, commissions or other terms constituting compensation for underwriters and any discounts, commissions or concessions allowed or reallowed or paid to agents or broker-dealers.

We have agreed with the selling stockholders to keep the registration statement of which this prospectus forms a part effective for specified periods of time or until the occurrence of certain events. We may, under certain circumstances, suspend the use of this prospectus upon notice to the selling stockholders, to update the registration statement of which this prospectus forms a part with periodic information or material non-public information as required by the Securities Act. We have agreed with the selling stockholders to limit these suspended periods to those required by the Securities Act or limit them to contractually specified limits. See "Registration Rights."

The holders of shares of our common stock that are beneficiaries of the registration rights agreement and have elected to participate in our initial public offering will not be able to sell any remaining shares owned by them and not included in our initial public offering for a period of 180 days following the effective date of such registration statement. The holders of shares of our common stock that are beneficiaries of the registration rights agreement and have elected not to participate in our initial public offering also will not be able to sell any such shares for a period of 60 days following the effective date of such registration statement.

Once sold under the registration statement of which this prospectus forms a part, the shares of common stock covered hereby will be freely tradeable in the hands of persons other than our affiliates.

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 October 31, 2006, we had a total of 44,807,697 shares of common stock outstanding. Following the completion of our initial public offering and assuming that the underwriters exercise their option to purchase additional shares in full, we will have shares of common stock outstanding based on the number of shares outstanding as of October 31, 2006. We have reserved 3,584,616 shares for issuance to employees under our 2006 Plan. As of October 31, 2006, we have options to purchase 2,692,293 shares of our common stock outstanding and 892,323 shares remain available for future grants.

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.

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 the 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 bylaws of the company.

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 the company 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 the rights of the company and 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 the 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 our initial public offering and 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 our initial public offering and 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 October 31, 2006, we had 44,807,697 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 a lock-up period of up to 180 days following the completion of our initial public offering. The holders of shares of our common stock that are beneficiaries of the registration rights agreement and have elected to participate in our initial public offering will not be able to sell any remaining shares owned by them and not included in our initial public offering for a period of 180 days following the effective date of such registration statement. The holders of shares of our common stock that are beneficiaries of the registration rights agreement and have elected not to participate in our initial public offering also will not be able to sell any such shares for a period of 60 days following the effective date of such registration statement.

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 or Rule 144(k) under the Securities Act. These rules are summarized below.

Rule 144

In general, under Rule 144 as currently in effect, beginning 90 days after the date of this prospectus, a person or persons whose shares are aggregated, who have beneficially owned restricted shares for at least one year, including persons who may be deemed to be our "affiliates," would be entitled to sell within any three-month period a number of shares that does not exceed the greater of (i) 1% of the number of shares of common stock then outstanding or (ii) the average weekly trading volume of our common stock during the four calendar weeks before a notice of the sale on SEC Form 144 is filed.

Sales under Rule 144 are also subject to certain manner of sale provisions and notice requirements and to the availability of certain public information about us.

Rule 144(k)

Under Rule 144(k), a person who is not deemed to have been one of our "affiliates" at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an "affiliate," is entitled to sell these shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

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 the July 2006. In the registration rights agreement we agreed, for the benefit of the purchasers of our common stock in the private offering, that we will, at our expense:

•

file two registration statements (the "shelf registration statements") with the SEC (which occurs in part pursuant to the filing of the shelf registration statement of which this prospectus is a part) by November 9, 2006;

•

use our commercially reasonable efforts to cause the shelf registration statements to become effective under the Securities Act not later than February 7, 2007;

•

continuously maintain the effectiveness of the shelf registration statements under the Securities Act until the earliest of:

•: the sale of all of the shares of common stock covered by the shelf registration statements pursuant to the registration statements or Rule 144 under the Securities Act or any similar provision then in effect;
•: such time as all of the shares of our common stock sold in the private offering and covered by the shelf registration statements and not held by affiliates of us are, in the opinion of our counsel, eligible for sale pursuant to Rule 144(k) (or any successor or analogous rule) under the Securities Act; or
•: the shares have been sold to us or any of our subsidiaries.

We filed the registration statement of which this prospectus is a part to satisfy in part our filing obligation under the registration rights agreement. A purchaser of our common stock in connection with this prospectus will not receive the benefits of the registration rights agreement.

Notwithstanding the foregoing, we will be permitted, under limited circumstances, to suspend the use, from time to time, of the shelf registration statement of which this prospectus is a part (and therefore suspend sales under the registration statement) 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 statement would have a material adverse effect on such public offering (in which case the black out period cannot be more than 45 days or, in the case of an 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) after the advice of counsel, the sale of the shares covered by the shelf registration statement 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 purpose 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 registrations statement (or such filings) to become effective or to promptly amend or supplement the registration statement on a post-effective basis; or
•: a majority of our board of directors, in good faith, determines, that we are required by law, rule or regulation to supplement the shelf registration statement or file a post-effective amendment

to the shelf registration statement in order to incorporate information into the shelf registration statement for the purpose of (1) including in the shelf registration statement a prospectus required under Section 10(a)(3) of the Securities Act; (2) including in the prospectus included in the shelf registration statement any facts or events arising after the effective date of the shelf registration statement (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 prospectus included in the shelf registration statement any material information with respect to the plan of distribution not disclosed in the shelf registration statement or any material change to such information.

The cumulative blackout periods in any 12-month period commencing on the closing of the private equity 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 it effective; provided we have used all commercially reasonable efforts to cause such post-effective amendment to be declared effective.

In addition to this limited ability to suspend use of the shelf registration statement, until we are eligible to incorporate by reference into the registration statement our periodic and current reports, which will not occur until at least one year following the end of the month in which the registration statement of which this prospectus is a part is declared effective, we will be required to amend or supplement the shelf registration statement to include our quarterly and annual financial information and other developments material to us. Therefore, sales under the shelf registration statement will be suspended until the amendment or supplement, as the case may be, is filed and effective.

Each holder will be deemed to have agreed that, upon receipt of notice of the occurrence of any event which makes a statement in the prospectus which is a part of the shelf registration statement untrue in any material respect or which requires the making of any changes in such prospectus in order to make the statements therein not misleading, or of certain other events specified in the registration rights agreement, such holder will suspend the sale of our common stock pursuant to such prospectus until we have amended or supplemented such prospectus to correct such misstatement or omission and have furnished copies of such amended or supplemented prospectus to such holder or we have given notice that the sale of the common stock may be resumed.

Although we have agreed to use commercially reasonable efforts to cause the registration statement, of which this prospectus is a part, to become effective under the Securities Act by February 7, 2007, there can be no assurance that the registration statement will become effective within such time period or at all.

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

The following is a summary of 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 the Internal Revenue Code of 1986 as amended (the "Code") and 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 United States federal income tax law, such as (without limitation):

•: certain United States expatriates;
•: stockholders that hold out 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 S corporations, entities treated as partnerships for United States 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 any aspect of state, local or foreign tax laws or 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 the 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. Moreover, this summary does not discuss alternative minimum tax consequences, if any, or any state, local or foreign tax consequences to holders of our common stock.

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 UNITED STATES 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 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 the 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 other applicable form) properly certifying eligibility for the reduced rate.

Dividends paid to a non-United States holder that are effectively connected with a trade or business conducted by the non-United States holder in the United States (and, where a tax treaty applies, are attributable to a permanent establishment maintained by the non-United States holder in the United States) 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 much the same manner as if the non-United States holder were a resident of the United States. 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 other applicable form) properly certifying eligibility for such exemption. Dividends received by a corporate non-United States holder that are effectively connected with a trade or business conducted by such corporate non-United States holder in the United States also 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 generally will not be subject to United States federal income tax unless:

•: the gain is effectively connected with a trade or business of 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" for United States federal income tax purposes.

An individual non-United States holder described in the first bullet point immediately above will be subject to tax on the net gain derived from the sale under regular graduated United States federal income tax rates. If a non-United States holder that is a foreign corporation falls 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 described in the second bullet point immediately above will be subject to a flat 30% tax on the gain derived from the sale, 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 are currently a "United States real property holding corporation" for United States federal income tax purposes. So long as our common stock is "regularly traded on an established securities market," only a non-United States holder who holds or held (at any time during the shorter of the five year period preceding the date of disposition or the holder's holding period) more than 5% of our common stock will be subject to United States federal income tax on the disposition of 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 United States federal income tax liability provided the required information is furnished to the IRS.

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.

EXPERTS

The financial statements of Ellora Energy Inc. as of December 31, 2004 and 2005, and for each of the three years in the period ended December 31, 2005 included in this prospectus have been audited by Hein & Associates LLP, independent 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 financial statements of Presco Western, LLC for the two years ended December 31, 2003 and 2004 included in this prospectus have been audited by Hein & Associates LLP, independent accountants, as stated in their report appearing in this prospectus, and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements of the Shelby County Acquisition Properties for the year ended December 31, 2004 included in this prospectus have been audited by Hein & Associates LLP, independent accountants, as stated in their report appearing in this prospectus, 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 December 31, 2005 audited by MHA Petroleum Consultants, Inc., independent petroleum engineers, and the estimates of the proved reserves as of June 30, 2006 prepared by MHA. The summary pages of their reports as of December 31, 2005 and June 30, 2006 are included in this prospectus as Appendix "A." These estimates are included in this prospectus in reliance upon the authority of MHA 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 at www.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.

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.

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.

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.

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.

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.

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 developed reserves expected to be recovered from zones behind casing in existing wells.

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 year-end reserves by the average production during the past year 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.

ELLORA ENERGY INC.
Index To Financial Statements

Annual Financial Statements
	Report of Independent Registered Public Accounting Firm
	Balance Sheets—December 31, 2004 (consolidated) and 2005 (combined)
	Statements of Income—For the Years Ended December 31, 2003 (consolidated), 2004 (consolidated) and 2005 (combined)
	Statements of Comprehensive Income—For the Years Ended December 31, 2003 (consolidated), 2004 (consolidated) and 2005 (combined)
	Statements of Stockholders' Equity and Comprehensive Income—For the Years Ended December 31, 2003 (consolidated), 2004 (consolidated) and 2005 (combined)
	Statements of Cash Flows—For the Years Ended December 31, 2003 (consolidated), 2004 (consolidated) and 2005 (combined)
	Notes to Financial Statements
Interim Financial Statements
	Balance Sheets—December 31, 2005 (combined) and June 30, 2006 (combined) (unaudited)
	Unaudited Statements of Income—For the Six Months Ended June 30, 2005 (combined) and 2006 (combined)
	Unaudited Statements of Comprehensive Income—For the Six Months Ended June 30, 2005 (combined) and 2006 (combined)
	Statements of Changes in Stockholders' Equity and Comprehensive Income—For the Year Ended December 31, 2005 (combined) and the Six Months Ended June 30, 2006 (combined) (unaudited)
	Unaudited Statements of Cash Flows—For the Six Months Ended June 30, 2005 (combined) and 2006 (combined)
	Notes to Condensed Unaudited Financial Statements
Presco Western, LLC Financial Statements
	Report of Independent Registered Public Accounting Firm
	Statements of Income—For the Years Ended December 31, 2003 and 2004 and the Three Months Ended March 31, 2005 (unaudited)
	Statements of Members' Equity—For the Years Ended December 31, 2003 and 2004 and the Three Months Ended March 31, 2005 (unaudited)
	Statements of Cash Flows—For the Years Ended December 31, 2003 and 2004 and the Three Months Ended March 31, 2005 (unaudited)
	Notes to Financial Statements
Shelby County Acquisition Properties Financial Statement
	Report of Independent Registered Public Accounting Firm
	Statements of Revenues and Direct Operating Expenses—For the Year Ended December 31, 2004 and the Six Months Ended June 30, 2005 (unaudited)
	Notes to Financial Statement

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors
Ellora Energy Inc.
Boulder, Colorado

We have audited the accompanying balance sheets of Ellora Energy Inc. and affiliated entities as of December 31, 2005 and 2004, 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, 2005. 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 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

HEIN & ASSOCIATES LLP
Denver, Colorado

March 3, 2006

F-2

ELLORA ENERGY INC. AND AFFILIATED ENTITIES
BALANCE SHEETS

				December 31,
				2004 Consolidated			2005 Combined
*ASSETS*
CURRENT ASSETS:
	Cash			$	2,748,000		$	3,161,000
	Accounts receivable:
		Oil and gas sales			3,675,000			10,522,000
		Joint interest billings			800,000			1,242,000
	Income taxes receivable				500,000			500,000
	Derivative asset				—			2,625,000
	Oil and gas equipment inventory				—			1,409,000
	Prepaids and other current assets				412,000			1,431,000

			Total current assets		8,135,000			20,890,000

PROPERTY AND EQUIPMENT:
	Oil and gas properties (successful efforts method):
		Developed properties			55,779,000			160,283,000
		Undeveloped leasehold costs			10,732,000			11,313,000
	Pipeline properties				10,161,000			11,878,000
	Furniture and equipment				512,000			1,152,000

			Total property and equipment		77,184,000			184,626,000
	Less accumulated depletion and depreciation				(6,373,000	)		(14,532,000	)

			Net property and equipment		70,811,000			170,094,000
OTHER LONG-TERM ASSETS					1,260,000			1,316,000

TOTAL ASSETS				$	80,206,000		$	192,300,000

*LIABILITIES AND STOCKHOLDERS' EQUITY*
CURRENT LIABILITIES:
	Accounts payable			$	6,558,000		$	5,128,000
	Accrued expenses				—			1,264,000
	Production taxes payable				1,109,000			1,373,000
	Oil and gas revenues payable				2,049,000			9,477,000

			Total current liabilities		9,716,000			17,242,000
NOTES PAYABLE					10,683,000			25,750,000
DEFERRED INCOME TAXES, NET					7,682,000			16,923,000
ASSET RETIREMENT OBLIGATIONS					368,000			716,000
COMMITMENTS (Note 9)
STOCKHOLDERS' EQUITY:
	Ellora Energy Inc. common stock, $.001 par value, 5,000,000 shares authorized, 3,546,635 and 3,622,370 issued and outstanding, respectively				4,000			4,000
	Additional paid-in capital				46,167,000			52,599,000
	Subscription receivable and accrued interest				(4,649,000	)		(6,224,000	)
	Ellora Oil and Gas Inc. common stock, $100 par value, 739,000 shares authorized, 0 issued and outstanding in 2004, 642,500 in 2005				—			64,250,000
	Retained earnings				10,037,000			20,818,000
	Accumulated other comprehensive income				198,000			222,000

			Total stockholders' equity		51,757,000			131,669,000

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY				$	80,206,000		$	192,300,000

See accompanying notes to these financial statements.

F-3

ELLORA ENERGY INC. AND AFFILIATED ENTITIES
STATEMENTS OF INCOME

			For the Years Ended December 31,
			2003 Consolidated			2004 Consolidated		2005 Combined
REVENUE:
	Oil and gas sales		$	11,810,000		$	22,780,000	$	47,595,000
	Gas aggregation and pipeline sales			—			1,103,000		5,586,000
	(Loss) on oil and gas hedging activities			—			—		(115,000	)
	Interest income and other			159,000			272,000		16,000
	Equity investment income			206,000			116,000		—

		Total revenue		12,175,000			24,271,000		53,082,000

COSTS AND EXPENSES:
	Lease operating expense			2,580,000			4,539,000		6,141,000
	Production taxes			473,000			1,291,000		1,813,000
	Gas aggregation and pipeline cost of sales			—			1,316,000		4,020,000
	Depreciation, depletion and amortization			1,432,000			3,479,000		8,189,000
	Exploration			—			—		422,000
	General and administrative (including $4,857,000 of stock compensation for the year ended December 31, 2005)			2,497,000			3,407,000		11,766,000
	Interest expense			219,000			355,000		716,000

		Total costs and expenses		7,201,000			14,387,000		33,067,000

INCOME BEFORE TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE				4,974,000			9,884,000		20,015,000
INCOME TAXES:
	Current income tax expense (benefit)			(254,000	)		—		—
	Deferred income tax expense			2,053,000			3,850,000		9,234,000

				1,799,000			3,850,000		9,234,000

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE				3,175,000			6,034,000		10,781,000
	Cumulative effect of accounting change, net of tax			30,000			—		—

NET INCOME			$	3,205,000		$	6,034,000	$	10,781,000

BASIC INCOME PER SHARE BEFORE ACCOUNTING CHANGE			$	.15		$	.22	$	.28

CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX				—			—		—

BASIC INCOME PER SHARE			$	.15		$	.22	$	.28

DILUTED INCOME PER SHARE BEFORE ACCOUNTING CHANGE			$	.15		$	.22	$	.27

CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX				—			—		—

DILUTED INCOME PER SHARE			$	.15		$	.22	$	.27

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC				21,691,999			27,541,033		38,754,598

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—DILUTED				21,915,302			27,945,641		40,089,555

See accompanying notes to these financial statements.

F-4

ELLORA ENERGY INC. AND AFFILIATED ENTITIES
STATEMENTS OF COMPREHENSIVE INCOME

		For the Years Ended December 31,
		2003 Consolidated			2004 Consolidated		2005 Combined
NET INCOME		$	3,205,000		$	6,034,000	$	10,781,000
OTHER COMPREHENSIVE INCOME:
	Risk management activities, net of tax		(102,000	)		300,000		24,000

COMPREHENSIVE INCOME		$	3,103,000		$	6,334,000	$	10,805,000

See accompanying notes to these financial statements.

F-5

ELLORA ENERGY INC. AND AFFILIATED ENTITIES
STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003 (CONSOLIDATED), 2004 (CONSOLIDATED) AND 2005 (COMBINED)

		Ellora Energy Inc.
		Ellora Energy Inc.								Ellora Oil and Gas Inc. Common Stock
		Common Stock													Accumulated Other Comprehensive Loss
		Common Stock			Additional Paid-In Capital		Subscription Receivable						Retained Earnings
		Shares	Amount		Additional Paid-In Capital		Subscription Receivable			Shares	Amount		Retained Earnings					Total
BALANCES, January 1, 2003		2,501,667	$	3,000	$	25,186,000	$	(1,667,000	)	—	$	—	$	798,000	$	—		$	24,320,000
	Sale of stock	500,000		—		10,000,000		—		—		—		—		—			10,000,000
	Stock issued for notes	83,333		—		1,333,000		(1,333,000	)	—		—		—		—			—
	Accrued interest on notes	—		—		180,000		(180,000	)	—		—		—		—			—
	Net income	—		—		—		—		—		—		3,205,000		—			3,205,000
	Other comprehensive loss	—		—		—		—		—		—		—		(102,000	)		(102,000	)

BALANCES, December 31, 2003		3,085,000		3,000		36,699,000		(3,180,000	)	—		—		4,003,000		(102,000	)		37,423,000
	Sale of stock	400,000		1,000		7,999,000		—		—		—		—		—			8,000,000
	Stock issued for notes	61,635		—		1,232,000		(1,232,000	)	—		—		—		—			—
	Accrued interest on notes	—		—		237,000		(237,000	)	—		—		—		—			—
	Net income	—		—		—		—		—		—		6,034,000		—			6,034,000
	Change in derivative instrument fair value	—		—		—		—		—		—		—		300,000			300,000

BALANCES, December 31, 2004		3,546,635		4,000		46,167,000		(4,649,000	)	—		—		10,037,000		198,000			51,757,000
	Sale of stock							—		642,500		64,250,000		—		—			64,250,000
	Stock issued for notes	75,735		—		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		3,622,370	$	4,000	$	52,599,000	$	(6,224,000	)	642,500	$	64,250,000	$	20,818,000	$	222,000		$	131,669,000

See accompany notes to these financial statements.

F-6

ELLORA ENERGY INC. AND AFFILIATED ENTITIES
STATEMENTS OF CASH FLOWS

				For the Years Ended December 31,
				2003 Consolidated			2004 Consolidated			2005 Combined
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	3,205,000		$	6,034,000		$	10,781,000
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			1,432,000			3,479,000			8,189,000
		Amortization of derivative asset			—			—			128,000
		Deferred income taxes			2,053,000			3,850,000			9,234,000
		Income from equity investment			(206,000	)		(116,000	)		—
		Cumulative effect of accounting change			(30,000	)		—			—
		Exploration			—			—			387,000
		Non-cash compensation expense			—			—			4,857,000
	Changes in operating assets and liabilities:
		Accounts receivable			(659,000	)		(3,165,000	)		(7,289,000	)
		Prepaid and other current assets			(371,000	)		322,000			(2,428,000	)
		Income taxes receivable			(500,000	)		—			—
		Other long-term assets			—			—			(56,000	)
		Accounts payable and accrued expenses			2,042,000			4,910,000			91,000
		Oil and gas revenues payable			78,000			999,000			7,428,000
		Income taxes payable			(298,000	)		—			—

			Net cash provided by operating activities		6,746,000			16,313,000			31,322,000

CASH FLOWS FROM INVESTING ACTIVITIES:
	Cash acquisition capital expenditures				—			—			(25,795,000	)
	Drilling capital expenditures				(19,090,000	)		(20,616,000	)		(33,935,000	)
	Acquisition of Presco Western, net of working capital of $285,000				—			—			(45,424,000	)
	Pipeline capital expenditures				—			(6,711,000	)		(1,717,000	)
	Purchase of other property and equipment				(176,000	)		(164,000	)		(640,000	)
	Distribution from pipeline				101,000			—			—

		Net cash used in investing activities			(19,165,000	)		(27,491,000	)		(107,511,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from sale of Ellora Energy Inc. common stock				10,000,000			8,000,000			—
	Proceeds from sale of Ellora Oil and Gas Inc. common stock				—			—			64,250,000
	Proceeds from long-term debt under credit agreement				8,500,000			4,350,000			26,750,000
	Payments of long-term debt under credit agreement				(7,950,000	)		—			(11,683,000	)
	Cash paid for derivative asset				(102,000	)		—			(2,715,000	)

		Net cash provided by financing activities			10,448,000			12,350,000			76,602,000

INCREASE (DECREASE) IN CASH					(1,971,000	)		1,172,000			413,000
CASH, beginning of year					3,547,000			1,576,000			2,748,000

CASH, end of year				$	1,576,000		$	2,748,000		$	3,161,000

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest			$	241,000		$	276,000		$	702,000

	Cash paid for taxes			$	300,000		$	—		$	—

NON CASH FINANCING ACTIVITIES:
	Stock issued for subscription agreement			$	1,333,000		$	1,232,000		$	1,265,000

	Accrued interest on subscription notes			$	—		$	237,000		$	310,000

See accompanying notes to these financial statements.

F-7

ELLORA ENERGY INC. AND AFFILIATED ENTITIES
NOTES TO COMBINED 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 with BP Amoco in the Hugoton field in Kansas. Ellora Oil and Gas Inc. also acquired Ellora Energy Inc.'s assets in Colorado and its interests in a joint venture with Centurion Exploration Company. Ellora Energy Inc. and Ellora Oil and Gas Inc. operate oil and gas properties in Texas, Louisiana, Colorado and Kansas and, when combined, 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 Combination and Presentation—The accompanying combined financial statements as of and for the year ended December 31, 2005 include the accounts of Ellora Energy Inc. and Ellora Oil and Gas Inc. These entities are related due to their common ownership All significant intercompany transactions have been eliminated in the combination of the two entities (see Note 8). The consolidated financial statements as of and for the years ended December 31, 2003 and 2004 include the accounts of Ellora Energy Inc. and its subsidiaries.

Cash and Cash Equivalents—Cash equivalents consist of money market accounts and investments which have an original maturity of three months or less.

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.

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 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. The costs of development wells are capitalized whether productive or nonproductive. 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.

F-8

Depletion expense for oil and gas producing property and related equipment was $1,344,000, $3,107,000 and $7,562,000 for the years ended December 31, 2003, 2004 and 2005, 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 future net undiscounted cash flows on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, then the cost of the property is written down to "fair value," which is determined using net discounted future cash flows from the producing property.

Reimbursed Overhead—Ellora Energy Inc. provided various administrative services to Ellora Oil and Gas Inc. for which Ellora Energy Inc. received overhead reimbursements. Amounts earned by Ellora Energy Inc. are included as a reduction to general and administrative expense and totaled $1,050,000 for the year ended December 31, 2005.

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.

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, primarily puts, 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."

F-9

Ellora has formally documented all relationships between hedging instruments and hedged items, as well 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, 2005, accumulated other comprehensive income consisted of $39,000 ($24,000 after tax) of unrealized gains, 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, 2004, accumulated other comprehensive income consisted of $484,000 ($300,000 after tax) of unrealized gains on Ellora's open commodity hedge derivatives. Included as a portion of accumulated other comprehensive loss as of December 31, 2003 was $165,000 ($102,000 after tax) of unrealized losses on Ellora's open commodity hedges.

Prior Year Reclassifications—Certain amounts in the financial statements for 2003 and 2004 have been reclassified to conform to the presentation for 2005. Such reclassifications have had no effect on net income.

Recent Accounting Pronouncements—On December 16, 2004, the Financial Accounting Standards Board ("FASB") published Statement of Financial Accounting Standards No. 123 (Revised 2004), "Share Based Payment" ("SFAS 123(R)"). SFAS 123(R) requires that compensation cost related to share based payment transactions be recognized in the financial statements. Share based payment transactions within the scope of SFAS 123(R) include stock options, restricted stock plans, performance based awards, stock appreciation rights, and employee share purchase plans. The provisions of SFAS 123(R) are effective for Ellora as of the first annual reporting period beginning after December 15, 2005. Accordingly, Ellora will implement the revised standard in the first quarter of 2006. Currently, Ellora accounts for its share based payment transactions under the provisions of APB 25, which does not necessarily require the recognition of compensation cost in the financial statements. Management is assessing the implications of this revised standard and the effect of the adoption of SFAS 123(R) will have on Ellora's financial position, results of operations, or cash flow.

Stock-Based Compensation—Ellora follows the provisions of SFAS No. 123, "Accounting for Stock Based Compensation," for all issuances of stock options to non-employees of Ellora. Ellora applies APB Opinion No. 25 (Opinion 25), "Accounting for Stock Issued to Employees" for all issuances

F-10

of stock options to their employees. No compensation cost has been recognized for stock options granted to employees under the Plans. Had compensation cost for the Plans been determined based upon the provisions of SFAS No. 123, Ellora's net income for 2004 and 2005 would have been decreased to the pro forma amounts indicated below, respectively:

	2003 Consolidated			2004 Consolidated			2005 Combined
Net income—as reported	$	3,205,000		$	6,034,000		$	10,781,000
Pro forma expense		(10,000	)		(240,000	)		(1,344,000	)

Net income—pro forma	$	3,195,000		$	5,794,000		$	9,437,000

The value of each option grant under the Plans is estimated on the date of grant, using the minimum value method described in SFAS No. 123, with the following assumptions:

	2003	2004	2005
Risk-free interest rate	3.0%	5.0%	7.0%
Expected life	7 years	7 years	7-10 years
Expected volatility	0%	0%	0%
Expected dividend	$0	$0	$0

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 the related payable 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.

Per Share Amounts—On July 12, 2006, Ellora completed the private placement of 2,500,000 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. Immediately after the exchange of the shares, the common stock was split 8.09216-for-1 and the earnings per share amounts were calculated using the basic and diluted shares outstanding subsequent to the exchange and stock split. 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 December 31, 2005 were 1,334,957 (subsequent to the stock split that occurred on July 12, 2006, refer to further information at Note 13).

F-11

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

	2003
	2003					2004					2005
				Net Income Per Share		2004					2005
	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	$	3,205,000	21,691,999	$	.15	$	6,034,000	27,541,033	$	.22	$	10,781,000	38,754,598		$.28
Effect of dilutive shares of common stock from stock options			223,303		—			404,608		—			1,334,957		(.01	)
Diluted earnings per share	$	3,205,000	21,915,302	$	.15	$	6,034,000	27,945,641	$	.22	$	10,781,000	40,089,555	$	.27

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.

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.

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.

English Bay Pipeline, L.P.—During 2002, Ellora Energy Inc. acquired a 25% interest in English Bay Pipeline, L.P. (English Bay) in Texas. 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. This investment was accounted for under the equity method until April 2004. In April 2004, Ellora Energy Inc. purchased the remaining 75% interest in English Bay for $6,711,000. The financial information of English Bay is included in Ellora's combined financial statements as of and for the year ended December 31, 2005 and in the consolidated financial statements as of December 31, 2004, and for the period from April 15, 2004 to December 31, 2004. Equity investment income of $116,000 was recorded for English Bay under the equity method of accounting for the period from January 1, 2004 to April 14, 2004.

F-12

The English Bay Pipeline provides gathering services to wells operated by Ellora. For the year ended December 31, 2005, English Bay recorded $1,367,000 of gathering income that is eliminated in the consolidation.

2. ACQUISITIONS:

Ellora completed two acquisitions during 2005:

•: On April 29, 2005, Ellora acquired Presco Western, LLC for approximately $45,000,000 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 $26,000,000 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 preliminary allocation of the purchase price for each transaction based on the acquisition date fair values of the assets acquired and liabilities assumed.

	Presco Western, LLC		Shelby County
Purchase Price:
Cash paid, net of cash received	$	45,424,000	$	25,795,000

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

F-13

The following table reflects the unaudited pro forma results of operations for the twelve months ended December 31, 2004 and 2005 as though the Presco Western, LLC and Shelby County acquisitions had occurred on January 1, 2004.

	Pro Forma Ellora
Year ended December 31, 2004:
Total revenues	$	34,351,000
Net income		9,475,000
Net income per share, basic	$	.34
Net income per share, diluted	$	.34
Year ended December 31, 2005:
Total revenues	$	57,288,000
Net income		11,232,000
Net income per share, basic	$	.29
Net income per share, diluted	$	.28

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, 2004, nor are the pro forma amounts necessarily indicative of the future results of operations of Ellora.

3. FURNITURE AND EQUIPMENT:

At December 31, 2005 and 2004, furniture and equipment consists of the following:

		2004			2005
Office furniture and equipment		$	132,000		$	232,000
Computers			345,000			722,000
Leasehold			29,000			57,000
Other			6,000			141,000

	Total		512,000			1,152,000
Less accumulated depreciation			(218,000	)		(442,000	)

	Furniture and equipment, net	$	294,000		$	710,000

Total depreciation expense related to furniture and equipment amounted to $88,000, $120,000, and $224,000 for the years ended December 31, 2003, 2004, and 2005, respectively.

4. ASSET RETIREMENT OBLIGATION:

F-14

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, 2005, 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:

	2004			2005
Beginning of year	$	348,000		$	368,000
Additional liabilities incurred		30,000			167,000
Accretion expense		28,000			29,000
Revisions to estimate		(38,000	)		152,000

End of year	$	368,000		$	716,000

5. NOTES PAYABLE:

Notes payable, reflected as non-current liabilities in the consolidated balance sheets, consisted of the following:

	December 31,
	2004		2005
Line-of-credit agreement with US Bank in the amount of $40,000,000 dated June 13, 2002 and amended June 9, 2005 bearing interest at prime (4.75% and 7.5% at December 31, 2004 and 2005, respectively) with an available borrowing base of $35,000,000 as of December 31, 2005. The line is collateralized by oil and gas properties and is due June 30, 2006.	$	10,683,000	$	25,750,000

Ellora is subject to various financial covenants, including a minimum working capital requirement, and as of December 31, 2005, is in compliance with all financial statement covenants.

On February 3, 2006, the line of credit with US Bank was paid in full and terminated. 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.

6. STOCKHOLDERS' EQUITY:

Ellora Energy Inc.—At inception, Ellora Energy Inc. issued 2,000,000 shares of common stock for $20,000,000. Ellora Energy Inc. issued 500,000 shares in 2003 for $10,000,000 and 400,000 shares in 2004 for $8,000,000.

Ellora Oil and Gas Inc.—During April 2005, Ellora Oil and Gas Inc. issued 642,500 shares of common stock for $64,250,000.

F-15

Subscription Agreements—For shares of common stock sold and issued to employees, Ellora Energy Inc. has financed the sale of those shares and entered into promissory notes that are collateralized by Ellora Energy Inc.'s stock. The promissory notes have been reflected as a reduction of stockholders' equity and are due June 2009, with an interest rate of 6%. Interest of $727,000 on these subscriptions has been recorded as a reduction to stockholders' equity and an addition to additional paid-in capital.

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 reserved for future issuance as of December 31, 2005.

Ellora Energy Inc. granted the following non-qualified options as of December 31, 2005:

		Number of Options		Weighted Average Exercise Price		Weighted Average Fair Value
Outstanding, January 1, 2003		—		$	—	$	—
	Granted	16,667			10.00		2.92
	Exercised	—			—		—
	Expired	—			—		—

Outstanding, December 31, 2003		16,667			10.00		2.92
	Granted	145,318			14.27		4.17
	Exercised	—			—		—
	Expired	—			—		—

Outstanding, December 31, 2004		161,985			13.83		4.04
	Granted	—			—		—
	Exercised	—			—		—
	Expired	—			—		—
	Cancelled	(31,732	)		12.12		3.54

Outstanding, December 31, 2005		130,253		$	14.24	$	4.16

The above options vest as follows:

	Number of Options	Weighted Average Exercise Price		Weighted Average Fair Value Price
Vested as of December 31, 2005	92,391	$	13.99	$	4.09
Vest in 2006	37,862		14.86		4.35

	130,253	$	14.24	$	4.16

If not previously exercised, the Ellora Energy Inc. options outstanding at December 31, 2005, which were issued under the 2002 Plan and were converted into options issued under Ellora's 2006 Plan following the merger of Ellora Energy Inc. and Ellora Oil and Gas Inc., will expire in 2010.

F-16

Ellora Oil and Gas Inc.—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, 320,000 shares are reserved for future issuance as of December 31, 2005.

Ellora Oil and Gas Inc. granted the following non-qualified options as of December 31, 2005:

	Number of Options	Weighted Average Exercise Price		Weighted Average Fair Value Price
Granted	82,000	$	100.00	$	38.22

Outstanding as of, December 31, 2005	82,000	$	100.00	$	38.22

The above options vest as follows:

	Number of Options	Weighted Average Exercise Price		Weighted Average Fair Value Price
Vested at December 31, 2005	11,389	$	100.00	$	38.22
Vest in 2006	27,333		100.00		38.22
Vest in 2007	27,333		100.00		38.22
Vest in 2008	15,945		100.00		38.22

	82,000	$	100.00	$	38.22

If not previously exercised, the Ellora Oil and Gas Inc. options outstanding at December 31, 2005, which were issued under the 2005 Plan and were converted into options issued under Ellora's 2006 Plan following the merger of Ellora Energy Inc. and Ellora Oil and Gas Inc., will expire in 2010. will expire in 2012.

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.

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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:

		2003			2004		2005
Current taxes		$	(254,000	)	$	—	$	—
Deferred taxes			2,053,000			3,850,000		9,234,000

	Total income tax expense	$	1,799,000		$	3,850,000	$	9,234,000

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:

		2004			2005
Oil and gas properties		$	11,016,000		$	19,615,000
Net operating loss carryforward			(3,340,000	)		(1,955,000	)
Accrued property tax			(95,000	)		(447,000	)
Abandonment obligations			(136,000	)		(276,000	)
Other			237,000			(14,000	)

	Total	$	7,682,000		$	16,923,000

At December 31, 2005, Ellora Energy Inc. and Ellora Oil and Gas Inc. had net operating loss carryforwards for Federal tax purposes of approximately $788,000 and $4,300,000, respectively. Reconciliation of Ellora's effective tax rate to the expected federal tax rate of 35% is as follows:

	2003		2004		2005
Expected Federal tax rate	35	%	35	%	35	%
Permanent difference—stock based compensation	—		—		9	%
State income taxes and other	1	%	4	%	2	%
Effective tax rate	36	%	39	%	46	%

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8. COMBINING FINANCIAL INFORMATION:

Presented below is the condensed combining information of Ellora Energy Inc. and Affiliated Entities (see Note 1):

	Condensed Combining Balance Sheet December 31, 2005
	Ellora Energy Inc.		Ellora Oil and Gas Inc.		Elimination			Total
Current assets	$	16,958,000	$	5,303,000	$	(1,371,000	)	$	20,890,000
Property and equipment, net		110,036,000		68,356,000		(8,298,000	)		170,094,000
Other long term assets		10,199,000		56,849,000		(65,732,000	)		1,316,000

	$	137,193,000	$	130,508,000	$	(75,401,000	)	$	192,300,000


	Liabilities and Stockholders' Equity
Current liabilities	$	14,618,000	$	3,995,000	$	(1,371,000	)	$	17,242,000
Long-term liabilities		42,098,000		1,291,000		—			43,389,000
Stockholders' equity		80,477,000		125,222,000		(74,030,000	)		131,669,000

	$	137,193,000	$	130,508,000	$	(75,401,000	)	$	192,300,000

	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 and impairment		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

F-19

9. COMMITMENTS:

Office Lease—Ellora leases office space with a term through January 31, 2010. Total rental expense was $84,000 and $196,000 for the years ended December 31, 2004 and 2005, respectively. Ellora's obligation for future minimum lease payments under this agreement is as follows:

2006	$	201,000
2007		208,000
2008		221,000
2009		235,000
2010		20,000

	$	885,000

Environmental Issues—Ellora is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental clean up of well sites or other environmental restoration procedures as 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. 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.

10. 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:

		2003		2004		2005
Unproved property acquisition		$	6,803,000	$	—	$	581,000
Proved property acquisition			9,000,000		2,594,000		71,219,000
Development			3,287,000		18,022,000		33,548,000
Exploration			—		—		387,000

	Total	$	19,090,000	$	20,616,000	$	105,735,000

During 2003, 2004 and 2005, additions to oil and gas properties of approximately $294,000, $2,000, and $319,000 were recorded for the estimated costs of future abandonment related to new wells drilled or acquired.

F-20

Net capitalized costs related to Ellora's oil and natural gas producing activities are summarized as follows:

		2003			2004			2005
Proven oil and gas properties		$	34,033,000		$	55,779,000		$	160,283,000
Unproved oil and gas properties			13,089,000			10,732,000			11,313,000
Accumulated depreciation, depletion and amortization			(2,806,000	)		(5,913,000	)		(13,587,000	)

	Oil and gas properties—net	$	44,316,000		$	60,598,000		$	158,009,000

During 2003, Ellora recorded an addition to oil and natural gas properties of $294,000 for the asset retirement costs related to the adoption of SFAS No. 143.

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.

11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

The estimate of proved reserves and related valuations for the year ended December 31, 2005 was based upon the report prepared by Ellora's engineering staff and audited by MHA Petroleum Consultants, Inc., independent petroleum engineers, in accordance with the provisions of Statement of Financial Accounting Standards No. 69 ("SFAS No. 69"), "Disclosures about Oil and Gas Producing Activities." For the years ended December 31, 2003 and 2004, respectively, the estimate of proved reserves and related valuations was based upon the reports of Ellora's engineering staff, in accordance with the provisions of SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." 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-21

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, 2003, 2004 and 2005, are as follows:

		Natural Gas		Oil
		(MMcf)		(MBbl)
Balance—January 1, 2003		80,243		75
	Extensions and discoveries	6,603		141
	Sales of minerals in place	—		—
	Purchases of minerals in place	22,032		66
	Production	(2,386	)	(81	)
	Revisions to previous estimates	21,378		1,038

Balance—December 31, 2003		127,870		1,239
	Extensions and discoveries	11,251		15
	Sales of minerals in place	—		—
	Purchases of minerals in place	—		—
	Production	(3,471	)	(63	)
	Revisions to previous estimates	(11,105	)	(737	)

Balance—December 31, 2004		124,545		454
	Extensions and discoveries	13,843		399
	Sales of minerals in place	—		—
	Purchases of minerals in place	39,644		5,343
	Production	(5,348	)	(125	)
	Revisions to previous estimates	44,140		3,811

Balance—December 31, 2005		216,824		9,882

Proved developed reserves:
	December 31, 2003	46,670		335

	December 31, 2004	41,947		50

	December 31, 2005	60,078		776

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

F-22

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):

		2003			2004			2005
Future cash flows		$	679,423		$	792,940		$	2,318,720
Future production costs			(200,262	)		(196,627	)		(584,350	)
Future development costs			(43,539	)		(83,858	)		(192,583	)
Future income tax expense			(154,465	)		(178,630	)		(540,603	)

Future net cash flows			281,157			333,825			1,001,184
10% annual discount for estimated timing of cash flows			(162,711	)		(197,212	)		(569,524	)

	Standardized measure of discounted future net cash flows	$	118,446		$	136,613		$	431,660

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 on the future cash flows for the years ended December 31, 2003, 2004, and 2005 was immaterial.

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):

	2003			2004			2005
Beginning of year	$	65,260		$	118,446		$	136,613
Sale of oil and gas produced, net of production costs		(8,533	)		(16,950	)		(38,274	)
Net changes in prices and production costs		20,057			61,541			83,379
Extensions, discoveries and improved recoveries		12,835			23,874			64,530
Development costs incurred		8,664			5,163			17,325
Changes in estimated development cost		(28,194	)		(45,483	)		(126,050	)
Purchases of mineral in place		30,117			—			194,177
Revisions of previous quantity estimates		47,573			(32,686	)		266,249
Net change in income taxes		(30,985	)		(8,028	)		(159,979	)
Accretion of discount		9,935			18,352			20,971
Changes in production rates and other		(8,283	)		12,384			(27,281	)

End of year	$	118,446		$	136,613		$	431,660

F-23

Average wellhead prices in effect at December 31, 2003, 2004 and 2005 inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows:

		2003			2004			2005
Oil (per Bbl)		$	30.55		$	39.55		$	56.50
Gas (per Mcf)		$	5.41		$	5.60		$	8.12

12. DERIVATIVE FINANCIAL INSTRUMENTS:

Ellora entered into various futures commitments to minimize the effect of natural gas price fluctuations summarized in the table below. Management does not anticipate that the execution of such transactions will result in any significant losses based on current market conditions. As of December 31, 2005, Ellora had the following outstanding financial natural gas positions:

Contract Type	Weighted Average Strike Price		Quantity	Contract Period
			(Mmbtu)
Futures Put	$	11.00	200,000	January 2006
Futures Put	$	11.00	200,000	February 2006
Futures Put	$	11.00	200,000	March 2006
Futures Put	$	10.00	300,000	May 2006
Futures Put	$	10.00	300,000	June 2006
Futures Put	$	10.00	300,000	July 2006
Futures Put	$	10.00	300,000	August 2006
Futures Put	$	10.00	300,000	September 2006
Futures Put	$	10.00	300,000	October 2006
Futures Put	$	10.00	100,000	November 2006
Futures Put	$	10.00	100,000	December 2006
Futures Put	$	10.00	100,000	January 2007

As of December 31, 2005, the above contracts had an unrealized gain, net of deferred tax effect, of $24,000, which is recorded in other comprehensive income.

13. SUBSEQUENT EVENT:

On July 12, 2006, Ellora Energy Inc. completed the private placement of 2,500,000 shares of common stock pursuant to Rule 144A and Section 4(2) under the Securities Act of 1933, as amended. Immediately prior to the private placement, Ellora Oil and Gas Inc. merged into Ellora Energy Inc. and the shares of Ellora Oil and Gas Inc. were exchanged for shares of Ellora Energy Inc. Net proceeds to Ellora were approximately $27,100,000 after deducting the initial purchaser's discount, placement fees, and offering expenses. Ellora also received approximately $6,300,000 from certain of the selling stockholders for repayment of loans from Ellora including acccrued interest of $928,000. On July 21, 2006, the net proceeds to Ellora from the private placement, and the proceeds received from the repayment of the selling stockholders' loans were used to pay the $30,940,000 line of credit in full.

F-24

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F-25

ELLORA ENERGY INC. AND AFFILIATED ENTITIES

BALANCE SHEETS

				December 31, 2005 Combined			June 30, 2006 Combined
							(unaudited)
*ASSETS*
CURRENT ASSETS:
	Cash			$	3,161,000		$	4,211,000
	Accounts receivable:
		Oil and gas sales			10,522,000			4,677,000
		Joint interest billings			1,242,000			814,000
	Income taxes receivable				500,000			500,000
	Derivative asset				2,625,000			4,975,000
	Prepaids and other current assets				2,840,000			694,000

			Total current assets		20,890,000			15,871,000

PROPERTY AND EQUIPMENT:
	Oil and gas properties (successful efforts method):
		Proved properties			160,283,000			191,430,000
		Unproved properties			11,313,000			7,693,000
	Pipeline properties				11,878,000			12,227,000
	Furniture and equipment				1,152,000			1,519,000

			Total property and equipment		184,626,000			212,869,000
	Less accumulated depletion and depreciation				(14,532,000	)		(19,062,000	)

			Net property and equipment		170,094,000			193,807,000
OTHER LONG-TERM ASSETS					1,316,000			1,509,000

TOTAL ASSETS				$	192,300,000		$	211,187,000

*LIABILITIES AND STOCKHOLDERS' EQUITY*
CURRENT LIABILITIES:
	Accounts payable			$	5,128,000		$	7,330,000
	Accrued expenses				2,637,000			2,097,000
	Oil and gas revenues payable				9,477,000			5,925,000

			Total current liabilities		17,242,000			15,352,000
NOTES PAYABLE					25,750,000			30,940,000
DEFERRED INCOME TAXES					16,923,000			22,164,000
ASSET RETIREMENT OBLIGATIONS					716,000			730,000
COMMITMENTS
STOCKHOLDERS' EQUITY:
	Ellora Energy Inc. common stock, $.001 par value, 5,000,000 shares authorized, 3,622,370 and 3,622,370 issued and outstanding, respectively				4,000			4,000
	Additional paid-in capital				52,599,000			53,501,000
	Subscription receivable and accrued interest				(6,224,000	)		(6,425,000	)
	Ellora Oil and Gas Inc. common stock, $100 par value, 739,000 shares authorized, 642,500 and 642,500 issued and outstanding, respectively				64,250,000			64,250,000
	Retained earnings				20,818,000			28,649,000
	Accumulated other comprehensive income				222,000			2,022,000

			Total stockholders' equity		131,669,000			142,001,000

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY				$	192,300,000		$	211,187,000

See accompanying notes to these financial statements.

F-26

ELLORA ENERGY INC. AND AFFILIATED ENTITIES

UNAUDITED STATEMENTS OF INCOME

			For the six months ended June 30,
			2005 Combined		2006 Combined
REVENUE:
	Oil and gas sales		$	16,146,000	$	26,824,000
	Gas aggregation and pipeline sales			2,092,000		2,429,000
	Gain on oil and gas hedging activities			—		2,421,000
	Interest income and other			77,000		24,000

		Total revenue		18,315,000		31,698,000

COSTS AND EXPENSES:
	Lease operating expense			1,718,000		5,770,000
	Production taxes			321,000		602,000
	Gas aggregation and pipeline cost of sales			1,210,000		2,111,000
	Depreciation, depletion and amortization			2,688,000		4,543,000
	Exploration			—		284,000
	General and administrative (including $4,857,000 and $701,000, respectively, of stock compensation)			8,476,000		4,284,000
	Interest expense			268,000		1,032,000

		Total costs and expenses		14,681,000		18,626,000

INCOME BEFORE INCOME TAXES				3,634,000		13,072,000

INCOME TAXES:
	Deferred income tax expense			3,226,000		5,241,000

NET INCOME			$	408,000	$	7,831,000

BASIC INCOME PER SHARE			$	.01	$	.19

DILUTED INCOME PER SHARE			$	.01	$	.18

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC				35,198,989		42,310,871

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—DILUTED				36,161,260		44,055,137

See accompanying notes to these financial statements.

F-27

ELLORA ENERGY INC. AND AFFILIATED ENTITIES

UNAUDITED STATEMENTS OF COMPREHENSIVE INCOME

		For the six months ended June 30,
		2005 Combined		2006 Combined
NET INCOME		$	408,000	$	7,831,000
OTHER COMPREHENSIVE INCOME:
	Risk management activities, net of tax		—		1,800,000

COMPREHENSIVE INCOME		$	408,000	$	9,631,000

See accompanying notes to these financial statements.

F-28

ELLORA ENERGY INC. AND AFFILIATED ENTITIES

STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
FOR THE YEAR ENDED DECEMBER 31, 2005 (COMBINED) AND THE SIX MONTHS ENDED JUNE 30, 2006 (COMBINED)
(unaudited)

		Ellora Energy Inc.
		Ellora Energy Inc.								Ellora Oil and Gas Inc. Common Stock
		Common Stock													Accumulated Other Comprehensive income
		Common Stock			Additional Paid-In Capital		Subscription Receivable						Retained Earnings
		Shares	Amount		Additional Paid-In Capital		Subscription Receivable			Shares	Amount		Retained Earnings				Total
BALANCES, January 1, 2005		3,546,635	$	4,000	$	46,167,000	$	(4,649,000	)	—	$	—	$	10,037,000	$	198,000	$	51,757,000
	Sale of stock	—		—		—		—		642,500		64,250,000		—		—		64,250,000
	Stock issued for notes	75,735		—		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		3,622,370		4,000		52,599,000		(6,224,000	)	642,500		64,250,000		20,818,000		222,000		131,669,000
	Stock issued for notes	—		—		—		—		—		—		—		—		—
	Accrued interest on notes	—		—		201,000		(201,000	)	—		—		—		—		—
	Non-cash compensation — stock options	—		—		701,000		—		—		—		—		—		701,000
	Net income	—		—		—		—		—		—		7,831,000		—		7,831,000
	Change in derivative instrument fair value	—		—		—		—		—		—		—		1,800,000		1,800,000

BALANCES, June 30, 2006		3,622,370	$	4,000	$	53,501,000	$	(6,425,000	)	642,500	$	64,250,000	$	28,649,000	$	2,022,000	$	142,001,000

See accompanying notes to these financial statements.

F-29

ELLORA ENERGY INC. AND AFFILIATED ENTITIES

UNAUDITED STATEMENTS OF CASH FLOWS

				For the six months ended June 30,
				2005 Combined			2006 Combined
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	408,000		$	7,831,000
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			2,688,000			4,543,000
		Amortization of derivative asset			—			873,000
		Deferred income taxes			3,226,000			5,241,000
		Exploration			—			284,000
		Compensation expense—stock options			—			701,000
		Non-cash compensation expense			4,857,000			—
	Changes in operating assets and liabilities:
		Accounts receivable			(1,025,000	)		6,251,000
		Prepaid and other current assets			321,000			1,658,000
		Other long-term assets			(348,000	)		101,000
		Accounts payable and accrued expenses			(1,020,000	)		452,000
		Oil and gas revenues payable			559,000			(3,552,000	)

			Net cash provided by operating activities		9,666,000			24,383,000

CASH FLOWS FROM INVESTING ACTIVITIES:
	Drilling capital expenditures				(12,491,000	)		(26,823,000	)
	Pipeline capital expenditures				(1,148,000	)		(349,000	)
	Acquisition of Presco Western, net of working capital of $285,000				(45,424,000	)		—
	Purchase of other property and equipment				(558,000	)		(367,000	)

		Net cash used in investing activities			(59,621,000	)		(27,539,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from sale of Ellora Oil & Gas Inc. common stock				64,250,000			—
	Proceeds from long-term debt under credit agreement				1,000,000			31,940,000
	Principal payments of long-term debt under credit agreement				(11,683,000	)		(26,750,000	)
	Loan origination fees				—			(794,000	)
	Loan termination fees				—			(190,000	)

		Net cash provided by financing activities			53,567,000			4,206,000

INCREASE IN CASH					3,612,000			1,050,000
CASH, beginning of period					2,748,000			3,161,000

CASH, end of period				$	6,360,000		$	4,211,000

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest			$	220,000		$	742,000

	Cash paid for taxes			$	—		$	—

NON CASH FINANCING ACTIVITIES:
	Accrued interest on subscription notes			$	147,000		$	201,000

See accompanying notes to these financial statements.

F-30

ELLORA ENERGY INC. AND AFFILIATED ENTITIES

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 is a party to a farmout agreement with BP Amoco in the Hugoton field in Kansas. Ellora Oil and Gas Inc. also acquired Ellora Energy Inc.'s assets in Colorado and its interest in a joint venture with Centurion Exploration Company. Ellora Energy Inc. and Ellora Oil and Gas Inc. operate oil and gas properties in Texas, Louisiana, Colorado and Kansas and, when combined 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 Combination and Presentation—The accompanying combined financial statements as of June 30, 2006 and for the six-month period ended June 30, 2006 include the accounts of Ellora Energy Inc. and Ellora Oil and Gas Inc. These entities are related due to their common ownership. All significant intercompany transactions have been eliminated in the combination of the two entities.

Cash and Cash Equivalents—Cash equivalents consist of money market accounts and investments, which have an original maturity of three months or less.

F-31

Depletion expense for oil and gas producing property and related equipment was $2,494,000 and $4,236,000 for the periods ended June 30, 2005 and 2006, respectively.

Reimbursed Overhead—Ellora Energy Inc. provided various administrative services to Ellora Oil and Gas Inc. for which Ellora Energy Inc. received overhead reimbursements. Amounts earned by Ellora Energy Inc. totaled $900,000 for the period ended June 30, 2006. Such amounts are eliminated in the combination of the entities.

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

F-32

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 six months ended June 30, 2006 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 5, "Stockholders' Equity."

English Bay Pipeline, L.P.—During 2002, Ellora Energy Inc. acquired a 25% interest in English Bay Pipeline, L.P. (English Bay) in Texas. 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. This investment was accounted for under the equity method until April of 2004. In April of 2004, Ellora Energy Inc. purchased the remaining 75% interest in English Bay for $6,711,000. The financial information of English Bay is included in Ellora's combined financial statements as of and for the six months ended June 30, 2005 and June 30, 2006 and as of December 31, 2005.

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The English Bay Pipeline provides gathering services to wells operated by Ellora. For the periods ended June 30, 2005 and 2006, English Bay recorded $859,000 and $898,000, respectively, of gathering income which are eliminated in the consolidation.

Unaudited Information—The accompanying interim financial information as of June 30, 2006 and the six months ended June 30, 2006 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 June 30, 2006 and the results of operations for the six months ended June 30, 2005 and June 30, 2006. The results of operations for the six months ended June 30, 2006 are not necessarily indicative of those to be expected for the year ended December 31, 2006.

2. ACQUISITIONS:

Ellora completed two acquisitions during 2005:

•: On April 29, 2005, Ellora acquired Presco Western, LLC for approximately $45,000,000 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.
•: 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 $26,000,000 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.

3. ASSET RETIREMENT OBLIGATION:

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143 (SFAS No. 143), "Accounting for Asset Retirement Obligations." Ellora adopted SFAS No. 143 beginning January 1, 2003. The most significant impact of this standard on Ellora was a change in the method of accruing for costs to plug and abandon oil and gas properties. Under SFAS No. 143, 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.

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At December 31, 2005 and June 30, 2006, 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, 2005 and June 30, 2006:

	December 31, 2005		June 30, 2006
Beginning of year	$	368,000	$	716,000
Additional liabilities incurred		167,000		—
Accretion expense		29,000		14,000
Revisions to estimate		152,000		—

End of period	$	716,000	$	730,000

4. NOTES PAYABLE:

Notes payable consisted of the following at December 31, 2005 and June 30, 2006:

		December 31, 2005			June 30, 2006
Credit Agreement		$	25,750,000		$	30,940,000

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 weighted average interest rate for the period was 7.49% and the effective interest rate as of June 30, 2006 is 6.63%. The loan is collateralized by Ellora's oil and gas properties and includes certain financial covenants, for which Ellora was in compliance. As of December 31, 2005, Ellora had a $40,000,000 line of credit agreement with a borrowing base of $35,000,000 with US Bank bearing interest at prime, which was 7.5% as of December 31, 2005. On February 3, 2006 the line of credit with US Bank was paid in full and terminated with the proceeds received from the JP Morgan Chase Bank line of credit agreement. The borrowing base for the JP Morgan Chase Bank credit agreement was determined at the discretion of the lenders based on the collateral value of the proved reserves that have been mortgaged to the lenders and is subject to regular redetermination on May 1 and November 1 of each year.

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.

5. STOCKHOLDERS' EQUITY:

Ellora Energy Inc.—At inception, on April 1, 2002, Ellora Energy Inc. issued 2,000,000 shares of common stock for $20,000,000. Ellora Energy Inc. issued 500,000 shares in 2003 for $10,000,000 and 400,000 shares in 2004 for $8,000,000.

Ellora Oil and Gas Inc.—During April 2005, Ellora Oil and Gas Inc. issued 642,500 shares of common stock for $64,250,000.

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Subscription Agreements—For shares of common stock sold and issued to employees, Ellora Energy Inc. has financed the sale of those shares and entered into promissory notes that are collateralized by Ellora Energy Inc.'s stock. The promissory notes have been reflected as a reduction of stockholders' equity and are 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.

Share Based Compensation—Effective January 1, 2006, Ellora adopted SFAS No. 123(R) "Share Based Payment." 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. The option-pricing model requires a number of assumptions, of which the most significant are, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire). The expected volatility was assumed at zero percent because Ellora's stock is not publicly traded. From inception through the period ended June 30, 2006, upon resignation of an employee, 1,000 Ellora Oil and Gas Inc. options were canceled.

For the six months ended June 30, 2005 and 2006, the value of each option grant under the Plans is estimated on the date of grant, using the minimum value method described in SFAS No. 123, with the following assumptions:

	June 30,
	2005	2006
Risk-free interest rate	7.0%	7.0%
Expected life	7-10 years	7-10 years
Expected volatility	0%	0%
Expected dividend	$0	$0

Prior to adopting SFAS No. 123(R), Ellora followed the provision 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 the APB 25, prior to January 1, 2006, no compensation cost has been recognized for stock options granted to employees under the plan. Under the modified prospective method of adopting SFAS No. 123(R), compensation cost recognized for the six months ended June 30, 2006 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.

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Had compensation cost for the 2006 Plan been determined based upon the provisions of SFAS No. 123, Ellora's net income for the six months ended June 30, 2005 would have been decreased to the pro forma amount presented below:

	June 30, 2005
Net income—as reported	$	408,000
Pro forma expense		(704,000	)

Net income—pro forma	$	(296,000	)

For the six months ended June 30, 2006, Ellora recognized share-based compensation costs of $701,000 in the statement of income. Ellora also recognized a total income tax benefit for share-based compensation of $266,000 for the six months ended June 30, 2006.

Ellora Energy Inc. Stock Option Plan—Ellora Energy Inc. adopted the 2002 Stock Option Plan for employees and non-employee directors to receive stock option rewards. Under the 2002 Stock Option Plan, 130,253 shares are reserved for future issuance as of June 30, 2006.

The following table shows a summary of the non-qualified options as of June 30, 2006:

		Number of Options	Weighted Average Exercise Price		Weighted Average Fair Value Price
Outstanding as of December 31, 2005		130,253	$	14.24	$	4.16
	Granted	—
	Exercised	—
	Expired	—

Outstanding as of June 30, 2006		130,253	$	14.24	$	4.16

As of June 30, 2006, 121,561 shares are fully vested and exercisable. In not previously exercised, the Ellora Energy Inc. options outstanding at June 30, 2006 will expire in 2010. The weighted average remaining contractual term of the options outstanding at June 30, 2006 is 3.61 years.

The total estimated unrecognized compensation cost from unvested stock options of Ellora Energy Inc. as of June 30, 2006 was approximately $24,000, which is expected to be recognized during 2006.

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Ellora Oil and Gas Inc. granted the following non-qualified options as of June 30, 2006:

		Number of Options		Weighted Average Exercise Price		Weighted Average Fair Value Price
Outstanding as of December 31, 2005		82,000		$	100.00
	Granted	—
	Exercised	—
	Expired	—
	Cancelled	(1,000	)

Outstanding as of June 30, 2006		81,000		$	100.00	$	38.22

If not previously exercised, the Ellora Oil and Gas Inc. options outstanding at June 30, 2006, which were issued under the 2005 Plan and were converted into options issued under Ellora's 2006 Plan following the merger of Ellora Energy Inc. and Ellora Oil and Gas Inc., will expire in 2015.

Total estimated unrecognized compensation cost from unvested stock options as of June 30, 2006 was approximately $2,015,000, which is expected to be recognized over a period of 2.08 years.

Ellora Energy Inc. Non-Cash Compensation Expense—In 2005, Ellora Energy Inc. sold shares of stock for less than fair value to an officer. Also in 2005, Ellora Energy Inc. made a modification to an existing plan that for financial reporting purposes is also accounted for as a sale of shares stock for less than fair value to an officer who retired. 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.

6. INCOME TAXES:

The provision for income taxes consists of the following:

			June 30, 2005		June 30, 2006
Deferred expense:
	Federal			3,226,000		5,241,000

		Total	$	3,226,000	$	5,241,000

The deferred income tax liability of $22,164,000 for the six months ended June 30, 2006 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. At June 30, 2006, Ellora Energy Inc. and Ellora Oil and Gas Inc. had net operating loss carryforwards for Federal tax purposes of approximately $5,217,000 and $7,314,000, respectively. The 2005 income tax expense does not compute to an expected rate of 38% due to the permanent difference in the stock compensation expense recorded for shares issued to an officer and a retiring officer.

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7. COMMITMENTS:

Office Lease—Ellora leases office space with a term through January 31, 2010. Total rental expense was $97,000 and $107,000 for the periods ended June 30, 2005 and 2006, respectively. Ellora's obligation for future minimum lease payments under this agreement is as follows:

2006	$	101,000
2007		208,000
2008		221,000
2009		235,000
2010		20,000

	$	785,000

Hugoton Farmout—We have the contractual obligation to explore the deep mineral interests in the Hugoton field of Southwest Kansas. We estimate the cost of this obligation at $5,000,000 per year, though we anticipate that we will spend in excess of this minimum amount.

8. DERIVATIVE FINANCIAL INSTRUMENTS

Ellora entered into various futures commitments to minimize the effect of natural gas price fluctuations summarized in the table below. Management does not anticipate that the execution of such transactions will result in any significant losses based on current market conditions. As of June 30, 2006, Ellora had the following outstanding financial natural gas positions:

Contract Type	Weighted Average Strike Price		Quantity	Contract Period
			(MMBtu)
Futures Put	$	10.00	300,000	July 2006
Futures Put	$	10.00	300,000	August 2006
Futures Put	$	10.00	300,000	September 2006
Futures Put	$	10.00	300,000	October 2006
Futures Put	$	10.00	100,000	November 2006
Futures Put	$	10.00	100,000	December 2006
Futures Put	$	10.00	100,000	January 2007

As of June 30, 2006, the above contracts had an unrealized gain, net of deferred tax effect, of $1,800,000 which is recorded in other comprehensive income.

9. SUBSEQUENT EVENT:

On July 12, 2006, Ellora completed the private placement of 2,500,000 shares of common stock pursuant to Rule 144A and Section 4(2) under the Securities Act of 1933, as amended. Immediately prior to the private placement, Ellora Oil and Gas Inc. merged into Ellora Energy Inc. and the shares of Ellora Oil and Gas Inc. were exchanged for shares of Ellora Energy Inc. Net proceeds to Ellora were approximately $27,100,000 after deducting the initial purchaser's discount, placement fees, and offering expenses. Ellora also received approximately $6,300,000

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from certain of the selling stockholders for repayment of loans from Ellora including accrued interest of $928,000. On July 21, 2006, the net proceeds to Ellora from this private placement and the proceeds received from the repayment of the selling stockholders' loans were used to pay the $30,940,000 line of credit in full.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
Ellora Energy Inc.
Boulder, Colorado

We have audited the accompanying statements of income, members' equity and cash flows of Presco Western, LLC for the years ended December 31, 2003 and 2004. 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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the operating results of Presco Western, LLC as of December 31, 2003 and 2004, and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

HEIN & ASSOCIATES LLP
Denver, Colorado
October 2, 2006

See accompanying notes to the financial statements.

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PRESCO WESTERN, LLC

STATEMENTS OF INCOME

			For the Years Ended December 31,				Three Months Ended March 31,
			2003		2004		2005
							(unaudited)
REVENUE:
	Oil and gas sales		$	3,597,000	$	5,792,000	$	1,635,000
	Interest income and other			31,000		66,000		12,000

		Total revenue		3,628,000		5,858,000		1,647,000

COSTS AND EXPENSES:
	Lease operating expense			1,001,000		1,075,000		241,000
	Abandonment expense			—		405,000		—
	Production taxes			85,000		213,000		60,000
	Depreciation, depletion and amortization			223,000		324,000		81,000
	Exploration			5,000		755,000		—
	General and administrative			793,000		894,000		223,000
	Interest expense			8,000		5,000		—

		Total costs and expenses		2,115,000		3,671,000		605,000

NET INCOME				1,513,000		2,187,000		1,042,000
PRO FORMA INCOME TAXES				575,000		831,000		396,000

PRO FORMA NET INCOME			$	938,000	$	1,356,000	$	646,000

See accompanying notes to the financial statements.

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PRESCO WESTERN, LLC

STATEMENTS OF MEMBERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2004
AND THE THREE MONTHS ENDED MARCH 31, 2005

		Members' Equity
BALANCE, January 1, 2003		$	506,000
	Net income		1,513,000

BALANCE, December 31, 2003			2,019,000
	Net income		2,187,000
	Distribution to stockholders		(133,000	)

BALANCE, December 31, 2004			4,073,000
	Net income (unaudited)		1,042,000

BALANCE, March 31, 2005 (unaudited)		$	5,115,000

See accompanying notes to the financial statements.

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PRESCO WESTERN, LLC

STATEMENTS OF CASH FLOWS

				For the Years Ended December 31,						Three Months Ended March 31,
				2003			2004			2005
										(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	1,513,000		$	2,187,000		$	1,042,000
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			223,000			324,000			81,000
		Exploration			5,000			755,000			—
	Changes in operating assets and liabilities:
		Accounts receivable			(232,000	)		(280,000	)		(274,000	)
		Accounts payable and accrued expenses			124,000			419,000			(214,000	)
		Oil and gas revenues payable			—			33,000			33,000

			Net cash provided by operating activities		1,633,000			3,438,000			668,000

CASH FLOWS FROM INVESTING ACTIVITIES:
	Drilling capital expenditures				(1,370,000	)		(3,247,000	)		(731,000	)
	Purchase of other property and equipment				—			—			—

		Net cash used in investing activities			(1,370,000	)		(3,247,000	)		(731,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Capital distribution				—			(133,000	)		—

			Net cash used in financing activities		—			(133,000	)		—

INCREASE (DECREASE) IN CASH					263,000			58,000			(63,000	)
CASH, beginning of period					27,000			290,000			348,000

CASH, end of period				$	290,000		$	348,000		$	285,000

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid for interest			$	—		$	5,000		$	—

	Cash paid for taxes			$	—		$	—		$	—

See accompanying notes to the financial statements.

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PRESCO WESTERN, LLC

NOTES TO FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION:

On April 12, 2005, Ellora acquired Presco Western, LLC ("Presco") for approximately $45,000,000 in cash. These historical financial statements, which include the results of operations, cash flows and members' equity, were required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

Fair Value of Financial Instruments—Presco's financial instruments approximate their fair value because of the short-term maturity of these instruments.

Concentration of Credit Risk—Substantially all of Presco'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 dependent upon the general economic conditions of the industry. Most of the receivables are not collateralized and to date, Presco has had minimal bad debts.

Oil and Gas Producing Operations—Presco 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. The costs of development wells are capitalized whether productive or nonproductive. 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 Presco's expected cost to abandon its well interests. Depletion expense for oil and gas producing property and related equipment was $199,000 and $311,000 for the years ended December 31, 2003 and 2004, 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," Presco 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 future net undiscounted cash flows on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, then the cost of the property is written down to "fair value," which is determined using net discounted future cash flows from the producing property.

Abandonment Liability—Effective January 1, 2003, Presco 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 Presco 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 Presco,

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this Statement applies directly to the plug and abandonment liabilities associated with Presco'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.

Revenue Recognition—Presco 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.

Income Taxes—Presco is a limited liability company under the Internal Revenue Code. As such, it is not subject to income taxes as a separate entity, and its income or loss is required to be included in the income tax returns of its equity holders. For financial presentation purposes, pro forma income tax expense has been calculated on the statements of income using and effective tax rate of 38%

Use of Estimates and Certain Significant Estimates—The preparation of Presco's financial statements in conformity with accounting principles generally accepted in the United States of America requires 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.

Unaudited Information—The accompanying interim financial information for the three months ended March 31, 2005 was taken from Presco'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 results of operations for the three months ended March 31, 2005.

2. COMMITMENTS:

Environmental Issues—Presco is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental clean up of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operation thereof. Acquisition of existing or previously drilled well bores, Presco 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. 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 Presco. Management believes its properties are operated in conformity with local state and Federal regulations. No claim has been made, nor is Presco aware of any uninsured liability that it may have, as it relates to any environmental clean up, restoration or the violation of any rules or regulations relating thereto.

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3. OIL AND GAS ACTIVITIES:

Presco's oil and natural gas activities are entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows:

	2003		2004
Unproved property acquisition	$	—	$	—
Proved property acquisition		—		—
Development		—		2,672,000
Exploration		5,000		755,000

Total	$	5,000	$	3,427,000

During 2003 and 2004, additions to oil and gas properties of approximately $53,000 and $23,000 were recorded for the estimated costs of future abandonment related to new wells drilled or acquired.

During 2003, Presco recorded an addition to oil and natural gas properties of $53,000 for the asset retirement costs related to the adoption of SFAS No. 143.

4. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

Reserve Quantities—The following table summarizes the estimated quantities of proved oil and gas reserves of Presco. These amounts were derived from reserve estimates prepared by Management. 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. The oil and gas reserves stated below are attributable solely to properties within the United States.

			Gas		Oil
			(MMcf)		(MBbl)
Balance—January 1, 2003			1,218		631
	Production		(275	)	(90	)
	Extensions and discoveries		47		403
	Revisions to previous quantity estimate		1,038		(115	)

Balance—December 31, 2003			2,028		829
	Production		(266	)	(153	)
	Extensions and discoveries		2,893		63
	Revisions to previous quantity estimate		(346	)	(103	)

Balance—December 31, 2004			4,309		636

Proved undeveloped reserves:
		December 31, 2002	No undeveloped

		December 31, 2003	No undeveloped

		December 31, 2004	No undeveloped

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Standardized Measure of Discounted Future Net Cash Flows—The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and 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, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. 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 Presco (in thousands).

		2003			2004
Future cash flows		$	39,748		$	50,972
Future production costs			(7,974	)		(10,434	)
Future development costs			(876	)		(5,576	)
Future income tax expense			(11,347	)		(12,233	)

Future net cash flows			19,551			22,729
10% annual discount for estimated timing of cash flows			(8,565	)		(11,278	)

	Standardized measure of discounted future net cash flows	$	10,986		$	11,451

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows (in thousands):

			2003			2004
Beginning of year			$	9,447		$	10,986
	Sale of oil and gas produced, net of production costs			(2,713	)		(4,504	)
	Net changes in prices and production costs			(2,169	)		1,455
	Extensions, discoveries and improved recoveries			5,651			9,039
	Development costs — net			(123	)		(4,700	)
	Revisions of previous quantity estimates			1,239			(3,637	)
	Net change in income taxes			(893	)		213
	Accretion of discount			1,493			1,736
	Changes in production rates and other			(946	)		863

		End of year	$	10,986		$	11,451

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Average wellhead prices in effect at December 31, 2003 and 2004 inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows:

		2003			2004
Oil (per Bbl)		$	30.55		$	39.55
Gas (per Mcf)		$	5.41		$	5.60

F-49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors
Ellora Energy Inc.
Boulder, Colorado

We have audited the accompanying statement of revenues and direct operating expenses of the Shelby County acquisition properties for the year ended December 31, 2004. The statement of revenues and direct operating expenses is the responsibility of the Company's management. Our responsibility is to express an opinion on the statement of revenues and direct operating expenses based on our audit.

We conducted our audit 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 historical summaries are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the historical summaries. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall historical summaries presentation. We believe that our audit provides a reasonable basis for our opinion.

The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission (for inclusion in the Form S-1 of Ellora Energy Inc.) as described in Note 1 and are not intended to be a complete presentation of the properties' revenues and expenses.

In our opinion, the statement of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenue and direct operating expenses of the Shelby County acquisition properties for the year ended December 31, 2004 in conformity with accounting standards generally accepted in the United States of America.

HEIN & ASSOCIATES LLP
Denver, Colorado
October 6, 2006

See accompanying notes to the Statements of Revenues and Direct Operating Expenses

F-50

SHELBY COUNTY ACQUISTION PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEAR ENDED DECEMBER 31, 2004
AND THE SIX MONTHS ENDED JUNE 30, 2005 (UNAUDITED)

			Year Ended December 31, 2004		Six Months Ended June 30, 2005
					(unaudited)
REVENUES—Oil and gas production			$	4,222,000	$	2,559,000

DIRECT OPERATING EXPENSES:
	Lease operating expense			731,000		279,000
	Production taxes			128,000		71,000

		Total direct operating expenses		859,000		350,000

REVENUE IN EXCESS OF DIRECT OPERATING EXPENSES			$	3,363,000	$	2,209,000

See accompanying notes to the Statements of Revenues and Direct Operating Expenses

F-51

SHELBY COUNTY ACQUISTION PROPERTIES

NOTES TO FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION:

On August 31, 2005, Ellora completed its acquisition of additional interests in natural gas fields located in Shelby County, Texas from a minority stockholder and former director of Ellora Energy Inc. for approximately $26,000,000. The properties are referred to herein as the "Shelby County Acquisition Properties," or "Shelby." The purchase price was entirely allocated to oil and gas properties.

Ellora was the operator of these wells prior to the acquisition of the additional interest. The accompanying statements of revenues and direct operating expenses were derived from the historical accounting records of Ellora and reflect the acquired interest in the revenues and direct operating expenses of the Shelby County Acquisition Properties. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense as these costs may not be comparable to the expenses expected to be incurred by Ellora on a prospective basis.

Shelby used the sales method to record gas revenue, where revenue is recognized based on the amount of gas sold to purchasers. Direct operating expenses include payroll, leases and well repairs, production taxes, maintenance, utilities and other direct operating expenses.

The process of preparing financial statements in conformity with generally accepted principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

Historical financial statements reflecting financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis and not meaningful to the Shelby County Acquisition Properties. Accordingly, the historical statements of revenue and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

Unaudited Information—The accompanying interim financial information for the six months ended June 30, 2005 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 results of operations for the six months ended June 30, 2005.

2. SUPPLEMENTAL DISCLOSURES OF OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

Reserve Quantities—The following table summarizes the estimated quantities of proved oil and gas reserves of the Shelby County Acquisition Properties. These amounts were derived from reserve estimates prepared by Management. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and

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development, price changes and other factors. The oil and gas reserves stated below are attributable solely to properties within the United States.

		Gas
		(MMcf)
Balance—January 1, 2004		6,631
	Production	(758	)
	Extensions and discoveries	2,472
	Revisions to previous quantity estimate	1,600

Balance—December 31, 2004		9,945

Proved developed reserves:
	December 31, 2003	6,631

	December 31, 2004	9,945

		2004
Future cash flows		$	62,777
Future production costs			(14,586	)
Future development costs			—
Future income tax expense			(17,054	)

Future net cash flows			31,137
10% annual discount for estimated timing of cash flows			(17,289	)

	Standardized measure of discounted future net cash flows	$	13,848

F-53

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows (in thousands):

			2004
Beginning of year			$	8,587
	Sale of oil and gas produced, net of production costs			(3,363	)
	Net changes in prices and production costs			150
	Extensions, discoveries and improved recoveries			5,327
	Revisions of previous quantity estimates			3,448
	Net change in income taxes			(2,693	)
	Accretion of discount			1,348
	Changes in production rates and other			1,044

		End of year	$	13,848

Average wellhead prices in effect at December 31, 2004, inclusive of adjustments for quality and location used in determining future net revenues, related to the standardized measure calculation are as follows:

		2004
Oil (per Bbl)		$	39.55
Gas (per Mcf)		$	5.60

F-54

Appendix A

November 3, 2006

Mr. T. Scott Martin
Ellora Energy Inc.
5480 Valmont, Suite 350
Boulder, CO 80301

Dear Mr. Martin:

MHA Petroleum Consultants, Inc. ("MHA") has conducted an audit of the estimated net reserve volumes attributed by Ellora Energy Inc. ("Ellora") to certain of Ellora's working interest properties. The effective date of the reserves audited in this report is December 31, 2005 (the "Effective Date"). It is MHA's opinion that the methods and techniques used by Ellora in preparing these reserve estimates are in accordance with generally accepted industry practices and that the proved reserve volumes are appropriately assigned as defined by the U. S. Securities Exchange Commission ("SEC"). MHA further opines that if it were to perform an independent estimate of the reserves, the aggregate volume would be well within 10 percent of Ellora's total volume.

Ellora's reserve estimates included 387 working interest properties located in the states of Colorado, Kansas, Louisiana and Texas. The aggregate reserves for these properties are shown in the following table:

Ellora Energy Inc., Reserves and Economics as of December 31, 2005

Reserve Category	Net Oil, Mbbls	Net Gas, MMscf	Net MMcfe*	Net Present Value Discounted @ 10%, M$
Proved Developed Producing	776.1	60,078.3	64,734.9	194,672.3
Proved Undeveloped	9,106.0	156,746.1	211,382.1	470,068.0
Total All Categories	9,882.1	216,824.4	276,117.0	664,740.3

*: Based on conversion of 6 Mcfe per bbl oil/condensate

Reserve Estimates

Our audit of the estimated net reserve volumes attributed by Ellora to certain of the Ellora's working interest properties was conducted on the basis of the SEC definitions set forth for proved, proved developed and proved undeveloped reserves as set forth in SEC Regulation S-X Part 210.4-10(a) as clarified by the subsequent SEC Staff Accounting Bulletin relating to the same.

Proved Developed Producing (PDP)

Over seventy-five percent of the gas equivalent PDP reserves were attributed to wells completed in the James Lime and Fredericksburg formations of east Texas. Ellora estimated PDP reserves by applying rate-time decline curve techniques. For wells with sufficient production data, a curve was fit to best represent past performance. Both hyperbolic and exponential curves were used. Whenever a hyperbolic curve was used, the forecast was converted to an exponential decline at a minimum decline

A-1

slope of five percent. For wells with limited production data, projections were based on a typical offset well decline parameters adjusted to the specific well's initial production rate.

MHA reviewed in detail the PDP forecasts for sixty-four properties. These properties represented 90.1 percent of Ellora's calculated PDP value (based on a present worth discounted at ten percent). Whenever MHA disagreed with the Ellora forecast, Ellora revised their forecast to be consistent with MHA's recommendations. The total of these revisions reduced Ellora's PDP value by approximately nine percent.

Proved Undeveloped (PUD)

Over sixty-three percent of the gas equivalent PUD reserves are attributed to the James Lime and Fredericksburg formations in east Texas. The next major contributors are the Morrow formation in Kansas (10.5 percent) and the James Lime in western Louisiana (8.6 percent). Ellora's plans indicate that all of the assigned PUD locations will be developed by April, 2010.

Ellora assigned PUD reserves on the basis of an "average well" performance. For the James Lime in Texas, an analysis of 65 wells yielded an average gross well recovery of 3,471.2 MMcf gas and 8,079 bbl of condensate. These values were assigned to PUD locations where the offset PDP wells had estimated ultimate recoveries equal to or greater than this average. The PUD reserves assigned to locations with poorer offset performance were reduced proportionately to either 1,900 MMcf or 900 MMcf (gross) depending on the area. James Lime wells in Louisiana were assigned an average gross EUR of 1,900 MMcf. The Fredericksburg PUD wells were given an average gross EUR of 1,540.9 MMcf gas and 61,638 bbl condensate based on available production data from Ellora's horizontal well completions in Texas and analog production from the Zwolle Field in Louisiana.

PUD reserves for the Kansas properties were again assigned on the basis of "average well" performance in a given formation. Completions in the nine-county area of southwestern Kansas that encompass Ellora's acreage were used in determining the average well recovery. This type of average well calculation is reasonable on a total project basis, given the wide areal distribution of Ellora's Kansas PUD locations. However, it is likely that specific well analyses could show differences of more than ten percent from the average well.

Economic Parameters

Ellora's economic calculations were based on prices received on December 31, 2005, corrected for heating content, basin differentials, and transportation costs. Operating costs, new well investments, and tax burdens were based on Ellora's operations as of the Effective Date in the specific areas. These parameters were briefly reviewed by MHA and seemed reasonable based on MHA's experience.

Statement of Risk

It is MHA's opinion that Ellora's estimated reserve volumes have been prepared in accordance with SEC Regulation S-X Part 210.4-10(a) as clarified by the subsequent SEC Staff Accounting Bulletin relating to the same.

It is important to note that the accuracy of reserve and economic evaluations are subject to uncertainty. The magnitude of this uncertainty is often proportional to the quantity and quality of data available for analysis. As the properties mature, revisions may be required which either increase or decrease the previous reserve assignments. Sometimes these may result not only in a significant change to the reserves and value assigned to a property, but may also impact the total reserve and economic status. Changes in market conditions and sales contracts, along with changes in operating conditions

A-2

and associated costs may also impact the actual ability to recover the estimated reserves and, subsequently, generate the estimated cash flow. Any use of or reliance on this report must accept and consider this uncertainty and risk. MHA makes no warranties concerning the data and interpretations of such data and in no event shall MHA be liable for any special or consequential damages arising from entity's use of this report.

Neither MHA, nor any of our employees have any interest in the subject properties and neither the employment to do this work, nor the compensation therefore, is contingent on our estimates of reserves for the properties described in the Reserve Report.

Sincerely,

Stanley W. Kleinsteiber Vice President

A-3

November 3, 2006

Mr. T. Scott Martin
Ellora Energy Inc.
5480 Valmont, Suite 350
Boulder, CO 80301

Dear Mr. Martin:

MHA Petroleum Consultants, Inc. ("MHA") has prepared an estimate of net reserve volumes, future production and income attributable to certain working interest properties held by Ellora Energy Inc. ("Ellora"). The effective date of the report detailing such reserve estimates ("Reserve Report") and this letter is June 30, 2006. MHA has prepared the Reserve Report using methods and techniques that are in accordance with generally accepted industry practices with the intention that the proved reserve volumes discussed in the Reserve Report may be appropriately assigned as defined by the U. S. Securities Exchange Commission ("SEC").

The reserve and income data have been estimated using SEC guidelines. Pricing was provided by Ellora and price differentials were applied. Operating costs and capital costs were held constant. Reserve estimates and cash flow estimates are dependent on the pricing and cost parameters used in the Reserve Report. Future variations in the pricing and cost parameters will cause variations in the reserve and cash flow estimates.

The Reserve Report includes working interest properties located in the states of Colorado, Kansas, Louisiana and Texas. The aggregate reserves for these properties, as described in the Reserve Report, are summarized in the following table:

Ellora Energy Inc., Reserves and Economics as of June 30, 2006

Reserve Category	Net Oil, Mbbls	Net Gas, MMscf	Net MMcfe*	Net Present Value Discounted @ 10%, M$
Proved Developed Producing	1,846.1	77,288.6	88,365.2	188,856.9
Proved Developed Nonproducing	9.3	5,582.5	5,638.3	12,224.1
Proved Undeveloped	5,732.4	153,097.6	187,492.0	285,692.2
Total All Categories	7,587.8	235,968.7	281,495.5	486,782.2

*: Based on conversion of 6 Mcfe per bbl oil/condensate

The future net revenue in the Reserve Report was based on net hydrocarbon volume sold multiplied by the appropriate price. Expenses include severance and ad valorem taxes, and the normal cost of operating the wells. Future net cash flow is future net revenue minus expenses and any development costs. The future net cash flow has not been adjusted for outstanding loans, which may or may not exist, nor does it include any adjustments for cash on hand or undistributed income. No attempt has been made to quantify or otherwise account for any accumulated gas production imbalances that may exist.

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Reserve Estimates

Reserve estimates included in the Reserve Report were assigned on the basis of the SEC definitions set forth for proved, proved developed and proved undeveloped reserves as set forth in the SEC's Regulation S-X Part 210.4-10(a) as clarified by the subsequent SEC Staff Accounting Bulletin relating to the same.

The reserve estimates included in the Reserve Report were estimated by performance methods, volumetric methods, simulation studies, and comparisons with analogous wells, where applicable. The reserves estimated by the performance method utilized extrapolations of historical production data. Reserves were estimated by analogy in cases where the historical production data was insufficient to establish a definitive trend.

Prices and Costs

Ellora provided the oil and gas prices and differentials for each state as follows:

State	Oil ($/Bbl)	Gas ($/Mcf)	Oil Differential	Gas Differential
Colorado	68.05	5.09	0.0	0.07
Kansas	65.00	5.535	3.3	0.0
Louisiana	70.50	6.04	1.80	(-0.1	)
Texas	70.00	5.745	3.25	(-0.0125	)

The oil and gas price differentials were applied to each well to reflect differences in oil and gas quality, contractual agreements, and regional price variations.

Operating costs used in the report were provided by Ellora and are specific to each well. Operating costs were held constant for the life of the properties. MHA reviewed the operating costs and made appropriate changes where applicable.

Development costs used in the report were provided by the current operator. MHA reviewed these development costs and recent AFEs to insure that they appeared reasonable. No deductions were made for estimated abandonment costs for the properties on the assumption that equipment salvage values would, at a minimum, be equal to abandonment costs. MHA has not performed a detailed study of the abandonment costs and salvage values of the leases. No deductions were made for the indirect costs such as loan repayments, interest expenses, and exploration and development prepayments.

Statement of Risk

The estimated reserve volumes prepared by MHA have been prepared in accordance with the SEC's Regulation S-X Part 210.4-10(a) as clarified by the subsequent SEC Staff Accounting Bulletin relating to the same and the proved reserves and economic calculations conform to year end SEC reporting guidelines.

The accuracy of reserve and economic evaluations is always subject to uncertainty. The magnitude of this uncertainty is often proportional to the quantity and quality of data available for analysis. As a well matures and new information becomes available, revisions may be required which either increase or decrease the previous reserve assignments. Sometimes, these revisions may result not only in a significant change to the reserves and value assigned to a property, but may also impact the total company reserve and economic status. The reserves and forecasts contained in this report were based upon a technical analysis of the available data using accepted engineering principles. However, they must be accepted with the understanding that further information and further reservoir performance

A-5

subsequent to the date of the estimates may justify their revision. It is MHA's opinion that the estimated proven reserves and other reserve information as specified in the Reserve Report and this letter are reasonable, and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.

It was a pleasure performing this work for Ellora. If you have any questions regarding this letter or the Reserve Report, or if additional information is needed, please contact me at this office.

Sincerely,

Leslie S. O'Connor Vice President

A-6

You may rely on the information contained in this prospectus. We have not authorized anyone to provide information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of shares of common stock means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy shares of common stock in any circumstances under which the offer or solicitation is unlawful.

TABLE OF CONTENTS

		PAGE
Prospectus Summary		1
Risk Factors		13
Cautionary Statement Regarding Forward-Looking Statements		25
Use of Proceeds		26
Dividend Policy		26
Capitalization		27
Selected Combined Historical Financial Data		31
Management's Discussion and Analysis of Financial Condition and Results of Operations		34
Business		47
Management		61
Security Ownership of Certain Beneficial Owners and Management		71
Certain Relationships and Related Party Transactions		72
Selling Stockholders		73
Plan of Distribution		81
Description of Capital Stock		84
Shares Eligible For Future Sale		87
Registration Rights		89
Material United States Federal Income Tax Considerations for Non-United States Holders		91
Legal Matters		95
Experts		95
Where You Can Find More Information		95
Glossary of Selected Oil and Gas Terms		96
Index to Financial Statements of Ellora Energy Inc.		F-1
Executive Summary Reports of MHA Petroleum Consultants, Inc.		A-1

11,623,261 SHARES

COMMON STOCK

PROSPECTUS

, 2006

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 Securities and Exchange Commission registration fee and the NASD filing fee, the amounts set forth below are estimates.

SEC registration fee		$	14,925
Legal fees and expenses
Nasdaq Global Market listing fee
Printing and engraving expenses
Engineering fees and expenses
Transfer agent's and registrar's fees
Accounting fees and expenses
Miscellaneous
	Total	$

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 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.

II-1

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 April 12, 2004, we sold 3,075,219 shares of common stock to Yorktown Energy Partners V, L.P. and 161,853 shares of common stock to Sheldon Lubar for aggregate purchase price of $8 million. Also on April 12, 2004, we sold 341,576 shares of our common stock to T. Scott Martin, Richard F. McClure, Valerie K. Walker, John W. Minnett, Gregory Faith (former V.P.) and an employee for an aggregate purchase price consisting of (i) a full recourse promissory notes issued by the purchasers in the total principal amount of $844,118 and (ii) $42.00 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.

2. On July 8, 2005, we sold 364,171 shares of common stock to James R. Casperson, Vice President of Finance and Chief Financial Officer, 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.

3. 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 were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and non-U.S. persons under Regulation S of 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 non-U.S. persons under Regulation S of 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 Regulation S 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 and Regulation S 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.

4. Additionally from April 1, 2002 (inception) through October 31, 2006, we have granted to our employees, including executive officers, and others providing services to us options to purchase 2,996,074 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

II-2

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.

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
3.1		Amended and Restated Certificate of Incorporation of Ellora Energy Inc. (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
3.2		Bylaws of Ellora Energy Inc. dated as of May 17, 2002 (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
3.3		Amendment to the Bylaws of Ellora Energy Inc. dated as of August 27, 2002 (incorporated by reference to Exhibit 3.3 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
3.4		Amendment No. 2 to the Bylaws of Ellora Energy Inc. dated as of September 11, 2006 (incorporated by reference to Exhibit 3.4 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
4.1		Registration Rights Agreement between Ellora Energy Inc. and Friedman, Billings, Ramsey & Co., Inc., dated as of July 12, 2006 (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 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 (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 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 (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
10.2		Employment Agreement dated as of July 12, 2006 between Ellora Energy Inc. and T. Scott Martin (incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
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.) (incorporated by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
10.4		Credit Agreement dated as of February 3, 2006 among Ellora Energy Inc., Ellora Oil & Gas Inc., JPMorgan Chase Bank, N.A. and the Lenders party thereto (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
21.1*		List of Subsidiaries of Ellora Energy Inc.
23.1*		Consent of Hein & Associates LLP.
23.2*		Consent of MHA Petroleum Consultants, Inc.
23.3**		Consent of Thompson & Knight LLP (to be included in Exhibit 5.1).
24*		Power of Attorney (included in the signature page).

*: Filed herewith
**: To be filed by amendment

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(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:

(a)

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i): To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933, as amended;
(ii): To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and
(iii): To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

provided, however, that paragraphs (a)(i), (ii) and (iii) above do not apply if the information required to be included in a post-effective amendment by those paragraphs is contained in reports filed with or furnished to the Commission by the registrant pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the Registration Statement, or is contained in a form of prospectus filed pursuant to Rule 424(b) that is part of this registration statement.

(b): That, for the purpose of determining any liability under the Securities Act of 1933, as amended, each such 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 that time shall be deemed to be the initial bona fide offering thereof.
(c): To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
(d): That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relaying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness;provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to the date of first use.
(e): That, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant's annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report

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pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(f): Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers, and controlling persons of the registrant pursuant to the provisions, 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 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, 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 Act and will be governed by the final adjudication of such issue.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Boulder, State of Colorado, on November 9, 2006.

		ELLORA ENERGY INC.
		By:	/s/ T. SCOTT MARTIN
		Name:	T. Scott Martin
		Title:	President and Chief Executive Officer

POWER OF ATTORNEY

We, the undersigned directors and officers of Ellora Energy Inc., a Delaware corporation, do hereby constitute and appoint T. Scott Martin and James R. Casperson, and each of them, our true and lawful attorney-in-fact and agent, to do any and all acts and things in our names and on our behalf in our capacities as directors and officers and to execute any and all instruments for us and in our name in the capacities indicated below, which said attorney and agent may deem necessary or advisable to enable said Registrant to comply with the Securities Act of 1933 and any rules, regulations and requirements of the Securities and Exchange Commission, in connection with the registration statements, or any registration statement for this offering that is to be effective upon filing pursuant to Rule 462 under the Securities Act of 1933, including specifically, but without limitation, power and authority to sign for us or any of us in our names in the capacities indicated below, any and all amendments (including post-effective amendments) hereof; and we do hereby ratify and confirm all that said attorneys and agents shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated below on November 9, 2006.

Signature	Capacity	Date

/s/ T. SCOTT MARTIN T. Scott Martin	Chairman of the Board President and Chief Executive Officer (Principal Executive Officer)	November 9, 2006
/s/ JAMES R. CASPERSON James R. Casperson	Vice President of Finance and Chief Financial Officer (Principal Accounting Officer)	November 9, 2006
/s/ CORTLANDT S. DIETLER Cortlandt S. Dietler	Director	November 9, 2006
/s/ BRYAN H. LAWRENCE Bryan H. Lawrence	Director	November 9, 2006
/s/ PETER A. LEIDEL Peter A. Leidel	Director	November 9, 2006
/s/ SHELDON B. LUBAR Sheldon B. Lubar	Director	November 9, 2006
/s/ NEIL L. STENBUCK Neil L. Stenbuck	Director	November 9, 2006
/s/ JAMES B. WALLACE James B. Wallace	Director	November 9, 2006
/s/ GEORGE A. WIEGERS George A. Wiegers	Director	November 9, 2006

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INDEX TO EXHIBITS

Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Ellora Energy Inc. (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
3.2		Bylaws of Ellora Energy Inc. dated as of May 17, 2002 (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
3.3		Amendment to the Bylaws of Ellora Energy Inc. dated as of August 27, 2002 (incorporated by reference to Exhibit 3.3 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
3.4		Amendment No. 2 to the Bylaws of Ellora Energy Inc. dated as of September 11, 2006 (incorporated by reference to Exhibit 3.4 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
4.1		Registration Rights Agreement between Ellora Energy Inc. and Friedman, Billings, Ramsey & Co., Inc., dated as of July 12, 2006 (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 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 (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 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 (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
10.2		Employment Agreement dated as of July 12, 2006 between Ellora Energy Inc. and T. Scott Martin (incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
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.) (incorporated by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
10.4		Credit Agreement dated as of February 3, 2006 among Ellora Energy Inc., Ellora Oil & Gas Inc., JPMorgan Chase Bank, N.A. and the Lenders party thereto (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (No. 333-138442) filed on November 3, 2006).
21.1*		List of Subsidiaries of Ellora Energy Inc.
23.1*		Consent of Hein & Associates LLP.
23.2*		Consent of MHA Petroleum Consultants, Inc.
23.3**		Consent of Thompson & Knight LLP (to be included in Exhibit 5.1).
24*		Power of Attorney (included in the signature page).

*: Filed herewith
**: To be filed by amendment

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Ellora Energy Inactive S-1IPO registration