American Noble Gas (AMNI) 10-K 2006 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2006
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from          to

Commission filenumber 0-17204

Infinity Energy Resources, Inc.

(Exact Name of Registrant as Specified in its Charter)

Delaware	20-3126427
(State of Incorporation or Organization)	(I.R.S. Employer Identification No.)
633 Seventeenth Street, Suite 1800 Denver, Colorado	80202 (Zip Code)
(Address of principal executive office)

(720) 932-7800

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined inRule 12b-2 of the Act).

Large accelerated filer o     Accelerated filer þ     Non-accelerated filer o 

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act).  Yes o      No þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2006, was approximately $102 million, based on the closing price of $6.95 per share as reported on the NASDAQ National Market.

As of March 12, 2007, 17,871,157 shares of the registrant’s common stock were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A in connection with the 2006 annual meeting of stockholders are incorporated by reference in Part III of this Report onForm 10-K.

TABLE OF CONTENTS

PART I
Item 1 and Item 2.	Business and Properties	4
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	25
Item 3.	Legal Proceedings	26
Item 4.	Submission of Matters to a Vote of Security Holders	26
PART II
Item 5.	Market for Registrant’s Common Equity and Related Shareholder Matters	26
Item��6.	Selected Financial Data	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	39
Item 8.	Financial Statements	40
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	40
Item 9A.	Controls and Procedures	40
Item 9B.	Other Information	41
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	41
Item 11.	Executive Compensation	41
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	42
Item 13.	Certain Relationships, Related Transactions and Director Independence	42
Item 14.	Principal Accountant Fees and Services	42
PART IV
Item 15.	Exhibits and Financial Statement Schedules	42
Acknowledgement and Termination Agreement
Subsidiaries of the Registrant
Consent of Ehrhardt Keefe Steiner & Hottman PC
Consent of Netherland Sewell & Associates, Inc.
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

FORWARD-LOOKING STATEMENTS

This report onForm 10-K of Infinity Energy Resources, Inc. (“Infinity”), including information incorporated by reference, contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. The use of any statements containing the words “anticipate,” “intend,” “believe,” “estimate,” “project,” “expect,” “plan,” “should” or similar expressions are intended to identify such statement. Forward-looking statements include, among other items:

•  Infinity’s business strategy and anticipated trends in Infinity’s business and its future results of operations;

•  the ability of Infinity to make and integrate acquisitions;

•  the financing of exploration and development operations for our offshore Nicaragua property;

•  commencement and progress of exploration, drilling and completion activities;

•  availability of drilling rigs and other support equipment;

•  the connection of Infinity’s wells to third party pipeline systems;

•  the costs and results of dewatering operations, including drilling water disposal wells;

•  the abandonment of wells and the costs associated therewith;

•  the availability of financing on acceptable terms;

•  the impact of governmental regulation;

•  the timing of engineering and environmental impact studies and permitting;

•  title to assets and related liens and encumbrances;

•  receipt of sufficientrights-of-way grants and permits to operate our business;

•  the impact of cash flows on future operations;

•  the impact of the adoption of Financial Accounting Standards Board (“FASB”) No. 48; and

•  the impact of the adoption of FASB Staff PositionNo. EITF 00-19-2.

Forward-looking statements inherently involve risks and uncertainties that could cause actual results to differ materially from the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to the following and the risks described in “Risk Factors”:

•  fluctuations in oil and natural gas prices and production,

•  inaccurate estimations of required capital expenditures,

•  uncertainties inherent in estimating quantities of oil and gas reserves and projecting future rates of production and timing of development activities,

•  an increase in the cost of oil and gas drilling, completion and production and in materials, fuel and labor costs,

•  the availability, conditions and timing of required government approvals and third party financing,

•  a decline in demand for Infinity’s oil and gas production, and

•  changes in general economic conditions.

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PART I

ITEM 1. AND ITEM 2.   BUSINESS AND PROPERTIES

GENERAL

Infinity Energy Resources, Inc. (“Infinity” or the “Company”) was organized as a Colorado corporation in April 1987 and reincorporated as a Delaware corporation in September 2005. Infinity is an independent energy company engaged in the acquisition, exploration, development and production of natural gas and oil in the United States through our wholly-owned subsidiaries, Infinity Oil and Gas of Texas, Inc. (“Infinity-Texas”) and Infinity Oil & Gas of Wyoming, Inc. (“Infinity-Wyoming”). Our current operations are focused in the Fort Worth Basin of north central Texas and in the Rocky Mountain region in the Greater Green River Basin in southwest Wyoming and the Sand Wash and Piceance Basins in northwest Colorado. Infinity is also pursuing an oil and gas exploration opportunity offshore Nicaragua in the Caribbean Sea. As used in this report,Infinity, we, usandourrefer collectively to Infinity Energy Resources, Inc., its predecessors and subsidiaries or one or more of them as the context may require.

From January 1, 2002 through December 31, 2004, we grew our production through exploration and development drilling exclusively in the Rocky Mountain region. During this period, we completed the drilling of 36 oil and gas wells with a success rate of 75% at our two projects in the Greater Green River Basin. Exploratory wells accounted for 69%, or 25 of the total wells drilled. Beginning in 2005, the Company’s primary exploration focus shifted to the Fort Worth Basin in north central Texas. During 2006 and 2005, we completed the drilling of 27 oil and gas wells with a success rate of over 90%. Exploratory wells accounted for 74%, or 20, of the total wells drilled. Our total proved reserves as of December 31, 2006 were an estimated 7.7 billion cubic feet of gas equivalent (“Bcfe”) with aPV-10 Value (as defined below) of $21.4 million (after-taxPV-10 Value of $21.4 million).

In accordance with our business strategy which is discussed below, we operate 100% of our projects with working interests that range between 50% and 100%.

On December 15, 2006, we sold our oilfield services subsidiaries, Consolidated Oil Well Services, Inc. and CIS Oklahoma, Inc.

Our corporate office is located at 633 Seventeenth Street, Suite 1800, Denver, Colorado 80202. Our telephone number is(720) 932-7800. Our website is http://www.infinity-res.com. We make available, free of charge through our website, our annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. The information on the website is not incorporated or part of this Annual Report onForm 10-K.

Infinity-Texas

Infinity-Texas is engaged in the acquisition, exploration, development and production of natural gas in the Fort Worth Basin of north central Texas. This subsidiary is a Delaware corporation with its headquarters located in Denver, Colorado.

Infinity-Texas was formed in June 2004 to acquire, explore, develop and produce natural gas from the Barnett Shale formation and other producing formations in the Fort Worth Basin. The Barnett Shale is a marine shale formation that is natural gas bearing at depths believed to range from 1,000 to 8,500 feet and is believed to be ubiquitous across the Fort Worth Basin. Though this area has been well known for natural gas production for many years, improvements in fracture techniques and the employment of horizontal drilling in recent years have generally improved the economics of producing this reservoir. In addition, the predominance of leases in the region relate to fee acreage and therefore have relatively few operating restrictions and regulations, as compared to the typical federal or state-owned leases in the Rocky Mountain region that involve more operating restrictions and regulations.

During the three months ended December 31, 2004, Infinity-Texas drilled three gross (2.7 net) wells and completed one gross (0.9 net) well. During 2005, Infinity-Texas drilled 5 wells (4.9 net) and completed seven wells (6.7 net), six as producers and one as a water disposal well. During 2006, Infinity-Texas drilled an additional

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14 wells (14 net) and completed 13 wells (163 net). At December 31, 2006, Infinity-Texas had one gross (and net) well awaiting completion. Infinity-Texas operates all drilled wells and expects to operate future wells. Operating the oil and gas properties in which it owns an interest allows Infinity-Texas to exercise greater control over operating costs, capital expenditures and the timing of exploration, development and exploitation activities.

At December 31, 2006, Infinity-Texas had total estimated proved reserves of 2.5 Bcfe.

Infinity-Wyoming

Infinity-Wyoming is engaged in the acquisition, exploration, development and production of natural gas, condensate and crude oil in the Rocky Mountain region in Wyoming and Colorado. This subsidiary is a Wyoming corporation with its headquarters located in Denver, Colorado.

Infinity-Wyoming was incorporated in January 2000 for the purpose of acquiring properties with the intent of exploring, developing and producing natural gas and coal bed methane. To date, we have developed our proven oil and gas reserves and increased production primarily through acquiring additional oil and gas leaseholds and drilling wells to exploit and develop tight sand and fractured shale properties.

At December 31, 2006, Infinity-Wyoming had total estimated proved reserves of 5.2 Bcfe.

Approximately 1.8 Bcfe of our proved oil and gas reserves were associated with tight sand properties in the Wamsutter Arch Pipeline Field in the Greater Green River Basin in southwest Wyoming (the “Pipeline Field”). Approximately 3.4 Bcfe of our proved reserves relates to fractured Niobrara shale properties in the Sand Wash Basin in Colorado (the “Sand Wash Prospect”).

At December 31, 2006, Infinity-Wyoming operated all of its proved developed oil and gas locations. During the year ended December 31, 2006, Infinity-Wyoming drilled no gross (and net) wells and completed one gross (and net) well drilled in 2005. Infinity-Wyoming drilled seven gross (and net) wells and completed six gross (and net) of such wells during 2005. At December 31, 2006, Infinity-Wyoming had six gross (and net) wells awaiting completion or abandonment operations in Wyoming. Operating the oil and gas properties in which it owns an interest allows Infinity-Wyoming to exercise greater control over operating costs, capital expenditures and the timing of exploration, development and exploitation activities.

Nicaragua

Since 1999, Infinity has pursued an oil and gas exploration opportunity offshore Nicaragua in the Caribbean Sea. Over such time period, the relationships which have been built with the Instituto Nicaraguense de Energia (“INE”) and the geological and geophysical research that was done allowed Infinity to become one of only six companies qualified to bid on offshore blocks in the first international bidding round held by INE in January 2003. Infinity was awarded the bid on 24 blocks of acreage, comprising approximately 1.4 million acres, in May 2003, and finalized the initial exploration and production contract for the two underlying prospects (Tyra and Perlas) in May 2006.

Discontinued Operations

On December 15, 2006, we sold all of our ownership interest in Consolidated Oil Well Services, Inc. and CIS Oklahoma, Inc. (collectively, “Consolidated”), which were wholly owned subsidiaries providing oilfield services in eastern Kansas, northeast Oklahoma and northeast Wyoming. We sold Consolidated to Q Consolidated Oil Well Services, LLC for approximately $52 million in cash. As a result of the sale, our business is now focused solely on the acquisition, exploration, development and production of natural gas and crude oil.

BUSINESS STRATEGY

Our principal objective is to create stockholder value through the execution of our business strategy. We will seek to: (i) consummate acquisitions of early-stage oil and gas properties, acreage leaseholds and prospects; (ii) explore such properties or prospects to discover underlying, commercially-viable hydrocarbon resource bases; (iii) develop such hydrocarbon resource bases into proved and producing reserves; (iv) operate and produce

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hydrocarbons from such reserve bases; and (v) sell or otherwise monetize such reserve bases at attractive valuations. We will usually seek to operate our exploration and production projects with a maximum working interest and net revenue interest, with exceptions or adjustments being made in situations in which the risk or capital requirements to explore, develop and produce from a given project are deemed high enough to warrant a partner, which may bring to the given project greater financial and technical resources than we have or are willing to commit.

We intend to finance our business strategies through employment of working capital, cash flow from operations, net proceeds from the sales of assets, and exercises of options and warrants and through external financing, which may include debt and equity capital raised in public and private offerings. Essentially all of our assets serve as collateral under our new credit facility, and as such, any disposition of material assets would require the approval of the lender.

In addition, the Company has retained an investment bank to explore its strategic alternatives, including a sale of some or all of its assets. The Company and its investment bank are actively engaged in discussions with numerous parties regarding its strategic alternatives. The Company cannot predict the outcome of these discussions, whether a transaction might be consummated, or the potential impact of such a transaction on the Company’s stockholders.

EXPLORATION AND PRODUCTION

Properties

This section is an explanation and detail of some of the relevant project groupings from our overall inventory of projects and prospects. Our operations are focused primarily in the Fort Worth Basin of Texas and the Greater Green River and Sand Wash Basins in the Rocky Mountain region. Our other area of interest is in the Caribbean Sea, offshore Nicaragua.

Fort Worth Basin

For purposes of presentation, we divide our Fort Worth Basin operations into two main property areas: Erath and Hamilton Counties, Texas and Comanche County, Texas.

Erath and Hamilton Counties, Texas

At December 31, 2006, Infinity-Texas held leases on approximately 41,000 gross (approximately 34,000 net) acres in this area located in the southwest portion of the Fort Worth Basin in north central Texas. Infinity-Texas currently seeks to explore for, develop and produce natural gas and natural gas liquids from the Barnett Shale, and possibly shallower formations. At December 31, 2006, Infinity-Texas operated 19 gross (18.6 net) wells in the area, of which 13 were active producers, five were shut-in, and one was a water disposal well. Infinity-Texas has a 90% average working interest and a 72% average net revenue interest in the acreage in this area. During 2006, Infinity-Texas produced approximately 765,000 thousand cubic feet (“Mcf”) of natural gas from the field, compared to 189,000 Mcf of natural gas produced from the field in 2005. Production during 2006 represented a 304% increase from 2005.

During 2004, Infinity-Texas horizontally drilled three wells, completing one of those wells prior to yearend 2004. During 2005, Infinity-Texas horizontally drilled an additional four wells and completed six wells. Infinity-Texas also vertically drilled a water disposal well in 2005 for the disposal of frac flowback fluids and water produced from its wells in the area. During 2006, Infinity-Texas horizontally drilled an additional 10 wells, vertically drilled one well and completed all 11 wells. During 2006, Infinity-Texas shot approximately 34 square miles of3-D seismic data principally over the southern portion of its acreage in Erath County. Infinity-Texas believes it has a multi-year drilling inventory available to it in this area, adjusting for and reflective of spacing requirements and surface or lease restrictions. Infinity-Texas has a drilling rig under contract for a minimum two-well commitment, is currently drilling one horizontal well, and expects completion operations to follow the drilling. Dependent upon the success of operations in early 2007, Infinity-Texas may seek to extend the contract to accelerate drilling and completion operations in the Erath and Hamilton Counties area in 2007.

In the first two months of 2007, Infinity-Texas has spud one horizontal well, which is expected to be completed in April 2007. During 2007, Infinity-Texas intends to interpret the approximately 26 square miles of3-D seismic data shot generally over the southern portion of its Erath County acreage.

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Comanche County, Texas

At December 31, 2006, Infinity-Texas held leases on approximately 34,000 gross (and net) acres in this area, located approximately 30 miles southwest of the Erath and Hamilton County properties. During 2006, Infinity-Texas vertically drilled 3 wells and completed 2 wells in Comanche County. During 2007, Infinity-Texas expects to explore for natural gas from the Barnett Shale and Lower Marble Falls formations at varying depths between 2,400 and 2,700 feet. Infinity-Texas has a 100% working interest and 80% net revenue interest in the acreage in this area. During 2006, Infinity-Texas produced approximately 11,000 Mcf of natural gas from the field.

Greater Green River Basin

For purposes of presentation, we divide our Greater Green River Basin operations into two main property areas: Pipeline Field and Labarge Field.

Pipeline Field

At December 31, 2006, Infinity-Wyoming held leases on approximately 21,000 gross acres (approximately 18,000 net acres) located on the Wamsutter Arch in the Greater Green River Basin of southwest Wyoming. Infinity-Wyoming currently seeks to exploit hydrocarbons in the cretaceous-aged Upper Almond sand at varying depths between 2,800 and 3,600 feet. At December 31, 2006, Infinity-Wyoming operated 38 wells in the field, of which 19 were active producers, 11 were shut-in, three were water disposal wells, and five were awaiting completion or plugging and abandonment operations.

During 2006, Infinity-Wyoming produced approximately 365,000 Mcf of natural gas and 16,000 barrels of crude oil, or 461,000 thousand cubic feet of natural gas equivalent (“Mcfe”) from the field, compared to 670,000 Mcf of natural gas and 25,000 barrels of crude oil, or 820,000 Mcfe produced from the field in 2005. Production during 2006 represented a 44% decrease from 2005. Production has generally declined since peaking in the quarter ended March 31, 2003.

Labarge Field

At December 31, 2006, Infinity-Wyoming held leases on approximately 11,000 gross (and 11,000 net) acres located on the northern extension of the Moxa Arch in southwest Wyoming and held options on an additional approximately 18,000 gross acres. Infinity-Wyoming currently seeks to exploit hydrocarbons in the Cretaceous Upper Mesaverde coals at varying depths between 3,400 and 4,200 feet. At December 31, 2006, Infinity-Wyoming operated 12 wells in the field, of which 10 were shut-in, and two were water disposal wells.

Infinity-Wyoming produced approximately 3,000 Mcf of natural gas from the field during 2006, as compared to approximately 12,000 Mcf of natural gas during 2005. Production during 2006 represented a 75% decrease as compared to 2005. Production has generally declined since peaking in the quarter ended September 30, 2002, when production reached 20,600 Mcfe. Production at Labarge has continued to be generally uneconomic.

Infinity-Wyoming has been subject to a Bureau of Land Management environmental impact study (“EIS”) on the Labarge Field and the Pinedale Resource Management Plan federal acreage. The EIS must be completed before significant development can occur. The EIS was commenced in 2002 and was originally anticipated to be completed in six to eight months. Infinity-Wyoming currently anticipates that an EIS covering the Greater Labarge Area will be completed during 2012.

Northwest Colorado

For purposes of presentation, we divide our northwest Colorado operations into two main property areas: Sand Wash Prospect and Piceance Basin Prospect.

Sand Wash Prospect

At December 31, 2006, Infinity-Wyoming held leases on approximately 36,000 gross acres (and net acres) located in the Sand Wash Basin of northwest Colorado and south central Wyoming. Infinity-Wyoming currently seeks to explore and develop hydrocarbons in the fractured Niobrara calcareous shale between 5,500 and 6,500 feet.

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Secondary objectives include exploiting the Williams Fork and Iles coals at varying depths between 2,500 and 3,000 feet.

At December 31, 2006, Infinity-Wyoming operated two producing oil properties and five shut-in wells in the field. Infinity-Wyoming continues to seek the acquisition of additional geophysical data in order to better delineate future prospective drilling locations.

During 2006, Infinity-Wyoming produced approximately 73,000 gross barrels (58,000 net barrels) of oil from this field as compared to approximately 53,000 gross barrels (43,000 net barrels) of oil from this field during 2005.

Infinity-Wyoming plans to conduct additional geological and geophysical studies to identify potential additional oil locations. As it pertains to the Williams Fork and Iles coals, Infinity-Wyoming suspended dewatering efforts at the original pilot location in 2004 due to the onset of winter and the resulting substantial production of ice on the surface. No measurable gas production was achieved during 2004. Infinity-Wyoming will need to further evaluate the results of the dewatering process prior to determining what additional operations, if any, to perform.

Piceance Basin Prospect

At December 31, 2006, Infinity-Wyoming held leases on approximately 8,000 gross (and net) acres in the northeastern corner of the Piceance Basin in northwest Colorado. The acreage is located along the northern rim of the Piceance Basin and the southern extent of the Axial Basin Arch. Immediately adjacent to the prospect are several large oil and gas fields which were discovered and developed as early as 1927. Most notable of these is the Wilson Creek field to the south, which has produced approximately 90 million barrels of oil and 75 Bcf of natural gas. Primary reservoir targets would include the Niobrara fractured shale and the Dakota and Morrison-Brushy Creek sandstone formations. Secondary reservoir targets might include the Mesaverde sands and coals, Morrison-Salt Wash, Entrada, Shinarump, Moenkopi, Weber and Morgan-Minturn formations. Infinity-Wyoming plans to conduct additional geological and geophysical studies in 2007 to identify potential 2008 drilling opportunities.

Nicaragua

Subsequent to being awarded two concessions in 2003, Infinity negotiated a number of key terms and conditions of an exploration and production contract covering the approximate 1.4 million acre Tyra (approximately 823,000 acres in the north) and Perlas (approximately 566,000 acres in the south) concession areas offshore Nicaragua. The contract, which was finalized in May 2006, contemplates an exploration period of up to six years with foursub-phases and a production period of up to 30 additional years (with a potential five-year extension). The initial capital costs during the first twelve months, for which Infinity has issued two letters of credit, are expected to total approximately $850,000, with a total of less than $2.0 million during the second twelve months, to cover costs of environmental studies, geological and geophysical analysis, acquisition of seismic data and other operational expenses. Infinity will not be able to begin exploration until the INE has determined the requirements for an environmental impact study.

Exploration offshore Nicaragua would focus on Eocene and Cretaceous Carbonate reservoirs and Infinity’s management and consultants believe: (i) numerous analogies can be made between the Infinity concession block and production from fractured Cretaceous carbonates in Mexico, Venezuela and Guatemala and (ii) the presence of Cretaceous source rocks onshore Honduras and Nicaragua can be projected into the offshore Caribbean Shelf. Infinity plans to seek offers from another industry operator or operators for interests in the acreage in exchange for cash and a carried interest in exploration and development operations. No assurance can be given that any such transactions will be consummated.

Oil and Natural Gas Reserves

We engaged Netherland, Sewell & Associates, Inc., independent petroleum engineers, to prepare estimates of proved reserves, projected future production and related future net revenue for our properties as of December 31, 2006. Estimates prepared by Netherland, Sewell & Associates, Inc. were based upon review of production histories and other geologic, economic, ownership, volumetric and engineering data. In estimating reserve quantities that are economically recoverable, oil and gas prices and estimated development and production costs as of December 31, 2006 were utilized.

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The following table sets forth estimates as of December 31, 2006 derived from the Netherland, Sewell & Associates, Inc. reserve report. The present value (discounted at 10 percent) of estimated future net revenue before income taxes(“PV-10 Value”) shown in the table is not intended to represent the current market value of our estimated proved oil and gas reserves. For additional information concerning the present value of future net revenue from these proved reserves, see Note 14 — Supplemental Oil and Gas Information (Unaudited) in the Notes to the Consolidated Financial Statements.

	Developed		Undeveloped		Total
Natural gas (Mcf)		3,779,185		—		3,779,185
Crude oil (barrels)		648,462		—		648,462
Total (Mcfe)		7,669,957		—		7,669,957
Future net revenue before income taxes (in thousands)	$	32,211	$	—	$	32,211
Present value of future net revenue before income taxes (in thousands)	$	21,376	$	—	$	21,376

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, the reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including future geologic success, prices, production levels and costs that may not prove correct. Predictions about prices and future production levels are subject to great uncertainty and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. There is no assurance that prices will not be materially higher or lower than the prices utilized in estimating the reserves.

The weighted average sales prices utilized for purposes of estimating our proved reserves and future net revenue therefrom as of December 31, 2006 were $5.66 per Mcf of natural gas and $48.56 per barrel of crude oil.

Production, Prices and Production Costs

The following table sets forth Infinity’s net oil and gas production, average sales prices realized, and costs and expenses associated with such production during the years indicated.

	2006		2005		2004
Production:
Natural gas (Mcf)		1,142,305		875,543		953,428
Crude oil (barrels)		81,203		68,497		33,668
Total (Mcfe)		1,629,524		1,286,525		1,155,436
Average daily production:
Natural gas (Mcf)		3,130		2,399		2,612
Crude oil (barrels)		222		188		92
Total (Mcfe)		4,464		3,525		3,164
Average sales price per unit:
Natural gas ($ per Mcf)	$	6.12	$	6.06	$	5.12
Crude oil ($ per barrel)	$	64.94	$	56.74	$	41.15
Total ($ per Mcfe)	$	7.53	$	7.14	$	5.42
Production costs per Mcfe	$	3.31	$	3.44	$	2.28

Infinity owned 36 gross (33.8 net) producing wells and six gross (six net) service wells as of December 31, 2006. Infinity owned an additional 33 gross (32.8 net) wells which were shut in, awaiting completion or plugging and abandonment operations as of December 31, 2006.

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Development, Exploration and Acquisition Capital Expenditures

The following table sets forth certain information regarding the costs incurred by Infinity in the purchase of proved and unproved properties and in development and exploration activities (in thousands):

	2006		2005		2004
Property acquisition costs
Proved	$	—	$	330	$	516
Unproved		4,844		5,745		3,625
Total property acquisition costs		4,844		6,075		4,141
Development costs		892		17,099		6,156
Exploration costs		24,865		17,583		5,294
Asset retirement costs		77		907		93
Total costs	$	30,678	$	41,664	$	15,684

Drilling Activity

The following table sets forth certain information regarding the wells completed during the years indicated. Frequently wells are spud or drilled in one period and completed in a subsequent period. In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.

	2006				2005				2004
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Productive		13		13		6		5.7		3		2.9
Nonproductive		—		—		1		1.0		—		—
Total		13		13		7		6.7		3		2.9
Development Wells
Service		—		—		1		1.0		—		—
Productive		1		1		5		5.0		9		8.0
Nonproductive		—		—		1		1.0		—		—
Total		1		1		7		7.0		9		8.0

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Acreage Data

The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases held by Infinity-Texas and Infinity-Wyoming as of December 31, 2006. Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Fort Worth Basin		6,000		5,000		69,000		63,000
Greater Green River Basin:
Wamsutter Arch		5,000		4,000		16,000		14,000
Labarge		2,000		2,000		9,000		9,000
Sand Wash Prospect		1,000		1,000		35,000		35,000
Piceance Basin Prospect		—		—		8,000		8,000
Total Onshore U.S.		14,000		12,000		137,000		129,000
Offshore Nicaragua		—		—		1,389,000		1,389,000
Total		14,000		12,000		1,526,000		1,518,000

Infinity-Wyoming held options on an additional approximately 18,000 gross acres in the Labarge field as of December 31, 2006.

Customers and Markets

The majority of Infinity-Wyoming’s gas production from the Pipeline Field is sold to Mountain Gas Resources at the Inside FERC, first of the month CIG Index, a published pricing index on which gas sales contracts in the Rocky Mountains are generally based. Infinity-Wyoming enters into fixed price contracts to hedge its production when market conditions are deemed favorable in order to manage price fluctuations and achieve a more predictable cash flow. The majority of Infinity-Texas’ gas production is sold to Louis Dreyfus Gas Development L.P. based on the daily WAHA index, a published pricing index on which gas sales in the Western Forth Worth and the Permian Basins are often based.

As of December 31, 2006, oil production from the Pipeline Field was being sold at the average daily NYMEX posted price less $.50 per barrel and oil production from the Sand Wash Prospect is sold at the average daily NYMEX posted price less $14.37 per barrel.

Based on the general demand for oil and natural gas, Infinity does not believe that a loss of any customer would have a material adverse effect on its business.

Competition

Infinity and its subsidiaries compete in virtually all facets of their businesses with numerous other companies in the oil and gas industry, including many that have significantly greater financial and other resources. Such competitors may be able to pay more for desirable oil and gas leases and to evaluate, bid for, and purchase a greater number of properties than the financial or personnel resources of Infinity permit.

Infinity’s business strategy includes highly competitive oil and natural gas acquisition, exploration, development and production. There can be no assurance, however, that Infinity or its subsidiaries will be able to successfully acquire identified targets, or have the financing available for the acquisitions. We face intense competition from a large number of independent exploration and development companies as well as major oil and gas companies in a number of areas such as:

•  Acquisition of desirable producing properties or new leases for future exploration;

•  Marketing our oil and natural gas production; and

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•  Seeking to acquire the services, equipment, labor and materials necessary to explore, operate and develop those properties.

Many of our competitors have financial and technological resources substantially exceeding those available to Infinity. Many oil and gas properties are sold in a competitive bidding process in which we may lack technological information or expertise available to other bidders. We cannot be sure that we will be successful in acquiring and developing profitable properties in the face of this competition.

Delivery Commitments

Effective September 2001, Infinity-Wyoming entered into a gas gathering and transportation contract with a third-party gatherer and processor in which the third-party gatherer and processor built gas gathering laterals and installed compression facilities to deliver gas produced from the Pipeline Field to the Overland Trail Transmission pipeline. During 2002, the contract was amended to include additional compression and gathering facilities to be installed by the third-party gatherer and processor and delivery points for the additional production being generated by Infinity-Wyoming. Infinity-Wyoming pays a gathering fee of approximately $0.40 per Mcf until 7,500,000 Mcf have been produced at which time the fee is to be reduced to $0.25 per Mcf. Additionally, the Company had annual volume commitments for five years starting September 1, 2001. If the Company exceeded the minimum in any year, the excess reduced the following year’s commitment. If the Company did not meet the minimum in any year, the shortfall was added to the following years. To date, Infinity-Wyoming has delivered approximately 4,545,000 Mcf under this contract. The Pipeline sales volumes are also subject to a $0.15 per MMBtu charge for access onto the Overland Trail Transmission line. While Infinity-Wyoming has failed to deliver the volumes required under the terms of the contract, the pipeline operators have also not provided the compression and gathering capabilities they were required to provide under the contract. Management is currently negotiating revised volume commitments under a lengthened contract with the third-party gatherer and processor.

In June 2005, the Company entered into a long-term gas gathering contract for natural gas production from the Company’s properties in Erath County, Texas, under which the Company pays a gathering fee of $0.35 per Mcf gathered. The contract contains minimum delivery volume commitments through June 30, 2015 associated with firm transportation rights. Under provisions of the contract, in December 2006 the Company reduced the minimum daily delivery volumes by 50%.

Government Regulation of the Oil and Gas Industry

General

Infinity’s business is affected by numerous laws and regulations, including, among others, laws and regulations relating to energy, environment, conservation and tax. Failure to comply with these laws and regulations may result in the assessment of administrative, civiland/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to Infinity, we cannot predict the overall effect of such laws and regulations on our future operations.

Infinity believes that its operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry.

The following discussion contains summaries of certain laws and regulations and is qualified as mentioned above.

Federal Regulation of the Sale of Oil and Gas

Various aspects of Infinity’s oil and natural gas operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In the past, the federal government has regulated the prices at which oil and gas could be sold. While “first sales” by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at

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uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

Commencing in April 1992, the FERC issued Order Nos. 636,636-A, 636-B, 636-C and636-D (“Order No. 636”), which require interstate pipelines to provide transportation services separate, or “unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipelines to provide open access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate Infinity’s production activities, FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry.

Regulation of Operations

Infinity conducts certain operations on federal oil and gas leases, which are administered by the Bureau of Land Management (“BLM”). Of Infinity-Wyoming’s Pipeline Field acreage, approximately 15,000 gross acres are leases that are administered by the BLM. Approximately 3,000 acres of 11,000 total acres of Infinity-Wyoming’s Labarge Field acreage, including acreage subject to options, are part of federal units for which Infinity-Wyoming is the operator for the development of the resources to certain depths. The Piceance Basin Prospect and Sand Wash Prospect acreage also include acreage that is administered by the BLM. Federal leases contain relatively standard terms and require compliance with detailed BLM regulations and orders, which are subject to change. Among other restrictions, the BLM has regulations restricting the flaring or venting of natural gas, and the BLM has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Under certain circumstances, the BLM may require any company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect Infinity’s financial condition, cash flows and operations.

The Minerals Management Service (“MMS”) administers the valuation, payment and reporting for royalties on oil and gas produced from federal leases. The BLM issued a final rule that amended its regulations governing the valuation of gas produced from federal leases. This rule primarily affects the transportation allowance used to value the federal royalty.

Exploration and production operations of Infinity-Texas and Infinity-Wyoming are subject to various types of regulation at the federal, state, and local levels. These regulations include requiring permits and drilling bonds for the drilling of wells and regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing 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 spacing, plugging and abandonment of such wells. The operation and production of Infinity-Wyoming’s properties is subject to the rules and regulations of the Wyoming Oil and Gas Conservation Commission (WYOGCC) and the Colorado Oil and Gas Conservation Commission (COGCC). In addition a portion of the properties are on federal lands and are subject to Onshore Orders 1 and 2, The National Historic Preservation Act (NHPA), National Environmental Policy Act (NEPA) and the Endangered Species Act. The operation and production of Infinity-Texas’ properties is subject to the rules and regulations of the Railroad Commission of Texas (RRC).

Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, BLM, MMS, state commissions and the courts. Infinity cannot predict when or whether any such proposals and proceedings may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, Infinity does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of Infinity or its subsidiaries.

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Environmental and Land Use Regulation

Various federal, state and local laws and regulations relating to the protection of the environment affect our operations and costs. The areas affected include:

•  unit production expenses primarily related to the control and limitation of air emissions, spill prevention and the disposal of produced water;

•  capital costs to drill development wells resulting from expenses primarily related to the management and disposal of drilling fluids and other oil and natural gas exploration wastes;

•  capital costs to construct, maintain and upgrade equipment and facilities;

•  operational costs associated with ongoing compliance and monitoring activities; and

•  exit costs for operations that we are responsible for closing, including costs for dismantling and abandoning wells and remediating environmental impacts.

The environmental and land use laws and regulations affecting oil and natural gas operations have been changed frequently in the past, and in general, these changes have imposed more stringent requirements that increase operating costsand/or require capital expenditures in order to remain in compliance. We believe that our business operations are in substantial compliance with current laws and regulations. Failure to comply with these requirements can result in civiland/or criminal fines and liability for non-compliance,clean-up costs and other environmental damages. It is also possible that unanticipated developments or changes in law could cause us to make environmental expenditures significantly greater than those we currently expect.

The following is a summary discussion of the framework of key environmental and land use regulations and requirements affecting our oil and natural gas exploration, development, production and transportation operations.

Discharges to Waters.  The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and comparable state statutes impose restrictions and controls, primarily through the issuance of permits, on the discharge of produced waters and other oil and natural gas wastes into regulated waters and wetlands. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future, including potential restrictions on the use of hydraulic fracturing. These laws prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters without a permit.

The Clean Water Act also regulates stormwater discharges from industrial properties and construction activities and requires separate permits and implementation of a stormwater management plan establishing best management practices, training, and periodic monitoring. Certain operations are also required to develop and implement “Spill Prevention, Control, and Countermeasure” plans or Facility Response Plans to address potential oil spills.

The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It also imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances into regulated waters.

Oil Spill Regulations.  The Oil Pollution Act of 1990, as amended (the “OPA”), amends and augments oil spill provisions of the Clean Water Act, imposing potentially unlimited liability on responsible parties, without regard to fault, for the costs of cleanup and other damages resulting from an oil spill in U.S. waters. Responsible parties include (i) owners and operators of onshore facilities and pipelines and (ii) lessees or permittees of offshore facilities.

Air Emissions.  Our operations are subject to local, state and federal regulations governing emissions of air pollution. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission

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sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies including the MMS, BLM and state agencies.

We may generate wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, although certain oil and natural gas exploration and production wastes currently are exempt from regulation under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA (“Hazardous Wastes”). Furthermore, it is possible that certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes, and therefore be subject to more rigorous and costly operating, disposal andclean-up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both on- and off-shore.

Superfund.  Under some environmental laws, such as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, also known as CERCLA or the Superfund law, and similar state statutes, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon any current or former site owners or operators, or upon any party who discharged one or more designated substances (“Hazardous Substances”) at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of Hazardous Substances, in the course of our operations we may have generated and may generate wastes that fall within CERCLA’s definition of Hazardous Substances. We may also be an owner or operator of facilities at which Hazardous Substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.

Abandonment and Remediation Requirements.  Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities, and the environmental restoration of operations sites. The Colorado Oil and Gas Conservation Commission, Wyoming Oil and Gas Conservation Commission and the Texas Railroad Commission are the principal state agencies and BLM the primary federal agency responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state. State and BLM regulations require operators to post performance bonds.

Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations

Significant potential costs relating to environmental and land use regulations associated with our existing properties and operations include those relating to (i) plugging and abandonment of facilities,(ii) clean-up costs and damages due to spills or other releases and (iii) civil penalties imposed for spills, releases or non-compliance with applicable laws and regulations.

Infinity-Texas and Infinity-Wyoming currently own or lease properties that are being used for the disposal of drilling and produced fluids from exploration, development and production of oil and gas. Although these subsidiaries follow operating and disposal practices that they considers appropriate under applicable laws and regulations, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the subsidiaries or on or under other locations where such wastes were taken for disposal. Infinity could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act or comparable state statutes for contamination caused by wastes it generated or for contamination existing on properties it owns or leases, even if the contamination was caused by the waste disposal practices of the prior owners or operators of the properties. In addition, it is not uncommon for landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of produced fluids or other pollutants into the environment.

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During December 2006, Infinity-Wyoming produced an average of 30 barrels of water per day from wells that it operates. Infinity-Wyoming currently uses four injection wells to dispose of the water into underground rock formations and plans to continue to use this method for disposal of the water produced from its operated wells. If the future wells produce water of lesser quality than allowed under state law for injection in underground rock formations or at a volume greater than can be injected into the current disposal wells, Infinity-Wyoming could incur costs of up to $7.50 per barrel of water to dispose of the produced water. At current production rates, this would cost Infinity-Wyoming approximately an additional $4,500 a month in water disposal costs. If Infinity-Wyoming’s wells produce water in excess of the limits of its permitted facilities, Infinity-Wyoming may have to drill additional disposal wells. Each additional disposal well could cost Infinity-Wyoming approximately $600,000. It costs Infinity-Wyoming approximately $1,500 per month to operate these disposal wells.

Infinity-Texas utilizes significant quantities of water in the fracture and stimulation of its wells in the Fort Worth Basin. Typically a high percentage of this water flows back and must be disposed of. Infinity-Texas drilled one disposal well in Erath County, Texas during 2005 at a cost of approximately $1,000,000. It costs Infinity-Texas approximately $12,000 per month to operate this disposal well.

Title to Properties

As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time Infinity acquires leases of properties believed to be suitable for drilling operations. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by independent attorneys. Once production from a given well is established, Infinity prepares a division order title opinion indicating the proper parties and percentages for payment or production proceeds, including royalties. We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficientrights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, such as those described under “Risk Factors.” In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us.

Employees

On December 31, 2006, Infinity and its subsidiaries had 16 employees.

ITEM 1A.   RISK FACTORS

We have a history of losses and we may be unable to achieve long-term profitability.

We incurred a net loss from continuing operations in our fiscal years ended December 31, 2006, 2005 and 2004 of approximately $58.8 million, $19.9 million and $9.8 million, respectively. Our history of losses may impair our ability to obtain financing for drilling and other business activities on favorable terms or at all. It may also impair our ability to attract investors if we attempt to raise additional capital, to grow our business or for other business purposes, by selling additional debt or equity securities in a private or public offering. Future losses incurred by the Company, if any, may also impact our ability to satisfy the financial covenants under our new credit facility.

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Our ability to achieve a profit from operations on a long-term basis will largely depend on whether we are successful in exploring for and producing oil and gas from our existing properties. We face the following potential risks in developing our oil and gas properties:

•  prices for oil and gas we produce may be lower than expected;

•  the capital, equipment, personnel or services required to develop the leases for production may not be available;

•  we may not find oil and gas reserves in the quantities anticipated;

•  the reserves we find may not produce oil and gas at the rate anticipated;

•  the costs of producing oil and gas may be higher than expected; and

•  we may encounter one or more of many operating risks associated with drilling for and producing oil and gas.

Oil and gas prices are volatile, and declines in prices would hurt our ability to achieve profitable operations.

Our future oil and gas revenue, operating results, profitability, future rate of growth and the carrying value of oil and gas properties will depend heavily on prevailing market prices for oil and gas. We expect the market for oil and gas to continue to be volatile for the foreseeable future. Excluding sales under a fixed price contract which averaged $4.57 per Mcf, gas price realizations ranged from a low of $3.88 per Mcf to a high of $7.48 per Mcf during the year ended December 31, 2006. Oil price realizations ranged from a low of $47.85 per barrel to a high of $73.95 per barrel during the year. Based on fourth quarter 2006 production levels, each $1.00 decrease in the price of crude oil per barrel would reduce Infinity’s oil revenue by approximately $15,000 per month and each $0.10 decrease in natural gas price per Mcf would reduce Infinity’s gas revenue by approximately $30,000 per month.

Approximately 49% of our proved reserves are natural gas and approximately 51% of our reserves are oil. Therefore, the volatility in the price of natural gas and oil will both have a significant impact on our operations. Various factors beyond our control affect prices of oil and gas, including:

•  worldwide and domestic supplies of oil and gas;

•  political instability or armed conflict in oil or gas producing regions;

•  the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil prices;

•  production controls;

•  the price and level of foreign imports;

•  worldwide economic conditions;

•  marketability of production;

•  the level of consumer demand;

•  the price, availability and acceptance of alternative fuels;

•  the price, availability and capacity of commodity processing and gathering facilities, and pipeline transportation;

•  weather conditions; and

•  actions of federal, state, local and foreign authorities.

These external factors and the volatile nature of the energy markets generally make it difficult to estimate future prices of oil and gas. Significant declines in oil and natural gas prices for an extended period may cause various negative effects on our business, including:

•  impairing our financial condition, cash flows and liquidity;

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•  limiting our ability to finance planned capital expenditures;

•  reducing our revenue, operating income and profitability; and

•  reducing the carrying value of our oil and natural gas properties.

A charge to earnings and book value would occur if there is a further ceiling write-down of the carrying value of our oil and gas properties. Impairments can occur when oil and gas prices are depressed or unusually volatile. Once incurred, a ceiling write-down of oil and gas properties is not reversible at a later date when better industry conditions may exist. We review, on a quarterly basis, the carrying value of our oil and gas properties under the full cost accounting rules of the SEC. Under these rules, costs of proved oil and gas properties may not exceed the present value of estimated future net revenue after giving effect to cash flow from hedges but excluding the future cash out flows associated with settling asset retirement obligations, discounted at 10%, net of taxes. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter, after giving effect to Infinity’s cash flow hedge positions, if any, and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time.

At December 31, 2006, the carrying amount of oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $14,300,000 based upon an average natural gas price of $5.66 per Mcf and an average oil price of $48.56 per barrel in effect at that date. However, based on subsequent pricing of approximately $7.07 per Mcf of gas and approximately $47.60 per barrel of oil at the March 5, 2007 measurement date, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $11,200,000. Therefore, the Company recorded an additional ceiling writedown of $11,200,000 at December 31, 2006, for a total writedown of $37,800,000 in 2006. In 2005 and 2004, the Company also recorded ceiling writedowns of $13,450,000 and $4,100,000. A decrease in oil or gas prices (which continue to remain volatile) an increase in production costs, a decrease in estimated gas production in future periods, or the reclassification of development costs to properties subject to depletion without an increase in associated proved reserves could result in a ceiling write-down during future periods.

Prices may be affected by regional factors.

The prices to be received for the natural gas production from our Wyoming and Texas properties will be determined mainly by factors affecting the regional supply of and demand for natural gas, which include the degree to which pipeline and refining and processing infrastructure exists in the region. Regional differences could cause negative basis differentials, which could be significant, between the published indices generally used to establish the price received for regional production and the actual price received by us for our production.

Forward sales and hedging transactions may limit our potential gains or expose us to losses.

To manage our exposure to price risks in the marketing of our natural gas, time to time we enter into fixed price natural gas physical delivery contracts for a portion of our current or future production. In addition, under the terms of our new credit facility, we are required to hedge at least 70% of projected production from our proved developed producing properties. These transactions could limit our potential gains if natural gas prices were to rise substantially over the prices established by the contracts. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•  our production is less than expected;

•  the counterparties to our contracts fail to perform under the contracts; or

•  our production costs on the contracted production significantly increase.

Exploration and development of our oil and gas projects will require large amounts of capital which we may not be able to obtain.

Full exploration and development of our properties could require drilling in excess of 1,000 production wells, 100 disposal wells to handle produced water, and the construction of 100 production facilities. This could require capital expenditures over time of in excess of $1 billion. Currently, our potential sources of financing for these

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activities are cash generated by operations, availability under our credit facility, future sales of equity securities or subordinated debt securities. Historically, a significant portion of cash flows from Infinity’s former oilfield services business was used to fund corporate overhead, debt service (or interest) and a portion of Infinity’s oil and gas exploration and development activities. The absence of such cash flows is expected to increase the overall debt required by Infinity to fund such activities in the future.

Future cash flows and the availability of financing are subject to a number of variables, such as:

•  our oil and gas projects in the Fort Worth Basin of Texas, Greater Green River Basin of Wyoming, and Sand Wash and Piceance Basins of Colorado achieving a level of production that provides sufficient cash flow to support additional borrowings and to attract other forms of debt and equity capital;

•  our success in locating and producing new reserves;

•  prices of crude oil and natural gas;

•  the level of production from existing wells; and

•  amounts of necessary working capital and expenses.

Issuing equity securities to satisfy our financing or refinancing requirements could cause substantial dilution to existing stockholders. Debt financing could lead to:

•  all or a substantial portion of our operating cash flow being dedicated to the payment of principal and interest;

•  an increase in interest expense as the amount of debt outstanding increases or as variable interest rates increase;

•  increased vulnerability to competitive pressures and economic downturns; and

•  restrictions on our operations that may be contained in any contract entered into with lenders.

In order to reduce our capital needs, while continuing development of our oil and gas projects, we could enter into partnerships with another oil and gas company or companies in which we would maintain a carried or reduced working interest in the oil and gas properties. However, this would reduce our ownership and control over the projects and could significantly reduce our future revenue generated from oil and gas production.

If projected revenue were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we were not able to obtain the necessary capital, our ability to execute development plans or maintain production levels could be limited.

The covenants and debt service obligations of our new credit facility may adversely affect our cash flow and our ability to raise additional capital.

Our new credit facility entered into in January 2007 is secured by a pledge of substantially all of our natural gas and oil properties, is guaranteed by our subsidiaries and contains covenants that limit additional borrowings, dividends to stockholders, the incurrence of liens, investments, sales or pledges of assets, changes in control and other matters. The credit facility also requires that specified financial ratios be maintained, including ratios regarding debt to EBITDA, interest coverage and collateral coverage. If we are unable to comply with the financial and other covenants of our new credit facility, our results of operations and financial condition may be adversely affected. The restrictions of our credit facility may have adverse consequences on our operations and financial results including:

•  it may be more difficult for us to satisfy our debt repayment obligations;

•  covenant violations, if any, could result in accelerated payment terms on existing debt;

•  the amount of our interest expense may increase because our borrowings are at a variable rate of interest, which, if interest rates increase, would result in higher interest expense;

•  we will need to use a portion of our revenue to pay principal and interest on our debt, which will reduce the amount of money we have to finance our operations and other business activities; and

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•  substantially all of our properties are pledged as collateral to lenders and failure to pay could result in foreclosure and loss of assets.

As of March 9, 2007, the principal amount of our long-term debt totaled approximately $9.5 million. Our level of debt could have important negative consequences to our business.

We may not be able to refinance our debt or obtain additional financing, particularly in view of the restrictions imposed by our credit facility on our ability to incur other debt and the fact that substantially all of our assets are currently pledged to secure obligations under that facility. Our overall level of long-term debt and our difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results including:

•  any additional financing we obtain may be on unfavorable terms;

•  we may have a higher level of debt than many of our competitors, which may place us at a competitive disadvantage;

•  we may issue equity securities at an undesired or unanticipated point in time to repay indebtedness, causing additional dilution to our stockholders;

•  we may be more vulnerable to economic downturns and adverse developments in our industry; and

•  our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industries in which we operate.

Information concerning our reserves, future net cash flow estimates, and potential future ceilingwrite-downs is uncertain.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values. Actual production, revenue and reserve expenditures will likely vary from estimates.

Estimates of oil and natural gas reserves are projections based on available geologic, geophysical, production and engineering data. There are uncertainties inherent in the manner of producing and the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of factors including:

•  the quality and quantity of available data;

•  the interpretation of that data;

•  the accuracy of various mandated economic assumptions; and

•  the judgment of the persons preparing the estimate.

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Since our wells in Texas have been producing for less than two years, other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir are used, in conjunction with the decline analysis method, to determine our estimates of proved reserves. As our wells are produced over time and more data is available, our estimated proved reserves will be redetermined at least annually and may be adjusted based on that data.

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices. Our reserves may also be susceptible to drainage by operators on adjacent properties.

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Investors should not construe the present value of future net cash flows as the current market value of the estimated oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Factors that will affect actual future net cash flows include:

•  the amount and timing of actual production;

•  the price for which that oil and gas production can be sold;

•  supply and demand for oil and natural gas;

•  curtailments or increases in consumption by natural gas and oil purchasers; and

•  changes in government regulations or taxation.

As a result of these and other factors, we will be required to periodically reassess the amount of our reserves, which may require us to recognize a ceiling write-down of our oil and gas properties. In 2006, 2005 and 2004 we recorded ceiling write downs of $37,800,000, $13,450,000 and $4,100,000, respectively. These factors could cause us to write down the value of our properties in future periods.

As of December 31, 2006, we had approximately $26.8 million invested in unproved oil and gas properties not subject to amortization. During 2007, a portion of the investment in unproved oil and gas properties may be reclassified to the full cost pool subject to depletion and the ceiling test, following our required periodic evaluation of the fair value of our unproved properties. The amount of any such reclassification could be significant. We could be required to write down a portion of the full cost pool of oil and gas properties subject to amortization upon reclassification of the unproved oil and gas property costs.

The oil and gas exploration business involves a high degree of business and financial risk.

The business of exploring for and developing oil and gas properties involves a high degree of business and financial risk. Property acquisition decisions generally are based on assumptions about the quantity, quality, production costs, marketability, and sales price for the acreage or reserves being acquired. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately the ultimate production potential, if any, of a particular property or well. Any decision to acquire a property is also influenced by our subjective judgment as to whether we will be able to locate the reserves, drill and equip the wells to produce the reserves, operate the wells economically, and market the production from the wells.

Our operations are dependent upon the availability of certain resources, including drilling rigs, steel casing, water, chemicals, and other materials necessary to support our development plans and maintenance requirements. The lack of availability of one or more of these resources at an acceptable price could have a material adverse affect on our business.

The successful completion of an oil or gas well does not ensure a profit on investment. A variety of factors may negatively affect the commercial viability of any particular well, including:

•  defects in title;

•  the absence of producible quantities of oil and gas;

•  insufficient formation attributes, such as porosity, to allow production;

•  water production requiring disposal; and

•  improperly pressured reservoirs from which to produce the reserves.

In addition, market-related factors may cause a well to become uneconomic or only marginally economic, such as:

•  availability and cost of equipment and transportation for the production;

•  demand for the oil and gas produced; and

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•  price for the oil and gas produced.

Our business is subject to operating hazards that could result in substantial losses against which we may not be insured.

The oil and natural gas business involves operating hazards, any of which could cause substantial losses, such as:

•  well blowouts;

•  craterings;

•  explosions;

•  uncontrollable flows of oil, natural gas or well fluids;

•  fires;

•  formations with abnormal pressures;

•  pipeline ruptures or spills; and

•  releases of toxic gas and other environmental hazards and pollution.

As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. Our insurance premiums can be increased or decreased based on the claims made by us under insurance policies. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. Whenever possible, we obtain agreements from customers that limit our liability; however, insurance and customer agreements do not provide complete protection against losses and risks and losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

In addition, we may be liable for environmental damage caused by previous owners of property we own or lease. As a result, we may face substantial potential liabilities to third parties or governmental entities that could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses. An event that is not fully covered by insurance — for instance, losses resulting from pollution and environmental risks that are not fully insured — could cause us to incur material losses.

We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired.

Exploratory drilling is an uncertain process with many risks.

Exploratory drilling involves numerous risks, including the risk that we will not find commercially productive natural gas or oil reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:

•  unexpected drilling conditions;

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•  pressure or irregularities in formations;

•  equipment failures or accidents;

•  adverse weather conditions;

•  defects in title;

•  compliance with governmental requirements, rules and regulations; and

•  shortages or delays in the availability of drilling rigs, the delivery of equipment and adequately trained personnel.

Our future drilling activities may not be successful, and we cannot be sure of our overall drilling success rate. Unsuccessful drilling activities would result in significant expenses being incurred without any financial gain.

Our business will depend on transportation facilities owned by others.

The marketability of our gas production will depend in part on the availability, proximity and capacity of pipeline systems owned by third parties. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own under interruptible or short-term transportation agreements. The transportation of our gas may be interrupted due to capacity constraints on the applicable system, or for maintenance or repair of the system. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of markets, systems or pipelines.

The oil and gas industry is heavily regulated and we must comply with complex governmental regulations.

Federal, state and local authorities extensively regulate the oil and gas industry and the drilling and completion of oil and gas wells. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may adversely affect, among other things, the pricing and production or marketing of oil and gas. Noncompliance with statutes and regulations may lead to substantial penalties and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. Federal, state and local authorities regulate various aspects of oil and gas drilling, service and production activities, including the drilling of wells through permit and bonding requirements, the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration.

Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local government authorities. Infinity spent approximately $1.0 million to drill and equip one water disposal well in 2005 to handle water produced from gas wells. It costs Infinity up to $150,000 per year to operate a disposal well. New laws or regulations, or changes to current requirements, could result in our incurring significant additional costs. We could face significant liabilities to government and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation.

Although we believe that we are in substantial compliance with all applicable laws and regulations, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not harm our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:

•  land use restrictions;

•  drilling bonds and other financial responsibility requirements;

•  spacing of wells;

•  emissions into the air;

•  unitization and pooling of properties;

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•  habitat and endangered species protection, reclamation and remediation;

•  the containment and disposal of hazardous substances, oil field waste and other waste materials;

•  the use of underground storage tanks;

•  the use of underground injection wells, which affects the disposal of water from our wells;

•  safety precautions;

•  the prevention of oil spills;

•  the closure of production facilities;

•  operational reporting; and

•  taxation.

Under these laws and regulations, we could be liable for:

•  personal injuries;

•  property and natural resource damages;

•  releases or discharges of hazardous materials;

•  well reclamation costs;

•  oil spillclean-up costs;

•  other remediation andclean-up costs;

•  plugging and abandonment costs, which may be particularly high in the case of offshore facilities;

•  governmental sanctions, such as fines and penalties; and

•  other environmental damages.

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities.

Our operations and facilities are subject to numerous environmental laws, rules and regulations, including laws concerning:

•  the containment and disposal of hazardous substances, oilfield waste and other waste materials;

•  the use of underground storage tanks; and

•  the use of underground injection wells.

Compliance with and violations of laws protecting the environment may become more costly. Sanctions for failure to comply with these laws, rules and regulations, many of which may be applied retroactively, may include:

•  administrative, civil and criminal penalties;

•  revocation of permits; and

•  corrective action orders.

In the United States, environmental laws and regulations typically impose strict liability. Strict liability means that in some situations we could be exposed to liability for cleanup costs and other damages as a result of our conduct, even if such conduct was lawful at the time it occurred, or as a result of the conduct of prior operators or other third parties. Cleanup costs, natural resource damages and other damages arising as a result of environmental laws and regulations, and costs associated with changes in environmental laws and regulations, could be substantial. From time to time, claims have been made against us under environmental laws. Changes in environmental laws and regulations may also negatively impact other oil and natural gas exploration and production companies, which in turn could reduce the demand for our oilfield services.

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Large volumes of water produced from coalbed methane wells and discharged onto the surface in the Powder River Basin of Wyoming have drawn the attention of government agencies, gas producers, citizens and environmental groups which may result in new regulations for the disposal of produced water. We intend to use injection wells to dispose of water into underground rock formations at certain of our fields and intend to discharge onto the surface where permissible. If our wells produce water of lesser quality than allowed under Colorado, Texas or Wyoming state law for surface discharge or injection into underground rock formations, we could incur costs of up to $7.50 per barrel of water to dispose of the produced water. At December 2006 production rates, this disposal would cost us an additional $180,000 per month in average water disposal costs. If our wells produce water in excess of the limits of our existing disposal facilities, we may have to drill additional disposal wells. Each additional disposal well could cost us up to $1.0 million.

The oil and gas industry is highly competitive.

We operate in the highly competitive areas of oil and natural gas acquisition, exploration, development and production with many other companies. We face intense competition from a large number of independent companies as well as major oil and natural gas companies in a number of areas such as:

•  acquisition of desirable producing properties or new leases for future exploration;

•  marketing our oil and natural gas production;

•  arranging for growth capital on attractive terms; and

•  seeking to acquire or secure the equipment, service, labor, other personnel and materials necessary to explore, operate and develop those properties.

Many of our competitors have financial and technological resources substantially exceeding those available to us. Many oil and gas properties are sold in a competitive bidding process in which we may lack technological information or expertise or financial resources available to other bidders. We cannot be sure that we will be successful in acquiring and developing profitable properties in the face of this competition.

We may have difficulty managing growth in our business.

Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

We depend on key personnel.

The loss of key members of our management team, or difficulty attracting and retaining experienced technical personnel, could reduce our competitiveness and prospects for future success. Our success depends on the continued services of our executive officers and a limited number of other senior management and technical personnel. Loss of the services of any of these people could have a material adverse effect on our operations. We do not have employment agreements with any of our executive officers. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for experienced explorationists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

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ITEM 3.   LEGAL PROCEEDINGS

There are currently no pending material legal proceedings to which we are a party.

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5.   MARKET FOR COMMON EQUITY AND RELATED SHAREHOLDER MATTERS

Principal Market and Price Range of Common Stock

Infinity’s Common Stock began trading on the Nasdaq Global Market on June 29, 1994, under the symbol “IFNY.” The following table sets forth the high and low closing sale prices for Infinity’s Common Stock as reported by the Nasdaq Stock Market. The closing price of the Common Stock on March 9, 2006 was $3.20 per share.

Quarter Ended	High		Low
March 31, 2005	$	13.79	$	7.68
June 30, 2005		10.52		7.52
September 30, 2005		8.97		7.21
December 31, 2005		8.39		6.23
March 31, 2006	$	9.40	$	6.85
June 30, 2006		8.45		6.03
September 30, 2006		7.04		3.87
December 31, 2006		4.00		3.20

Approximate Number of Holders of Common Stock

At March 9, 2007, there were approximately 400 stockholders of record of Infinity’s $0.0001 par value Common Stock and an estimated 4,000 beneficial holders whose Common Stock is held in street name by brokerage houses.

Dividends

Holders of common stock are entitled to receive such dividends as may be declared by Infinity’s Board of Directors. Infinity has not declared nor paid and does not anticipate declaring or paying any dividends on its common stock in the near future. Any future determination as to the declaration and payment of dividends will be at the discretion of Infinity’s board of directors and will depend on then-existing conditions, including Infinity’s financial condition, results of operations, contractual restrictions, capital requirements, business prospects and such other factors as the board deems relevant. Pursuant to the terms of its new Credit Facility, Infinity is prohibited from paying dividends.

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ITEM 6.   SELECTED FINANCIAL DATA

The selected consolidated financial information presented below for the years ended December 31, 2006, 2005, 2004, 2003 and 2002 is derived from the audited consolidated financial statements of Infinity. Certain reclassifications have been made to prior financial data to conform to the current presentation. The table gives effect to thetwo-for-one split of Infinity’s common stock effective May 13, 2002 for all periods presented. The table also gives effect to the December 15, 2006 sale of the Company’s oilfield services business, which has been reflected as a discontinued operation for all periods presented. The following table should be read in conjunction with Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below, and the Consolidated Financial Statements and Notes thereto.

	As of or for the Years Ended December 31,
	2006			2005			2004			2003			2002
	(In thousands, except per share amounts)
Statement of Operations Data
Revenue:
Oil and gas sales		12,292			9,192			6,267			6,589			2,368
Costs and expenses:
Oil and gas production expense		4,583			3,548			1,914			2,162			1,583
Production taxes		806			877			722			759			238
General and administrative expenses		3,619			3,002			2,748			2,839			2,183
Depreciation, depletion and amortization		7,936			6,183			3,740			1,642			286
Ceiling write-down of oil and gas properties		37,800			13,450			4,100			2,975			—
		54,744			27,060			13,224			10,377			4,290
Operating loss		(42,452	)		(17,868	)		(6,957	)		(3,788	)		(1,922	)
Other income (expense):
Financing costs		(31,598	)		(4,531	)		(2,983	)		(7,451	)		(490	)
Change in derivative fair value		14,727			2,908			—			—			—
Other, net		535			(424	)		104			114			87
Net loss from continuing operations before income taxes		(58,788	)		(19,915	)		(9,836	)		(11,125	)		(2,325	)
Income tax benefit		—			—			—			—			985
Net loss from continuing operations		(58,788	)		(19,915	)		(9,836	)		(11,125	)		(1,340	)
Income from discontinued operations, net of tax		12,750			6,338			5,203			1,200			(217	)
Gain on sale of discontinued operations, net of tax		33,351			—			—			—			—
Net loss	$	(12,687	)	$	(13,577	)	$	(4,633	)	$	(9,925	)	$	(1,557	)
Basic and diluted income (loss) per common share
Continuing operations		(3.90	)		(1.54	)		(1.04	)	$	(1.38	)		(.19	)
Discontinued operations		3.06			.49			.55			.15			(.03	)
Net loss	$	(0.84	)	$	(1.05	)	$	(0.49	)	$	(1.23	)	$	(0.22	)
Statement of Cash Flows Data
Net cash provided by (used in):
Operating activities	$	14,917		$	9,650		$	5,463		$	2,845		$	136
Investing activities		18,020			(42,454	)		(9,942	)		(6,902	)		(16,218	)
Financing activities		(40,007	)		37,694			6,804			3,917			16,283

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	As of or for the Years Ended December 31,
	2006		2005		2004		2003		2002
	(In thousands, except per share amounts)
Balance Sheet Data
Cash and cash equivalents	$	872	$	6,204	$	2,208	$	537	$	722
Accounts receivable, net of allowance		1,511		2,004		793		675		567
Net property and equipment		94		2,236		2,306		2,891		1,946
Net oil and gas properties		51,384		66,548		44,352		36,262		32,284
Net intangible assets		59		2,321		1,263		3,693		4,963
Total assets		56,304		94,284		62,467		55,266		53,130
Note payable and current portion of long-term debt		48		288		124		171		721
Accounts payable		7,832		4,269		3,491		2,257		2,122
Accrued liabilities		2,775		5,378		4,056		747		759
Long-term debt, net of current portion		—		39,874		21,282		24,706		21,246
Derivative liabilities		5,895		9,837		—		—		—
Stockholders’ equity		37,617		30,217		28,822		22,911		22,810

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following information should be read in conjunction with the Consolidated Financial Statements and Notes presented elsewhere in thisForm 10-K. Infinity follows the full-cost method of accounting for oil and gas properties. See “Organization and Summary of Significant Accounting Policies,” included in Note 1 to the Consolidated Financial Statements.

Infinity and its operating subsidiaries Infinity-Texas and Infinity-Wyoming are engaged in identifying and acquiring oil and gas acreage, exploring and developing acquired acreage and oil and gas production, with a focus on the acquisition, exploration and development of and production from its properties in the Fort Worth Basin of north central Texas and Greater Green River, Sand Wash and Piceance Basins of southwest Wyoming and northwest Colorado. Infinity has also been awarded a 1.4 million acre concession offshore Nicaragua in the Caribbean Sea, which it intends to explore over the next few years.

On December 15, 2006, Infinity sold its oilfield services business for approximately $52 million. Infinity has reflected the results its oilfield services business as discontinued operations in its statements of operations and balance sheet. The Company’s discussion in Management’s Discussion and Analysis is presented on a continuing operations basis.

Infinity, through Infinity-Texas, continued its exploration and production operations in the Fort Worth Basin of Texas during the year ended December 31, 2006. Infinity-Texas successfully drilled ten horizontal and four vertical exploratory wells during 2006. As such, Infinity significantly increased natural gas production from Infinity-Texas during 2006 as compared to 2005. Infinity-Texas’ operations benefit from year-round access to exploration and development locations, ease of permitting, better weather, and less restrictive government and environmental laws and regulations. Meanwhile, Infinity-Wyoming continued to explore and develop the various projects and prospects in the Rocky Mountain region, but continues to be hampered by weather, governmental and environmental restrictions and regulations, as well as various operational issues at the Labarge, Pipeline and Sand Wash fields.

Infinity expects to continue to explore and develop its Fort Worth Basin acreage and its Rocky Mountain prospects. Infinity expects its Rocky Mountain projects to proceed more slowly, due in part to governmental restrictions. Infinity raised incremental debt and equity capital to fund its exploration operations from the net proceeds from the sale of senior secured notes and from the proceeds of option and warrant exercises during 2006. In addition to expected increases in cash flows from operating activities, Infinity will likely require external financing during 2007 and beyond to fund its exploration operations. The type, timing, cost and amounts of such financing, if any, will depend upon general energy and capital markets conditions and the success of Infinity’s operations.

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The Company engaged Netherland, Sewell & Associates, Inc. to prepare its December 31, 2006, 2005 and 2004 third-party reserve evaluations. Results of these evaluations are disclosed in the “Supplemental Oil and Gas Disclosures” in Infinity’s Consolidated Financial Statements and in the “Oil and Natural Gas Reserves” section of Item 1. and Item 2. Business and Properties.

The following table sets forth Infinity’s production and other financial data for the years ended December 31, 2006, 2005 and 2004:

		2006		2005		2004
Production:
Natural gas (MMcf)			1,142.3		875.5		953.4
Oil (thousands of barrels)			81.2		68.5		33.7
Total (MMcfe)			1,629.5		1,286.5		1,155.4
Financial Data (in thousands):
Total revenue		$	12,292	$	9,192	$	6,267
Production expenses			4,583		3,548		1,914
Production taxes			806		877		722
Financial Data per Mcfe:
Total revenue	��	$	7.54	$	7.14	$	5.42
Production expenses			2.81		2.76		1.66
Production taxes			.50		0.68		0.63

Under full cost accounting rules, Infinity reviews, on a quarterly basis, the carrying value of its oil and gas properties. Under these rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future revenue at the prices in effect as of the end of each fiscal quarter, and a write-down for accounting purposes is required if the ceiling is exceeded. During the first nine months of 2006, the Company recognized aggregate ceiling writedowns of $26,600,000 as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitation. At December 31, 2006, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $14,300,000, based upon a natural gas price of approximately $5.66 per Mcf and an oil price of approximately $48.56 per barrel in effect at that date. However, based on subsequent pricing of approximately $7.07 per Mcf of gas and approximately $47.60 per barrel of oil at the March 5, 2007 measurement date, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $11,200,000. Therefore, the Company recorded an additional ceiling writedown of $11,200,000 at December 31, 2006. In 2005 and 2004, the Company also recorded ceiling writedowns of $13,450,000 and $4,100,000, respectively. A decline in prices received for oil and gas sales or an increase in operating costs subsequent to the measurement date or reductions in estimated economically recoverable quantities could result in the recognition of additional ceiling write-downs of oil and gas properties in future periods.

2007 Operational and Financial Objectives

Infinity-Wyoming plans to focus on optimizing production from existing wells and the advancement of its prospects through additional geological and geophysical analysis. Infinity-Wyoming anticipates 2007 capital expenditures will be approximately $1 million to $2 million to deepen an oil well, reenter and recomplete a gas well previously abandoned by another operator, conduct additional geological and geophysical analysis, and increase its acreage positions.

Infinity-Texas plans to focus on increasing its production and acreage position in the Fort Worth Basin of central Texas. Infinity-Texas anticipates its 2007 capital expenditures will be approximately $20 million to $24 million to drill between 10 and 20 wells, complete one vertical well awaiting completion at December 31, 2006, conduct additional geological and geophysical analysis on its acreage and acquire additional acreage.

The Company’s ability to complete these activities is dependent on a number of factors including, but not limited to:

•  The availability of the capital resources required to fund the activity;

29

•  The availability of third party contractors for drilling rigs and completion services (although the Company has one rig under contract and operating in Texas); and

•  The approval by regulatory agencies of applications for permits to conduct exploration activities in a timely manner.

Corporate Activities

Infinity plans to conduct an environmental study and the development of geological information from reprocessing and additional evaluation of existing2-D seismic data to be acquired over its Perlas and Tyra concession blocks offshore Nicaragua. Infinity has issued letters of credit of approximately $850,000 for this initial work on the leases.

Results of operations for the year ended December 31, 2006 compared to the year ended December 31, 2005

On December 15, 2006, Infinity sold its oilfield services business for approximately $52 million. Infinity has reflected the results its oilfield services business as discontinued operations in its statements of operations and balance sheet. The Company’s discussion of its results of operations is presented on a continuing operations basis.

Net Loss

Infinity incurred a net loss after taxes of $12.7 million, or $.84 per diluted share, in 2006 compared to a net loss after taxes of $13.6 million, or $1.05 per diluted share, in 2005. The change between periods was the result of the items discussed below.

Revenue

Infinity achieved total oil and gas revenue of $12.3 million in 2006 compared to $9.2 million in 2005. The increase in oil and gas revenue was the result of improved price realizations combined with higher oil and natural gas sales volumes. The increase in sales volumes was due primarily to successful developmental drilling in the Sand Wash Basin in northwest Colorado and successful exploratory drilling in the Fort Worth Basin.

Production Expenses

Oil and gas production expenses increased to $4.6 million, or $2.81 per Mcfe, during 2006, from $3.5 million, or $2.76 per Mcfe, in the prior year. The increase in production expenses during 2006 was attributable to a full year of costs incurred at the Company’s Sand Wash Basin property, which began producing in March 2005, and Fort Worth Basin properties, which began producing in the second quarter of 2005. The increase in production cost on a per Mcfe basis was the result of a year-over-year increase in oilfield services costs.

Production Taxes

Oil and gas production taxes for 2006 decreased slightly to $0.8 million from $0.9 million in 2005 as a result of a decrease in production from the Pipeline Field located in Wyoming where production taxes are higher than the Company’s other producing locations. In addition, oil and gas production taxes for 2006 include a credit of approximately $125,000 recorded in the period to reflect estimated refunds of production taxes paid in prior periods. The estimated refunds result from the June 2006 designation of the Barnett Shale in Erath County, Texas as an area eligible for a reduced production tax rate. As a result of this designation, the Company reflects the payments of severance tax for the eligible wells as a prepayment rather than as production tax expense.

General and Administrative Expenses

General and administrative expenses increased to $3.6 million for 2006, from $3.0 million in the prior year. The increase was largely due to costs associated with the Company’s efforts to refinance its debt in the 2006 period,

30

an increase in personnel and personnel related costs and stock-based compensation expense recorded during the 2006 period.

Depreciation, Depletion, Amortization and Accretion

Infinity recognized depreciation, depletion, amortization and accretion (“DD&A”) expense of approximately $7.9 million during 2006, an increase of approximately $1.7 million compared to DD&A expense of approximately $6.2 million in the prior year. The increase in DD&A expense was due to an increase in finding costs associated with the Company’s exploration and development program and increased oil and gas production.

Ceiling Write Down

During the first nine months of 2006, the Company recognized aggregate ceiling writedowns of $26,600,000 as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitation. At December 31, 2006, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $14,300,000, based upon a natural gas price of approximately $5.66 per Mcf and an oil price of approximately $48.56 per barrel in effect at that date. However, based on subsequent pricing of approximately $7.07 per Mcf of gas and approximately $47.60 per barrel of oil at the March 5, 2007 measurement date, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $11,200,000. Therefore, the Company recorded an additional ceiling writedown of $11,200,000 at December 31, 2006. At December 31, 2005, the carrying amount of the Company’s oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $13,450,000 based upon an average natural gas price of $8.21 per Mcf and an average oil price of $60.74 per barrel in effect at that date.

Other Income (Expense)

Other income and expense was a net expense of $16.3 million in 2006 compared to a net expense of $2.0 million in the prior year. The change of $14.3 million was principally due to (i) a $0.7 million increase in interest expense due to an increase in average debt outstanding and higher average interest rates during 2006, (ii) $0.2 million of additional amortization costs resulting from higher debt issuance costs recorded in connection with the Company’s issuance of senior secured notes in 2005 and 2006, and (iii) $26.2 million of additional early extinguishment of debt expense resulting from amendments to and repayment of the Company’s senior secured notes, partially offset by a $11.8 million increase in income resulting from the decrease in the fair value of derivative liabilities.

Income Tax

Infinity reflected no net tax benefit or expense from continuing operations in 2006 and 2005. The net operating losses generated in those periods increased Infinity’s net deferred tax asset. Included in gain on sale of discontinued operations for 2006 is $0.5 million of estimated alternative minimum taxes. Due to uncertainty as to the ultimate utilization of the Company’s net deferred tax asset, as of December 31, 2006 and 2005, the Company recorded a full valuation allowance for its net deferred tax asset.

Discontinued Operations

On December 15, 2006, the Company completed the sale of its oilfield services subsidiaries for approximately $52 million in cash. In connection with the sale, the Company recognized a gain of $33,351,000, net of taxes of $0.5 million. Results from the Company’s oilfield subsidiaries are reflected as discontinued operations for all periods. Included in income from discontinued operations for the years ended December 31, 2006 and 2005 are revenues of $34,625,000 and $21,583,000, respectively.

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Results of operations for the year ended December 31, 2005 compared to the year ended December 31, 2004

Net Loss

Infinity incurred a net loss after taxes of $13.6 million, or $1.05 per diluted share, in 2005 compared to a net loss after taxes of $4.6 million, or $0.49 per diluted share, in 2004. The change between periods was the result of the items discussed below.

Revenue

Infinity achieved total oil and gas revenue of $9.2 million in 2005 compared to $6.3 million in 2004. The increase in oil and gas revenue was the result of improved price realizations for both oil and gas combined with higher oil sales volumes, partially offset by lower gas sales volumes. The increase in oil sales volumes was due primarily to successful developmental drilling in the Sand Wash Basin in northwest Colorado. Declines in gas sales volumes from the Company’s Pipeline field were partially offset by new production from exploratory drilling in the Fort Worth Basin.

Production Expenses

Oil and gas production expenses increased to $3.5 million, or $2.76 per Mcfe, during 2005, from $1.9 million, or $1.66 per Mcfe, in the prior year. The increase in production expenses was attributable to costs incurred at the Company’s Sand Wash Basin property, which began producing in March 2005, and Fort Worth Basin properties, which began producing in the second quarter of 2005. The increase in production cost on a per Mcfe basis was the result of the increase in production from the Company’s Sand Wash Basin oil property, which has higher operating costs.

Production Taxes

Oil and gas production taxes for 2005 increased to $.9 million from $0.7 million in 2004 as a result of the increase in revenue discussed above.

General and Administrative Expenses

General and administrative expenses increased to $3.0 million for 2005, from $2.7 million in the prior year. The increase was largely due to an increase in personnel and personnel-related costs, costs associated with the Company’s Sarbanes-Oxley compliance efforts and increased cost of being incorporated in Delaware, partially offset by an increase in capitalized general and administrative expenses in 2005 as a result of increased drilling and acquisition activity.

Depreciation, Depletion, Amortization and Accretion

Infinity recognized depreciation, depletion, amortization and accretion (“DD&A”) expense of approximately $6.2 million during 2005, an increase of approximately $2.5 million compared to DD&A expense of approximately $3.7 million in the prior year. The increase in DD&A expense was due to an increase in finding costs associated with the Company’s exploration and development program and increased oil and gas production.

Ceiling Write Down

At December 31, 2005, the carrying amount of the Company’s oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $13,450,000 based upon an average natural gas price of $8.21 per Mcf and an average oil price of $60.74 per barrel in effect at that date. At December 31, 2004, the carrying amount of the Company’s oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $8,900,000 based upon an average natural gas price of $6.07 per Mcf and an average oil price of $40.25 per barrel in effect at that date. However, due to subsequent price increases to approximately $6.53 per Mcf of gas and $54.55 per barrel of oil at the March 15, 2005 measurement date, the Company was only required to record a ceiling writedown of $4,100,000 in the quarter and year ended December 31, 2004.

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Other Income (Expense)

Other income and expense was a net expense of $2.0 million in 2005 compared to a net expense of $2.9 million in the prior year. The change of $0.9 million was principally due to (i) a $1.5 million increase in interest expense due to an increase in average debt outstanding and higher average interest rates during 2005, and (ii) $0.7 million of additional early extinguishment of debt expense resulting from additional debt retired during 2005, partially offset by a $0.6 million decrease in amortization costs resulting from loan costs written off in connection with debt retirement in 2005 and $2.9 million of income resulting from the decrease in the fair value of derivative liabilities (see Note 5 in notes to consolidated financial statements).

Income Tax

Infinity reflected no net tax benefit or expense in 2005 and 2004. The net operating losses generated in those periods increased Infinity’s net deferred tax asset. Due to uncertainty as to the ultimate utilization of the Company’s net deferred tax asset, as of December 31, 2005 and 2004, the Company recorded a full valuation allowance for its net deferred tax asset, as further described in Note 7 of the consolidated financial statements.

Discontinued Operations

On December 15, 2006, the Company completed the sale of its oilfield services subsidiaries for approximately $52 million in cash. Results from the Company’s oilfield subsidiaries are reflected as discontinued operations for all periods. Included in income from discontinued operations for the years ended December 31, 2005 and 2004 are revenues of $21,583,000 and $14,721,000, respectively.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

Liquidity and Capital Resources

Infinity’s primary sources of liquidity are cash provided by operations and debt and equity financings. Infinity’s primary needs for cash are for the operation, development, production, exploration and acquisition of oil and gas properties and for fulfillment of working capital obligations.

As of December 31, 2006, the Company had a working capital deficit of $7.4 million, compared to a working capital surplus of $1.6 million at December 31, 2005. Excluding current assets and liabilities of discontinued operations at December 31, 2005, the Company would have had a working capital deficit at December 31, 2005 of $1.9 million. The $5.5 million change in working capital (excluding the effects of current assets and liabilities of discontinued operations) is largely the result of a significant increase in vendor payables incurred and cash used in connection with the Company’s 2006 drilling program.

During the year ended December 31, 2006, cash provided by operating activities was $14.9 million, compared to $9.7 million in 2005. The increase in cash provided by operating activities of $5.2 million was primarily due to improved gross profit, partially offset by increased interest expense and cash expenses paid in connection with early extinguishment of debt.

During 2006, cash provided by investing activities was $18.0 million, compared to $42.5 million used in 2005. Excluding net proceeds of $49.7 million from the sale of the Company’s oilfield services business, cash used in investing activities during 2006 was $31.7 million. The decrease in cash used in investing activities of $10.8 million was primarily attributable to a $13.7 million decrease in exploration and development capital expenditures resulting from the suspension of exploration and development activities in mid-2006, partially offset by an increase of $1.4 million in oilfield services capital expenditures.

During 2006, cash used in financing activities was $40.0 million, compared to $37.7 million provided by financing activities during 2005. The net change of $77.7 million was principally due to the repayment of a net $40.0 million of debt during 2006 (including $9.0 million of increased principal resulting from covenant violations under the Company’s then outstanding senior secured notes) compared to net debt proceeds of $35.7 million

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received in 2005 and proceeds from issuance of common stock of $4.7 million, partially offset by $2.7 million of debt and equity issuance costs incurred in 2005.

On December 15, 2006, Infinity completed the sale of its oilfield services subsidiaries, Consolidated Oil Well Services, Inc. and CIS-Oklahoma, Inc. for approximately $52 million in cash. Infinity’s former oilfield services business is reported as a discontinued operation in the accompanying statements of operations and balance sheets; however, cash flows from the former oilfield services business are not reflected separately in the accompanying statements of cash flows. The following table quantifies cash flows from the discontinued operation by category:

	2006			2005			2004
	(In millions)
Net cash provided by (used in):
Operating activities		13			8			3
Investing activities		(5	)		(4	)		2
Financing activities		—			(4	)		1

Historically, a significant portion of cash flows from Infinity’s former oilfield services business was used to fund corporate overhead, debt service (or interest) and a portion of Infinity’s oil and gas exploration and development activities. The absence of such cash flows is expected to increase the overall debt required by Infinity to fund such activities in the future.

Infinity used a portion of the proceeds from the sale of its oilfield services business to repay the outstanding principal amount of notes and accrued interest on its former senior secured notes facility and terminate the facility. On January 10, 2007, Infinity entered into a $50 million reserve-based revolving credit facility (the “Credit Facility”) with Amegy Bank N.A. (“Amegy”). Under the terms of the Credit Facility, Infinity may borrow, repay and re-borrow on a revolving basis up to the lesser of (i) the aggregate sums permitted under the borrowing base, initially set at $27 million, or (ii) $50 million. At closing, Infinity borrowed $8.9 million under the Credit Facility, which was used to settle past due trade payables, fund working capital needs and pay expenses of the financing transaction. Additional amounts borrowed under the facility may be used to fund the plan of development agreed to by Infinity and Amegy.

The Credit Facility has an initial term of two years. Amounts borrowed bear interest at graduated variable rates based on LIBOR or the prime rate, which rates shall be adjusted based on the percentage of the applicable borrowing base used by Infinity from time to time. LIBOR rates can range between LIBOR plus 2.50% and LIBOR plus 3.25%, and prime rates can range between prime and prime plus 0.50%. Interest payments are due on a monthly basis and principal payments may be required under the Credit Facility to meet a borrowing base deficiency or monthly borrowing commitment reductions. The borrowing base under the Credit Facility and the applicable interest rate are subject to adjustment at least once every six months. Outstanding balances are secured by substantially all of the assets of Infinity and its subsidiaries.

The Credit Facility contains certain standard continuing covenants and agreements and requires Infinity to maintain certain financial ratios and thresholds. Under the Credit Facility, Infinity is subject to certain limitations with respect to hedging transactions. In addition, Infinity was required to enter into certain hedging transactions covering in the aggregate at least seventy percent (70%) of anticipated production from its proved developed producing oil and gas properties.

Outlook for 2007

The Company has retained an investment bank to explore its strategic alternatives, including a sale of some or all of its assets. The Company and its investment bank are actively engaged in discussions with numerous parties regarding its strategic alternatives. The Company cannot predict the outcome of these discussions, whether a transaction might be consummated, or the potential impact of such a transaction on the Company’s stockholders.

Depending on the results of Infinity’s exploration of strategic alternatives, the availability of capital resources, the availability of third party contractors for drilling and completion services, and satisfaction of regulatory activities, Infinity could incur capital expenditures of approximately $21 million to $27 million during 2007. Approximate capital expenditures by operating entity are anticipated to be $24 million by Infinity-Texas; $2 million

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by Infinity-Wyoming; and $1 million by Infinity Energy Resources, Inc. The Company could also make capital expenditures for acquisitions or accelerated drilling activities in excess of these amounts should appropriate opportunities arise.

The Company has a $50 million reserve-based revolving credit facility (the “Credit Facility”) with Amegy Bank N.A. (“Amegy”), under which Infinity may borrow, repay and re-borrow on a revolving basis up to the lesser of (i) the aggregate sums permitted under the borrowing base, initially set at $27 million, or (ii) $50 million. As of March 9, 2007, the Company had drawn $9.5 million under the Credit Facility, and has $17.5 million available to fund budgeted capital expenditures under the approved plan of development under the Credit Facility. The Credit Facility has an initial term of two years and amounts borrowed bear interest at graduated variable rates based on LIBOR or the prime rate, which rates shall be adjusted based on the percentage of the applicable borrowing base used by Infinity from time to time. LIBOR rates can range between LIBOR plus 2.50% and LIBOR plus 3.25%, and prime rates can range between prime and prime plus 0.50%.

Depending on the market price for crude oil and natural gas during 2007, the number of wells ultimately drilled and stabilized production levels from wells expected to be placed on line during 2007, Infinity would expect to generate cash flow from operating activities during 2007 of between $4 million and $8 million.

In summary, Infinity believes that it will have approximately $23 million to $27 million available to it in 2007 from external financing, including borrowings under the Credit Facility, cash from operating activities, and cash collateral of $850,000 securing letters of credit related to its Nicaraguan concessions to fund its 2007 planned capital expenditures of $21 million to $27 million.

Should Infinity identify acquisition opportunities, or if it wishes to accelerate the exploration and development of its oil and gas properties beyond that currently anticipated, or if cash flow from operating activities is not at levels anticipated, or if Infinity is unable to borrow under the Credit Facility, Infinity may seek the forward sale of oil and gas production, partnerships or strategic alliances for the development of its undeveloped acreage, the public or private offering of common or preferred equity or subordinated debt, asset sales, or other joint interest or joint venture opportunities to fund any cash shortfalls, or, because Infinity’s planned capital expenditures are largely discretionary, Infinity could decrease the level of its planned capital expenditures.

Critical Estimates

Following is a discussion of estimates used in the preparation of Infinity’s financial statements that management deems to be critical in nature because either (i) the accounting estimate requires the Company to make assumptions about matters that are highly uncertain at the time the accounting estimate is made, and different estimates could have reasonably been used for the accounting estimate in the current period, or (ii) in management’s judgment changes in the accounting estimate that are reasonably likely to occur from period to period would have a material impact on the presentation of the Company’s financial condition or results of operations.

Reserve Estimates

Infinity’s estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, the Company must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may, in fact, vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Company’s reserves. Despite the inherent imprecision in these engineering estimates, oil and gas reserves are used throughout Infinity’s financial statements. For example, since oil and gas properties are depleted using theunits-of-production method, the quantity of reserves could significantly impact DD&A expense. In addition, oil and gas properties are subject to a ceiling limitation based in part on the quantity of proved reserves. Finally, these reserves are the basis for supplemental oil and gas disclosures.

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Unproved Properties

On a quarterly basis, the costs of unproved properties are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Fair Value of Derivatives

The Company records all derivative instruments assets or liabilities at fair value on the balance sheet. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument qualifies for hedge accounting and, if so, whether the derivative is a cash flow hedge or a fair value hedge. Changes in the fair value of effective cash flow hedges are recognized in other comprehensive income until the hedged item is recognized in earnings. For fair value hedges, to the extent the hedge is effective there is no effect on the statement of operations, because changes in the fair value of the derivative instrument offset changes in the fair value of the hedged item. For derivative instruments that do not qualify as fair value hedges or cash flow hedges, changes in fair value are recognized in earnings.

The Company periodically hedges a portion of its oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. In addition, the warrants issued with the Company’s retired senior secured notes are separately accounted for as freestanding derivatives at estimated fair value.

The estimated fair values of the Company’s derivative instruments require substantial judgment. The determination of fair value includes significant estimates by management including the term of the instruments, volatility of the price of the Company’s common stock and interest rates, among other items. The fluctuations in estimated fair value may be significant from period to period, which, in turn, may have a significant impact on the Company’s reported financial condition and results of operations.

Asset Retirement Obligations

The Company has obligations to remove tangible equipment and restore locations, primarily associated with plugging and abandoning wells. Estimating future restoration and removal costs, or asset retirement obligations (“ARO”), is difficult and requires management to make estimates and judgments, because most of the removal obligations are several years in the future. Inherent in the calculation of the present value of the Company’s ARO under existing accounting literature are numerous assumptions and judgments, including ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time will be reflected as accretion expense in the Consolidated Statements of Operations.

Valuation of Tax Asset

The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred taxes recognized is limited to the amount of the benefit that is more likely than not to be realized. In assessing the value of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible,

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as of December 31, 2006 and 2005, management was not able to conclude that it is more likely than not that the Company will realize the benefits of these deductible differences. As such, at December 31, 2006 and 2005, the Company recorded a full valuation allowance for its net deferred tax asset.

Critical Policies

The accounting for Infinity’s business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the full-cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in the Company’s financial statements. Infinity has elected to follow the full-cost method, which is described below.

Oil and Gas Properties, Depreciation and Full Cost Ceiling Test

Under the full cost method of accounting for oil and gas properties, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition costs, geological and geophysical work, delay rentals, the cost of drilling, completing and equipping oil and gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. The capitalized costs are depleted over the life of the reserves associated with the assets, with the depletion expense recognized in the period that the reserves are produced. This depletion expense is calculated by dividing the period’s production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the capitalized investment.

The costs of wells in progress and unevaluated properties, including any related capitalized interest, are not amortized. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test prescribed by SECRegulation S-XRule 4-10. The test determines a limit, or ceiling, on the net book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved oil and natural gas reserves, as adjusted for the effect of cash flow hedges. This ceiling is compared to the net book value of the oil and gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment, or non-cash writedown, is required. A ceiling test impairment could cause the Company to record a significant non-cash loss for a particular period; however, the future depletion, depreciation and amortization rate would be reduced. In 2006, 2005 and 2004, the Company recorded ceiling writedowns of $37,800,000, $13,450,000 and $4,100,000, respectively.

Under the alternative “successful efforts method” of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property by property basis under the successful efforts method. Impairments are assessed on a property by property basis and are charged to expense when assessed. In general, the application of the full cost method of accounting results in higher capitalized costs and higher depletion rates compared to the successful efforts method.

The Company follows the full cost method because management believes it appropriately reflects the cost of the Company’s exploration programs as part of an overall investment in discovering and developing proved reserves.

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Contractual Obligations

The following table summarizes by period the Company’s contractual obligations as of December 31, 2006.

	Payments Due by Period
	Total		2007		2008 and 2009		2010 and 2011		Thereafter
	(In thousands)
Asset retirement obligations(a)	$	1,602	$	466	$	289	$	453	$	394
Capital lease		48		48		—		—		—
Operating leases		655		198		396		61		—
Gas gathering commitments(b)		4,793		560		1,839		1,916		478
Non-current production and property taxes		535		—		535		—		—
Total contractual obligations	$	7,633	$	1,272	$	3,059	$	2,430	$	872

(a)

The table above reflects the Company’s estimate of the settlement of its asset retirement obligations; however, neither the timing nor the ultimate settlement amounts of such obligations can be determined in advance with any precision. See Note 1 of Notes to Consolidated Financial Statements.

(b)

Gathering commitments represent minimum estimated gathering fees under a gas gathering contract for gas production from the Company’s Erath County, Texas properties; however, the ultimate settlement amounts of these obligations can not be determined in advance with any precision. The table above does not reflect the obligations associated with a gas gathering and transportation contract related to the Company’s Pipeline field. While Infinity-Wyoming has failed to deliver the volumes required under the terms of the contract, the pipeline operators have also not provided the compression and gathering capabilities they were required to provide under the contract. Management is currently negotiating revised volume commitments under a lengthened contract with the third-party gatherer and processor. See Note 8 of Notes to Consolidated Financial Statements.

Recently Issued Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation Number 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109. This interpretation clarifies the accounting for uncertainty in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards No. 109,Accounting for Income Taxes. This statement prescribes a recognition threshold and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company does not expect the adoption of FIN 48 to have a material impact on its financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the statement to determine what impact, if any, it will have on the Company’s financial position or results of operations.

In December 2006, the FASB issued FASB Staff Position (“FSP”) No. EITF00-19-2,Accounting for Registration Payment Arrangements, which addresses an issuer’s accounting for registration payment arrangements. The FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB

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Statement No. 5,Accounting for Contingencies. The guidance in the FSP amends FASB Statements No. 133,Accounting for Derivative Instruments and Hedging Activities, and No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to include scope exceptions for registration payment arrangements. The FSP further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable generally accepted accounting principles without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. FSP No. EITF00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of issuance of the FSP. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of the FSP, the provisions of the FSP are effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. The Company does not expect the adoption of FSP No. EITF00-19-2 to have a material impact on its financial position or results of operations.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Infinity’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to Infinity’s crude oil and natural gas production. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Excluding sales under a fixed price contract, gas price realizations ranged from a low of $3.88 to a high of $7.48 per Mcf during the year ended December 31, 2006. Oil price realizations ranged from a low of $47.85 per barrel to a high of $73.95 per barrel during that period.

Infinity periodically enters into fixed-price physical contracts and commodity derivative contracts on a portion of its projected natural gas and crude oil production in accordance with its Energy Risk Management Policy. These activities are intended to support cash flow at certain levels by reducing the exposure to oil and gas price fluctuations. Through March 2006, the Company sold 2,000 MMBtu of natural gas per day under one fixed price physical contract. Sales under this fixed price contract were accounted for as normal sales agreements under the exemption in SFAS No. 133. For the years ended December 31, 2006, 2005 and 2004, the effect of Infinity’s sale of a portion of its gas production under a fixed price contract, compared to spot sales, was a decrease in revenue of approximately $0.3 million, $1.4 million and $0.6 million, respectively.

As of December 31, 2006, Infinity had the following costless collar arrangements in place to manage exposure to oil price volatility on a portion of its oil production:

Terms of Arrangements	Bbls per Day		NYMEX Floor Price		NYMEX Ceiling Price
July 1, 2006 — March 31, 2007		50	$	55.00	$	77.00
January 1, 2007 — June 30, 2007		50	$	57.50	$	77.50
April 1, 2007 — September 30, 2007		50	$	60.00	$	85.50
July 1, 2007 — December 31, 2007		50	$	62.50	$	87.00
October 1, 2007 — March 31, 2008		50	$	62.00	$	85.60

As of December 31, 2006, Infinity had the following costless collar arrangements in place to manage exposure to natural gas price volatility on a portion of its natural gas production:

Terms of Arrangements	MMBtu per Day		WAHA Floor Price		WAHA Ceiling Price
January 1, 2007 — March 31, 2007		1,000	$	7.50	$	12.00
January 1, 2007 — June 30, 2007		1,000	$	6.00	$	10.55
April 1, 2007 — September 30, 2007		1,000	$	6.50	$	10.20

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Subsequent to December 31, 2006, the Company entered into the following NYMEX oil swaps:

Terms of Arrangements	Bbls per Day		NYMEX Swap Price
April 1, 2008 — December 31, 2008		65	$	57.40
January 1, 2009 — December 31, 2009		55	$	57.95
January 1, 2010 — December 31, 2010		50	$	58.90

Subsequent to December 31, 2006, the Company entered into the following WAHA Natural gas swaps:

	MMBtu
Terms of Arrangements	per Day		WAHA Swap Price
October 1, 2007 — December 31, 2007		1,000	$	6.915
January 1, 2008 — December 31, 2008		800	$	7.235
January 1, 2009 — December 31, 2009		500	$	7.170
January 1, 2010 — December 31, 2010		500	$	6.865

Subsequent to December 31, 2006, the Company entered into the following CIG Natural gas swaps:

	MMBtu		CIG
Terms of Arrangements	per Day		Swap Price
February 1, 2007 — December 31, 2007		600	$	5.200
January 1, 2008 — December 31, 2008		400	$	6.475
January 1, 2009 — December 31, 2009		400	$	6.810
January 1, 2010 — December 31, 2010		300	$	6.565

ITEM 8.   FINANCIAL STATEMENTS

The consolidated financial statements and supplementary information filed as part of this Item 8 are listed under Part IV, Item 15, “Exhibits, Financial Statement Schedules, and Reports onForm 8-K” and contained in thisForm 10-K commencing onpage F-1.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.   CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer, President and Chief Operating Officer, and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the fiscal year covered by this Annual Report onForm 10-K. The Company’s Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report onForm 10-K, the Company’s disclosure controls and procedures were effective.

Management’s Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance regarding

40

the reliability of financial reporting and the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles and includes those policies and procedures that:

•  pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of its assets;

•  provide reasonable assurance that transactions are recorded as necessary to permit preparation of its financial statements in accordance with generally accepted accounting principles, and that its receipts and expenditures are being made only in accordance with authorizations of its management and directors; and

•  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on its financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management’s projections of any evaluation of the effectiveness of internal control over financial reporting as to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 and in making this assessment used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework in accordance with the standards of the Public Company Accounting Oversight Board (United States). The Company’s management determined that as of December 31, 2006, the Company’s internal control over financial reporting was effective.

Report of Independent Registered Public Accounting Firm

Ehrhardt Keefe Steiner & Hottman PC, the Company’s independent registered public accounting firm that audited the Company’s financial statements included in this Annual Report onForm 10-K for the period ended December 31, 2006, has issued an audit report on the effectiveness of the Company’s system of internal control over financial reporting.

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

PART III

ITEM 10:   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding directors of Infinity is incorporated by reference to the section entitled “Election of Directors” in our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A in connection with the 2007 annual meeting of stockholders (the “Proxy Statement”).

ITEM 11:   EXECUTIVE COMPENSATION

Reference is made to the information set forth under the caption “Executive Compensation and Other Information” in the Proxy Statement, which information (except for the report of the board of directors on executive compensation and the performance graph) is incorporated by reference in this report onForm 10-K.

41

ITEM 12:   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Reference is made to the information set forth under the caption “Security Ownership of Principal Shareholders and Management” in the Proxy Statement, which information is incorporated by reference in this report onForm 10-K.

ITEM 13:   CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Reference is made to the information contained under the caption “Certain Transactions” contained in the Proxy Statement, which information is incorporated by reference in this report onForm 10-K.

ITEM 14:   PRINCIPAL ACCOUNTANT FEES AND SERVICES

Reference is made to the information contained under the caption “Appointment of Independent Accountant” contained in the Proxy Statement, which information is incorporated by reference in this report onForm 10-K.

PART IV

ITEM 15:   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as part of this report onForm 10-K or incorporated by reference.

(1) Our consolidated financial statements are listed on the “Index to Consolidated Financial Statements” onPage F-1 to this report.

(2) Financial Statement Schedules (omitted because not applicable or not required. Information is disclosed in the notes to the financial statements).

(3) The following exhibits are filed with this report onForm 10-K or incorporated by reference.

EXHIBITS

Exhibit
Number			Description of Exhibits
	3	.1	Articles of Incorporation(1)
	3	.2	Bylaws(1)
	4	.1	Form of Placement Agent Warrant in connection with 8% Convertible Subordinated Notes(2)
	4	.2	Form of Placement Agent Warrants in connection with 7% Convertible Subordinated Notes(3)
	4	.3	Form of Warrant Agreement for 12% Bridge Note Financing(2)
	4	.4	Form of Registration Rights Agreement in connection with January 2004 private placement(4)
	4	.5	Form of Registration Rights Agreement for November 2004 private placement(5)
	4	.6	Securities Purchase Agreement for Senior Secured Notes dated January 13, 2005(6)
	4	.7	Form of Initial Note for Senior Secured Notes(6)
	4	.8	Form of Additional Note for Senior Secured Notes(6)
	4	.9	Registration Rights Agreement dated January 13, 2005(6)
	4	.10	Form of Warrant in connection with Senior Secured Notes(6)
	4	.11	Form of Security Agreement for Senior Secured Notes(6)
	4	.12	Form of Guaranty for Senior Secured Notes(6)
	4	.13	Form of Mortgage for Senior Secured Notes(6)
	10	.1	Stock Option Plan(2); 1999 Stock Option Plan(7); 2000 Stock Option Plan(8); 2001 Stock Option Plan(8); 2002 Stock Option Plan(9); 2003 Stock Option Plan(10); 2004 Stock Option Plan(11); 2005 Equity Incentive Plan(12); 2006 Equity Incentive Plan(13)
	10	.2	First Additional Closing Agreement dated September 7, 2005(14)
	10	.3	Purchase Agreement between Infinity Energy Resources, Inc. and Q Consolidated Oil Well Services, LLC dated December 1, 2006(15)

42

Exhibit
Number			Description of Exhibits
	10	.4	Loan Agreement between Infinity Energy Resources, Inc., Infinity Oil and Gas of Texas, Inc. and Infinity Oil & Gas of Wyoming, Inc. and Amegy Bank N.A., dated effective as of January 9, 2007(16)
	10	.5	Revolving Promissory Note between Infinity Energy Resources, Inc. and Amegy Bank N.A., dated January 9, 2007(16)
	10	.6	Form of Change in Control Agreement(17)
	10	.7	Waiver and Amendment Agreement, dated August 9, 2006(17)
	10	.8	October 2006 Waiver and Amendment Agreement, dated October 2, 2006(18)
	10	.9	Acknowledgement and Termination Agreement between Infinity Energy Resources, Inc., Consolidated Oil Well Services, Inc. and Stephen D. Stanfield, dated December 15, 2006(19)
	21		Subsidiaries of the Registrant
	23	.1	Consent of Ehrhardt Keefe Steiner & Hottman PC
	23	.2	Consent of Netherland Sewell & Associates, Inc.
	31	.1	Certification of Chief Executive Officer of Periodic Report pursuant to Rule 13a14(a) andRule 15d-14(a) (Section 302 of the Sarbanes-Oxley act of 2002)
	31	.2	Certification of Chief Financial Officer of Periodic Report pursuant to Rule 13a14(a) andRule 15d-14(a) (Section 302 of the Sarbanes-Oxley act of 2002)
	32	.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 (Section 906 of the Sarbanes-Oxley Act of 2002)
	32	.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 (Section 906 of the Sarbanes-Oxley Act of 2002)

(1)	Incorporated by reference to our Registration Statement onForm 8-A filed on September 13, 2005.
(2)	Incorporated by reference to our Registration Statement(No. 33-17416-D).
(3)	Incorporated by reference to our Registration Statement onForm S-3 filed on June 29, 2002 (FileNo. 333-96671).
(4)	Incorporated by reference to our Current Report onForm 8-K, filed on January 21, 2004.
(5)	Incorporated by reference to our Current Report onForm 8-K, filed on November 16, 2004.
(6)	Incorporated by reference to our Current Report onForm 8-K, filed on January 14, 2005.
(7)	Incorporated by reference to our Annual Report onForm 10-KSB for the fiscal year ended March 31, 2000.
(8)	Incorporated by reference to our Annual Report onForm 10-KSB for the fiscal year ended March 31, 2001.
(9)	Incorporated by reference to our Annual Report onForm 10-KSB for the transition period ended December 31, 2001.
(10)	Incorporated by reference to our Annual Report onForm 10-KSB for the fiscal year ended December 31, 2002.
(11)	Incorporated by reference to our Registration Statement onForm S-8 filed on July 15, 2004 (FileNo. 333-117390).
(12)	Incorporated by reference to our Registration Statement onform S-8 filed on August 29, 2005 (FileNo. 333-12794).
(13)	Incorporated by reference to our Proxy Statement on Schedule 14A, filed on May 2, 2006.
(14)	Incorporated by reference to our Current Report onForm 8-K, filed on September 8, 2005.
(15)	Incorporated by reference to our Current Report onForm 8-K, filed on December 6, 2006.
(16)	Incorporated by reference to our Current Report onForm 8-K filed on January 17, 2007.
(17)	Incorporated by reference to our Quarterly Report onForm 10-Q, filed on August 10, 2006.
(18)	Incorporated by reference to our Current Report onForm 8-K, filed on October 3, 2006.
(19)	Filed herewith.

43

SIGNATURES

In accordance with the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Infinity has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

INFINITY ENERGY RESOURCES, INC.

By:  /s/  STANTON E. ROSS

Stanton E. Ross

Chief Executive Officer

Dated: March 12, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Infinity and in the capacities and on the dates indicated:

Signature	Capacity	Date
/s/  STANTON E. ROSS Stanton E. Ross	Chief Executive Officer (Principal Executive Officer) and Director	March 12, 2007
/s/  TIMOTHY A. FICKER Timothy A. Ficker	Vice President, Chief Financial Officer (Principal Financial and Accounting Officer)	March 12, 2007
/s/  JAMES A. TUELL James A. Tuell	President, Chief Operating Officer and Director	March 12, 2007
/s/  ELLIOT M. KAPLAN Elliot M. Kaplan	Director	March 12, 2007
/s/  ROBERT O. LORENZ Robert O. Lorenz	Director	March 12, 2007
/s/  LEROY C. RICHIE Leroy C. Richie	Director	March 12, 2007

44

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Financial Statements:
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Changes in Stockholders’ Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Infinity Energy Resources, Inc.

Denver, Colorado

We have audited the accompanying consolidated balance sheets of Infinity Energy Resources, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. We also have audited management’s assessment, included in the accompanying Managements’ Report on Internal Control over Financial Reporting included in Item 9A, that Infinity Energy Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these consolidated financial statements, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Infinity Energy Resources, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, management’s assessment that Infinity Energy Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). Furthermore, in our opinion, Infinity Energy Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”).

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for share-based payments.

/s/  Ehrhardt Keefe Steiner & Hottman PC

March 9, 2007

Denver, Colorado

F-2

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
	(In thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	872		$	6,204
Accounts receivable		1,511			2,004
Prepaid expenses and other		719			133
Prepaid severance taxes		609			—
Current assets of discontinued operations		—			5,224
Total current assets		3,711			13,565
Property and equipment, at cost, net of accumulated depreciation		94			2,236
Oil and gas properties, using full cost accounting, net of accumulated depreciation, depletion, amortization and ceiling write-down:
Proved		24,581			43,699
Unproved		26,803			22,849
Intangible assets, at cost, less accumulated amortization		59			2,321
Other assets, net		1,056			168
Long term assets of discontinued operations		—			9,446
Total assets	$	56,304		$	94,284
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Note payable and current portion of long-term debt	$	48		$	288
Accounts payable		7,832			4,269
Accrued liabilities		2,775			5,378
Current portion of asset retirement obligations		466			284
Current liabilities of discontinued operations		—			1,702
Total current liabilities		11,121			11,921
Long-term liabilities:
Production taxes payable		535			401
Asset retirement obligations, less current portion		1,136			1,129
Accrued interest		—			905
Derivative liabilities		5,895			9,837
Long-term debt, less current portion		—			39,874
Total liabilities		18,687			64,067
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, par value $.0001, authorized 10,000,000 shares, issued and outstanding -0- (2006) and -0- (2005) shares		—			—
Common stock, par value $.0001, authorized 75,000,000 shares, issued and outstanding 17,866,157 (2006) and 13,501,988 (2005) shares		2			1
Additionalpaid-in-capital		78,303			58,335
Accumulated other comprehensive income		118			—
Accumulated deficit		(40,806	)		(28,119	)
Total stockholders’ equity		37,617			30,217
Total liabilities and stockholders’ equity	$	56,304		$	94,284

See Notes to Consolidated Financial Statements.

F-3

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2006			2005			2004
	(In thousands, except per share data)
Revenue:
Oil and gas sales	$	12,292		$	9,192		$	6,267
Operating expenses:
Oil and gas production expenses		4,583			3,548			1,914
Oil and gas production taxes		806			877			722
General and administrative expenses		3,619			3,002			2,748
Depreciation, depletion, amortization and accretion		7,936			6,183			3,740
Ceiling write-down of oil and gas properties		37,800			13,450			4,100
		54,744			27,060			13,224
Operating loss		(42,452	)		(17,868	)		(6,957	)
Other income (expense):
Financing costs:
Interest expense		(3,147	)		(2,454	)		(971	)
Amortization of loan discount and costs		(1,290	)		(1,066	)		(1,656	)
Early extinguishment of debt		(27,161	)		(1,011	)		(356	)
Change in derivative fair value		14,727			2,908			—
Other		535			(424	)		104
Total other expense		(16,336	)		(2,047	)		(2,879	)
Net loss from continuing operations		(58,788	)		(19,915	)		(9,836	)
Income from discontinued operations		12,750			6,338			5,203
Gain on sale of discontinued operations, net of tax		33,351			—			—
Net loss	$	(12,687	)	$	(13,577	)	$	(4,633	)
Basic and diluted net loss per share:
Net loss from continuing operations	$	(3.90	)	$	(1.54	)	$	(1.04	)
Income from discontinued operations		0.85			0.49			0.55
Gain on sale of discontinued operations		2.21			—			—
Net loss	$	(.84	)	$	(1.05	)	$	(0.49	)
Weighted average shares outstanding (basic and diluted)		15,085			12,936			9,495

See Notes to Consolidated Financial Statements.

F-4

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the years ended December 31, 2006, 2005 and 2004

											Accumulated
					Additional						Other
	Common Stock				Paid-In			Accumulated			Comprehensive			Stockholders’
	Shares		Amount		Capital			Deficit			Income (Loss)			Equity
	(In thousands, except share data)
Balance, January 1, 2004		8,204,032	$	1	$	32,721		$	(9,909	)	$	98		$	22,911
Issuance of common stock in private equity placement, net of financings costs		2,027,000		—		8,918			—			—			8,918
Issuance of common stock to partially repay related party debt		125,000		—		500			—			—			500
Issuance of common stock upon the exercise of options and warrants		146,300		—		428			—			—			428
Conversion of subordinated convertible notes and accrued interest into common stock		125,864		—		796			—			—			796
Comprehensive loss:
Net loss		—		—		—			(4,633	)		(4,633	)		(4,633	)
Reclassifications, net of income tax expense		—		—		—			—			(98	)		(98	)
Comprehensive loss											$	(4,731	)
Balance, December 31, 2004		10,628,196		1		43,363			(14,542	)		—			28,822
Reclassification of non-employee warrants to derivative liabilities		—		—		(6,090	)		—			—			(6,090	)
Reclassification of non-employee warrants from derivative liabilities in connection with exercise		—		—		2,174			—			—			2,174
Issuance of common stock upon the exercise of options and warrants		857,556		—		4,707			—			—			4,707
Conversion of subordinated convertible notes and accrued interest into common stock		2,016,236		—		14,181			—			—			14,181
Comprehensive loss:
Net loss		—		—		—			(13,577	)		(13,577	)		(13,577	)
Comprehensive loss											$	(13,577	)
Balance, December 31, 2005		13,501,988		1		58,335			(28,119	)		—			30,217
Issuance of common stock upon conversion of senior secured notes and settlement of accrued interest		4,214,419		1		18,216			—			—			18,217
Issuance of common stock upon the exercise of options		144,750		—		694			—			—			694
Stock-based compensation		—		—		687			—			—			687
Reclassification of non-employee warrants from derivative liabilities				—		341			—			—			341
Other		5,000		—		30			—			—			30
Comprehensive loss:
Net loss		—		—		—			(12,687	)		(12,687	)		(12,687	)
Reclassifications, net of income tax expense		—		—		—			—			(29	)		(29	)
Unrealized gain on effective commodity derivative instruments		—		—		—			—			147			147
Comprehensive loss											$	(12,569	)
Balance, December 31, 2006		17,866,157	$	2	$	78,303		$	(40,806	)	$	118		$	37,617

See Notes to Consolidated Financial Statements.

F-5

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2006			2005			2004
	(In thousands)
Cash flows from operating activities:
Net loss	$	(12,687	)	$	(13,577	)	$	(4,633	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, accretion and ceiling write-down		47,091			20,901			9,298
Amortization of loan discount and costs		1,290			1,066			1,741
Non-cash early extinguishment of loan cost		27,161			1,052			356
Current interest expense settled by stock issuance, net of amounts capitalized		1,079			—			—
Interest expense added to principal		1,357			—			—
Non-cash stock-based compensation expense		717			—			—
Change in fair value of derivative liabilities		(14,727	)		(2,908	)		—
Gain on sale of discontinued operations		(33,851	)		—		��	—
Impairment of note receivable and other		—			530			—
(Gain) loss on sales of other assets		(255	)		96			(2,824	)
Unrealized (gain) loss on commodity derivative instruments		(272	)		28			—
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable		247			(1,273	)		(1,687	)
(Increase) decrease in inventories		(197	)		(167	)		65
(Increase) decrease in prepaid expenses and other		(574	)		232			(89	)
Increase in accounts payable		1,046			1,034			1,526
Increase (decrease) in accrued liabilities		(2,508	)		2,636			1,710
Net cash provided by operating activities		14,917			9,650			5,463
Cash flows from investing activities:
Capital expenditures — exploration and production		(25,555	)		(39,271	)		(11,714	)
Capital expenditures — oilfield services		(5,569	)		(4,190	)		(1,149	)
Acquisitions — exploration and production		—			(330	)		(516	)
Acquisitions — oilfield services, net of cash acquired		—			—			(1,189	)
Proceeds from sale of discontinued operations, net of transaction costs		49,744			—			—
Proceeds from sale of fixed assets — exploration and production and other		280			133			156
Proceeds from sale of fixed assets — oilfield services		8			31			4,654
Increase in other assets		(888	)		(31	)		(200	)
Proceeds from note receivable		—			1,204			16
Net cash provided by (used in) investing activities		18,020			(42,454	)		(9,942	)
Cash flows from financing activities:
Proceeds from notes payable		—			434			295
Proceeds from borrowings on long-term debt		8,000			45,000			5,845
Proceeds from issuance of common stock		694			4,707			9,666
Debt and equity issuance costs		(372	)		(2,751	)		(320	)
Repayment of notes payable		(329	)		(406	)		(664	)
Repayment of long-term debt		(48,000	)		(9,290	)		(8,018	)
Net cash (used in) provided by financing activities		(40,007	)		37,694			6,804
Net (decrease) increase in cash and cash equivalents		(7,070	)		4,890			2,325
Cash and cash equivalents, beginning of period		7,942			3,052			727
Cash and cash equivalents, end of period	$	872		$	7,942		$	3,052
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized	$	580		$	1,175		$	436
Non-cash transactions:
Non-cash costs capitalized in the full cost pool for oil and gas properties		2,446			764			1,070
Property and equipment acquired through capital lease or assumption of debt		—			189			195
Options and warrants granted in connection with debt, recorded as loan costs or debt discount		1,857			8,828			120
Conversion of subordinated convertible notes and accrued interest to common stock		18,217			14,181			796
Issuance of common stock to partially repay related party debt		—			—			500
Issuance of additional notes in lieu of cash interest payment on 7% subordinated convertible notes		—			—			795

See Notes to Consolidated Financial Statements.

F-6

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations

Infinity Energy Resources, Inc. and its subsidiaries (collectively, “Infinity” or the “Company”) are engaged in the acquisition, exploration, development and production of natural gas and crude oil in the United States and the acquisition and exploration of oil and gas properties in Nicaragua.

Basis of Presentation

The consolidated financial statements include the accounts of Infinity Energy Resources, Inc. and its wholly-owned subsidiaries, which include Infinity Oil and Gas of Texas, Inc. and Infinity Oil & Gas of Wyoming, Inc. All significant intercompany balances and transactions have been eliminated in consolidation. Certain prior period amounts in the accompanying consolidated financial statements have been reclassified to conform to the current year presentation.

On December 15, 2006, the Company sold its oilfield services subsidiaries, Consolidated Oil Well Services, Inc. and CIS Oklahoma, Inc. (collectively “Consolidated”). As a result, Consolidated’s results of operations have been presented as discontinued operations in the accompanying statements of operations and balance sheet. See Note 2.

Management Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to the consolidated financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative liabilities and the realizability of deferred tax assets.

Cash and Cash Equivalents

For purposes of reporting cash flows, cash and cash equivalents consist of cash on hand and demand deposits with financial institutions. At times, the Company maintains deposits in financial institutions in excess of federally insured limits. Management monitors the soundness of the financial institutions and believes the Company’s risk is negligible. The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Derivative Instruments

The Company accounts for derivative instruments or hedging activities under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities.  SFAS No. 133 requires the Company to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings.

The Company periodically hedges a portion of its oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk.

F-7

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As a result of certain terms, conditions and features included in certain warrants issued by the Company, those warrants are required to be accounted for as derivatives at estimated fair value. See Note 5.

Oil and Gas Properties

The Company follows the full cost method of accounting for exploration and development activities. Accordingly, all costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals and dry holes) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Overhead related to exploration and development activities is also capitalized. The Company capitalized $846,000, $884,000 and $652,000 of internal costs during the years ended December 31, 2006, 2005 and 2004, respectively. Costs associated with production and general corporate activities are expensed in the period incurred.

Pursuant to full cost accounting rules, the Company must perform a “ceiling test” each quarter. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current costs and prices, including the effects of derivative instruments accounted for as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.

During the first nine months of 2006, the Company recognized aggregate ceiling writedowns of $26,600,000 as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitation. At December 31, 2006, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $14,300,000, based upon a natural gas price of approximately $5.66 per Mcf and an oil price of approximately $48.56 per barrel in effect at that date. However, based on subsequent pricing of approximately $7.07 per Mcf of gas and approximately $47.60 per barrel of oil at the March 5, 2007 measurement date, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $11,200,000. Therefore, the Company recorded an additional ceiling writedown of $11,200,000 at December 31, 2006. In 2005 and 2004, the Company recorded ceiling writedowns of $13,450,000 and $4,100,000, respectively.

Depletion of proved oil and gas properties is computed on theunits-of-production method, with oil and gas being converted to a common unit of measure based on relative energy content, whereby capitalized costs, as adjusted for estimated future development costs and estimated asset retirement costs, are amortized over the total estimated proved reserve quantities. The costs of wells in progress and unevaluated properties, including any related capitalized interest, are not amortized. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Proceeds from the sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Expenditures for maintenance and repairs are charged to oil and gas production expense in the period incurred.

Prepaid Severance Taxes

At December 31, 2006, the Company had approximately $609,000 recorded as prepaid severance taxes related to estimated severance tax refunds from the State of Texas. The estimated refunds result from the June 2006 designation of the Barnett Shale in Erath County, Texas as a tight gas formation eligible for a reduced production tax

F-8

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

rate. As a result of this designation, the Company reflects the payments of severance taxes for the eligible wells as a prepayment rather than as production tax expense.

Other Assets, Net

At December 31, 2006, other assets include approximately $852,000 of cash on deposit at a bank to secure two letters of credit. The letters of credit were issued to the Instituto Nicaraguense de Energia in connection with the Company’s May 2006 execution of exploration and production contracts for two oil and gas concessions in the Caribbean Sea of Nicaragua and the Company’s requirement under the contracts to incur capital costs of a similar amount during the first year of the contracts.

Asset Retirement Obligations

The Company records estimated future asset retirement obligations pursuant to the provisions of SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the obligation is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to present value. The Company’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. Capitalized costs are depleted as a component of the full cost pool using the units of production method. The following table summarizes the activity for the Company’s asset retirement obligations for the years ended December 31, 2006, 2005 and 2004:

	2006			2005			2004
	(In thousands)
Asset retirement obligations at January 1	$	1,413		$	635		$	521
Accretion expense		112			70			21
Liabilities incurred		30			51			93
Liabilities assumed		—			17			—
Liabilities settled		—			(199	)		—
Revision in estimates		47			839			—
Asset retirement obligations at December 31		1,602			1,413			635
Less: current portion of asset retirement obligations		(466	)		(284	)		—
Asset retirement obligations at December 31, less current portion	$	1,136		$	1,129		$	635

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized for the years ended December 31, 2006, 2005 and 2004 were $2,339,000, $1,451,000 and $635,000, respectively.

Intangible Assets

Intangible assets consist of deferred loan costs, which are amortized over the terms of the related debt instruments using the effective interest method. See Note 4.

During the years ended December 31, 2006, 2005 and 2004, the Company recorded amortization of deferred loan costs and early extinguishment of debt related to deferred loan costs of $2,634,000, $1,693,000 and $2,625,000, respectively. The Company capitalizes amortization of loan costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Amortization of loan costs is capitalized only for the period that activities are in progress to bring these

F-9

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

projects to their intended use. Total loan cost amortization capitalized for the years ended December 31, 2006, 2005 and 2004 was $203,000, $261,000 and $555,000, respectively. See Note 4.

Revenue Recognition

The Company accounts for natural gas sales using the sales method. Under this method, revenue is recognized based on actual volumes sold by the Company, which may be more or less than the Company’s share of pro-rata production from certain wells.

Natural gas imbalances at December 31, 2006 and 2005 were immaterial. The Company recognizes sales of oil when title to the product is transferred.

Transportation Costs

The Company accounts for transportation costs under Emerging Issues Task Force Issue00-10,Accounting for Shipping and Handling Fees and Costs, whereby amounts paid for transportation are classified as operating expenses.

Per Share Information

Basic earnings per share is computed by dividing net earnings from continuing operations by the weighted average number of shares of common stock outstanding during each period, excluding treasury shares. Diluted earnings per share is computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options, warrants and convertible debt.

Stock Options

Effective January 1, 2006, the Company adopted SFAS No. 123(R),Share-Based Payment, which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards. SFAS No. 123(R) also requires tax benefits relating to the deductibility of increases in the value of equity instruments issued under share-based compensation arrangements that are not included in costs applicable to sales (“excess tax benefits”) to be presented as financing cash inflows in the statement of cash flows. Prior to January 1, 2006, the Company accounted for share-based payments under the recognition and measurement provisions of APB Opinion No. 25,Accounting for Stock Issued to Employees, and related Interpretations, as permitted by SFAS No. 123,Accounting for Stock-Based Compensation. In accordance with APB Opinion No. 25, no compensation cost was required to be recognized for options granted that had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant. The Company adopted SFAS No. 123(R) using the modified prospective transition method. Under this method, compensation cost recognized is based on the grant-date fair value for all share-based payments granted or modified subsequent to December 31, 2005, estimated in accordance with the provisions of SFAS No. 123(R). All share-based awards outstanding as of the January 1, 2006 adoption date were fully vested. The results for prior periods have not been restated.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred taxes are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax asset. As of December 31, 2006 and 2005, the Company had recorded a full valuation allowance for its net deferred tax asset.

F-10

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive Income (Loss)

The Company has elected to report comprehensive income (loss) in the consolidated statements of stockholders’ equity. Comprehensive income (loss) is composed of net income (loss) and all changes to stockholders’ equity, except those due to investments by stockholders, changes in additional paid-in capital and distributions to stockholders.

Recently Issued Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation Number 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109. This interpretation clarifies the accounting for uncertainty in an enterprise’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. This statement prescribes a recognition threshold and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company does not expect the adoption of FIN 48 to have a material impact on its financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the statement to determine what impact, if any, it will have on its financial position and results of operations.

In December 2006, the FASB issued FASB Staff Position (“FSP”) No. EITF00-19-2,Accounting for Registration Payment Arrangements, which addresses an issuer’s accounting for registration payment arrangements. The FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5,Accounting for Contingencies. The guidance in the FSP amends FASB Statements No. 133,Accounting for Derivative Instruments and Hedging Activities, and No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to include scope exceptions for registration payment arrangements. The FSP further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable generally accepted accounting principles without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. FSP No. EITF00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of issuance of the FSP. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of the FSP, the provisions of the FSP are effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. The Company does not expect the adoption of FSP No. EITF00-19-2 to have a material impact on its financial position or results of operations.

Note 2 — Discontinued Operations

On December 15, 2006, the Company completed the sale of Consolidated to Q Consolidated Oil Well Services, LLC for approximately $52 million in cash. In connection with the sale, the Company recognized a gain of $33,351,000 net of taxes of $500,000. Included in income from discontinued operations in the accompanying

F-11

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

statements of operations for the years ended December 31, 2006, 2005 and 2004 are revenues of $34,625,000, $21,583,000 and $14,721,000, respectively.

Note 3 — Accrued Liabilities

Accrued liabilities consist of the following:

	December 31,
	2006		2005
	(In thousands)
Production taxes payable — current portion	$	692	$	516
Oil and gas revenue payable to oil and gas property owners		742		680
Current income taxes		500		—
Accrued interest		—		247
Accrued drilling costs		—		2,918
Other accrued liabilities		841		1,017
	$	2,775	$	5,378

Note 4 — Debt

Debt consists of the following:

	December 31,
	2006			2005
	(In thousands)
Senior Secured Notes, net of discount of $7,417 at December 31, 2005	$	—		$	37,583
Promissory note to seller (for a 50% interest in an aircraft)		—			2,203
Other		48			376
		48			40,162
Less current portion		(48	)		(288	)
Long-term debt	$	—		$	39,874

Senior Secured Notes Facility

The Company had a senior secured notes facility (the “Senior Secured Notes Facility”) with a group of lenders (collectively, the “Buyers”), under which the Company sold, and the Buyers purchased, on four separate occasions, an aggregate of $53.0 million principal amount of senior secured notes (the “Notes”), and five-year warrants to purchase an aggregate of 2,971,451 shares of the Company’s common stock at a weighted average exercise price of $9.81 per share (the “Warrants”).

Under the original terms of the Senior Secured Notes Facility, in certain circumstances, Infinity had the option to repay the Notes with direct issuances of shares of common stock in lieu of cash at a conversion rate equal to 95% of the weighted average trading price of the Company’s common stock on the trading day preceding the conversion (the “Conversion Option”). In addition, the Company also had the option to settle accrued interest due under the Notes with direct issuances of shares of common stock in lieu of cash at a conversion rate equal to 95% of the weighted average trading price of shares of the Company’s common stock on the trading day preceding the conversion. In January, April and July 2006, the Company elected to settle an aggregate of approximately $3.5 million of accrued interest through the issuance of an aggregate of 594,884 shares of common stock. In addition, in the first, second and third quarters of 2006, the Company converted an aggregate of $8.0 million in principal amount of Notes (along with accrued interest of approximately $112,000) into an aggregate of 1,369,718 shares of common stock.

F-12

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As a result of the violation of certain of the covenants under the Senior Secured Notes Facility at June 30, 2006, on August 9, 2006 the Company and the Note holders entered into a Waiver and Amendment ( “August Amendment”) to the Senior Secured Notes Facility and the Notes that waived the violations at June 30, 2006 and amended the Notes and Warrants to provide for the following:

•  repayment or conversion of $2.5 million principal amount of Notes by September 15, 2006 (a total of $2,547,000 of principal and interest was converted into 614,500 shares of common stock by September 15, 2006);

•  reduction of the exercise price of the outstanding Warrants from a weighted-average exercise price of $9.81 per share to $5.00 per share and increase in the number of Warrants from 2,971,451 to 5,829,726.

The Company was unable to maintain compliance with the terms of the amended Senior Secured Notes Facility and Notes. As such, effective October 2, 2006, the Company entered into an October 2006 Waiver and Amendment Agreement (“October Amendment”) which further amended the Senior Secured Notes Facility, the Notes and the Warrants to provide for the following:

•  increase in the outstanding principal Notes balance by 20%, or $9 million, plus an additional $1.4 million equal to the interest that would have been due on October 2, 2006;

•  conversion of approximately $7.4 million principal amount of Notes by January 15, 2007, at the election of the Note holders (a total of $7,444,000 principal and interest was converted into 2,249,807 shares of common stock by December 14, 2006);

•  Warrant holders may require the Company to redeem their Warrants in connection with a sale of all or substantially all of the Company to a “non-public” buyer.

The outstanding principal amount of Notes and accrued interest of approximately $49.2 million was repaid on December 15, 2006 with proceeds from the sale of the Company’s oilfield services business (see Note 2) and the Senior Secured Notes Facility was terminated.

Under the provisions ofEITF 96-19,Debtor’s Accounting for a Modification or Exchange of Debt Instruments, the Company determined that the August and October Amendments each resulted in substantial modifications to the terms of the Notes. As a result, the Company accounted for each amendment as an extinguishment of debt. In connection with the August and October amendments and the termination of the Senior Secured Notes Facility in December 2006, the Company recognized approximately $27.0 million of early extinguishment of debt expense consisting of the following (in thousands):

Change in fair value of Warrants upon repricing	$	9,812
Increase in principal resulting from covenant violations		9,000
Write off of debt discount		6,500
Write off of debt issuance costs and other		1,639
	$	26,951

In connection with the Note conversions during the year ended December 31, 2006 the Company reclassified unamortized discount (see discussion below under Debt Discount) of $1,030,000 related to the converted Notes against additionalpaid-in-capital, reclassified Conversion Option derivative liability of $479,000 (see Note 5) to additionalpaid-in-capital and wrote off deferred financing costs of $210,000 to early extinguishment of debt.

Promissory Note to Seller

In connection with the 2003 acquisition of a 50% interest in an aircraft, the Company entered into a promissory note in favor of the seller. The note and accrued interest were settled in full in February 2006 in connection with the sale of the aircraft.

F-13

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8% Convertible Subordinated Notes

Effective June 13, 2001, the Company sold $6,475,000 of 8% Subordinated Convertible Notes in a private placement. During 2004, the holders of $300,000 of 8% Subordinated Convertible Notes converted the debt and accrued interest into 63,197 shares of the Company’s common stock. On January 13, 2005, the Company called for redemption all of the remaining 8% Subordinated Convertible Notes outstanding on February 28, 2005. The holders of all $2,493,000 of 8% Subordinated Convertible Notes outstanding converted the debt and accrued interest into 517,296 shares of the Company’s common stock. The remaining unamortized loan costs of $156,000 were expensed as early extinguishment of debt.

7% Convertible Subordinated Notes

Effective April 22, 2002, the Company sold $12,540,000 of 7% Subordinated Convertible Notes in a private placement. During 2004, the holders of $462,000 of 7% Subordinated Convertible Notes converted the debt and accrued interest into 62,685 shares of the Company’s common stock. On February 25, 2005, the Company called for redemption all of the remaining 7% Subordinated Convertible Notes outstanding on April 22, 2005 at a redemption price of 102.8% plus accrued and unpaid interest. Holders of $11,479,000 of 7% Subordinated Convertible Notes outstanding converted the debt and accrued interest into 1,498,940 shares of the Company’s common stock, and the remaining balance of $38,000 plus accrued interest was paid in full on April 22, 2005. The unamortized loan costs of $753,000 were expensed as early extinguishment of debt.

Debt Discount

In connection with the issuance of the Notes discussed above, the Company recorded aggregate debt discount of $10,685,000, which was being amortized over the maturities of the Notes utilizing the effective interest method. The Company capitalizes amortization of debt discount to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Amortization of debt discount is capitalized only for the period that activities are in progress to bring these projects to their intended use. Total debt discount amortized during the years ended December 31, 2006 and 2005 was $995,000 (net of $750,000 capitalized to oil and gas properties) and $647,000 (net of $764,000 capitalized to oil and gas properties). There was no debt discount amortization capitalized in 2004.

See Note 13 for discussion of a new credit facility entered into by the Company on January 10, 2007.

Note 5 — Derivative Instruments

The Company accounts for derivative instruments or hedging activities under the provisions of SFAS No. 133, which requires the Company to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings.

Commodity Derivatives

The Company periodically hedges a portion of its oil and gas production through fixed-price physical contracts and commodity derivative contracts. The purpose of the hedges is to provide a measure of stability to the Company’s

F-14

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. As of December 31, 2006 the Company had the following oil collar derivative arrangements outstanding:

	Bbls		NYMEX		NYMEX
Term of Arrangements	per Day		Floor Price		Ceiling Price
July 1, 2006 — March 31, 2007		50	$	55.00	$	77.00
January 1, 2007 — June 30, 2007		50	$	57.50	$	77.50
April 1, 2007 — September 30, 2007		50	$	60.00	$	85.50
July 1, 2007 — December 31, 2007		50	$	62.50	$	87.00
October 1, 2007 — March 31, 2008		50	$	62.00	$	85.60

As of December 31, 2006 the Company had the following natural gas collar derivative arrangements outstanding:

	MMBtu		WAHA		WAHA
Term of Arrangements	per Day		Floor Price		Ceiling Price
January 1, 2007 — March 31, 2007		1,000	$	7.50	$	12.00
January 1, 2007 — June 30, 2007		1,000	$	6.00	$	10.55
April 1, 2007 — September 30, 2007		1,000	$	6.50	$	10.20

Through the third quarter 2006, all of the Company’s collar arrangements qualified as cash flow hedges. In connection with a change in the terms under which the Company sells a portion of its crude oil production and a loss of correlation between the index on which the Company sells its natural gas in Texas and the index on which its natural gas collars are settled, in the fourth quarter 2006 the Company determined it was no longer able to conclude that its oil or natural gas collars were effective hedges. As of December 31, 2006 and 2005, the Company had a derivative asset (liability) of approximately $363,000 and ($28,000), respectively, which are included in prepaid expenses and other assets and accrued liabilities, respectively, on the accompanying consolidated balance sheet. During the years ended December 31, 2006 and 2005, the Company recognized ineffectiveness of approximately $244,000 and ($28,000), respectively, under its collar arrangements, which is reflected in other income (expense) in the accompanying consolidated statements of operations. During 2006, the Company received approximately $68,000, net under its collar arrangements, which is included in oil and gas revenue. No amounts were received or paid by the Company during 2005 under its collar arrangements. During the years ended December 31, 2006 and 2004, the Company reclassified from other comprehensive income to natural gas revenue, gains of approximately $29,000 and $98,000, respectively, related to contracts that had been designated as cash flow hedges.

Subsequent to December 31, 2006, the Company entered into the following NYMEX oil swaps:

	Bbls		NYMEX
Term of Arrangement	per Day		Swap Price
April 1, 2008 — December 31, 2008		65	$	57.40
January 1, 2009 — December 31, 2009		55	$	57.95
January 1, 2010 — December 31, 2010		50	$	58.90

Subsequent to December 31, 2006, the Company entered into the following WAHA natural gas swaps:

	MMBtu		WAHA
Term of Arrangement	per Day		Swap Price
October 1, 2007 — December 31, 2007		1,000	$	6.915
January 1, 2008 — December 31, 2008		800	$	7.235
January 1, 2009 — December 31, 2009		500	$	7.170
January 1, 2010 — December 31, 2010		500	$	6.865

F-15

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Subsequent to December 31, 2006, the Company entered into the following CIG natural gas swaps:

	MMBtu		CIG
Term of Arrangement	per Day		Swap Price
February 1, 2007 — December 31, 2007		600	$	5.200
January 1, 2008 — December 31, 2008		400	$	6.475
January 1, 2009 — December 31, 2009		400	$	6.810
January 1, 2010 — December 31, 2010		300	$	6.565

Other Derivatives

As more fully discussed in Note 4 above, the Company issued Notes and Warrants in January, September and December 2005 and March 2006. Under the provisions of SFAS No. 133 and EITF00-19 the Company bifurcated the Conversion Option associated with the Notes and accounted for it and the Warrants as derivatives. The fair values of the Conversion Option and the Warrants, which aggregated $557,000 and $10,108,000, respectively, for all four series of Notes, were recorded as debt discount. Subsequent changes in the fair value of those derivatives were recorded as changes in derivative fair value in the accompanying consolidated statements of operations. During the years ended December 31, 2006 and 2005, the Company recognized changes in derivative fair value of approximately $0 and $34,000, respectively, related to the decrease in the fair value of the Conversion Option and approximately $12,141,000 and $1,885,000, respectively, related to the decrease in the fair value of the Warrants. The terms of the Notes and Warrants contained other embedded derivatives that management determined to have de minimus value.

As a result of the issuance of the initial Notes in January 2005, under the provisions of EITF00-19, the Company was no longer able to conclude that it had sufficient authorized and unissued shares available to settle its previously issued non-employee options and warrants (the “Non-employee Options and Warrants”) (see Note 6) after considering the commitment to potentially issue common stock under terms of the Notes in an event of default. As such, effective with the issuance of the initial Notes on January 13, 2005, the Company reclassified the fair value of the Non-employee Options and Warrants out of stockholders’ equity on the accompanying consolidated balance sheet and recognized them as a derivative liability of $6,090,000. Changes in the fair value of the Non-employee Options and Warrants were recorded as change in derivative fair value in the accompanying consolidated statements of operations. Non-employee Options and Warrants settled in common stock were remeasured prior to settlement and then reclassified back to additional paid-in capital. During 2005, in connection with the exercise of 538,850 Non-employee Options and Warrants, the Company reclassified $2,174,000 back to additional paid-in capital. During the years ended December 31, 2006 and 2005, the Company recognized changes in derivative fair value of approximately $2,586,000 and $989,000, respectively, related to the decrease in the fair value of these instruments. In connection with the repayment of the Notes on December 15, 2006, the Company was able to conclude that the Non-employee Options and Warrants were no longer required to be accounted for as derivatives. As such, the Company reclassified the Non-employee Options and Warrants derivative liability of $341,000 back to additional paid-in capital.

Note 6 — Stockholders’ Equity

Private Institutional Equity Placements

In January 2004, the Company issued 1,000,000 shares of common stock in exchange for $4,000,000. In November 2004, the Company issued 1,027,000 shares of common stock in exchange for $5,237,700. Costs associated with the issuances totaled $320,000.

Non-Employee Warrants and Options

In connection with the issuance of the Notes during 2006 and 2005, the Company issued five-year warrants to purchase an aggregate of 2,971,451 shares of the Company’s common stock at a weighted average price of $9.81 per share. As further discussed in Note 4 above, in August 2006 the exercise prices of these warrants were reduced to

F-16

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$5.00 per share and the number of warrants was increased to 5,829,726. The Warrants contain anti-dilution provisions that require the Company to adjust the exercise price and the number of Warrants outstanding if the Company issues stock at less than the exercise price. Through December 31, 2006, none of these warrants have been exercised.

In connection with the issuance of bridge notes in 2003, the Company issued warrants to purchase an aggregate of 1,163,500 shares of the Company’s common stock at $8.75 per share, with expiration dates ranging from January 23, 2008 through June 27, 2008. The warrant agreement for 250,000 of the warrants issued contain anti-dilution provisions that require the Company to adjust the exercise price and the number of warrants outstanding if the Company sells stock at less than the exercise price. As a result of the private institutional placements of equity discussed above in January and November 2004, and the conversion of Notes discussed in Note 4, the exercise price of these warrants has been adjusted to $7.13 per share and the number of shares to be acquired under the warrants was increased by 56,954.

The following table summarizes non-employee option and warrant activity for the years ended December 31, 2006, 2005 and 2004:

				Weighted Average		Weighted Average
	Number of			Exercise		Grant Date Fair
	Shares			Price per Share		Value per Share
Outstanding, January 1, 2004		2,110,150		$	8.27	$
Granted		47,746			8.24		4.80
Outstanding, December 31, 2004		2,157,896			8.17
Granted		2,507,363			9.87		3.38
Exercised		(546,850	)		6.97
Outstanding, December 31, 2005		4,118,409			9.36
Granted		3,351,571			5.00		3.35
Outstanding, December 31, 2006		7,469,980			5.75

The following table summarizes information about non-employee warrants and options outstanding at December 31, 2006:

	Number
	Outstanding and
	Exercisable at		Weighted Average		Weighted
	December 31,		Remaining		Average
Range of Exercise Prices	2006		Contractual Life		Exercise Price
$5.00		5,829,726		3.4 years	$	5.00
$7.13 — 7.34		395,754		1.2 years	$	7.18
$8.75 — $9.06		1,244,500		1.1 years	$	8.80
		7,469,980

Options Under Employee Option Plans

In May 2006, the Company’s stockholders approved the 2006 Equity Incentive Plan (the “2006 Plan”), under which both incentive and non-statutory stock options may be granted to employees, officers, non-employee directors and consultants. An aggregate of 470,000 shares of the Company’s common stock are reserved for issuance under the 2006 Plan. Options granted under the 2006 Plan allow for the purchase of common stock at prices not less than the fair market value of such stock at the date of grant, become exercisable immediately or as directed by the Company’s Board of Directors and generally expire ten years after the date of grant. The Company also has other equity incentive plans with terms similar to the 2006 Plan. As of December 31, 2006, 828,381 shares were available for future grants under all plans.

F-17

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model, which requires the input of subjective assumptions, including the expected term of the option award, expected stock price volatility and expected dividends. These estimates involve inherent uncertainties and the application of management judgment. For purposes of estimating the expected term of options granted, the Company aggregates option recipients into groups that have similar option exercise behavioral traits. Expected volatilities used in the valuation model are calculated based on the methodology used in the valuation of certain of the Company’s warrants. The risk-free rate for the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The following table summarizes the inputs used in the calculation of fair value of options granted during the years ended December 31, 2006, 2005 and 2004:

	2006	2005	2004
Expected term (in years)	5.5 - 10	10		10
Expected stock price volatility	58% - 62%	67%		147	%
Expected dividends	—	—		—
Risk-free rate	4.71% - 5.15%	4.00% - 4.13%		1.50	%
Forfeiture rate	22.5%	—		—

The following table summarizes stock option activity as of and for the year ended December 31, 2006:

				Weighted				Weighted
				Average				Average
	Number of			Exercise		Aggregate		Remaining
	Options			Price per Share		Intrinsic Value		Contractual Term
						(In thousands)
Outstanding at January 1, 2006		1,383,250		$	6.52
Granted		440,000			5.91
Exercised		(144,750	)		4.79
Expired		(160,000	)		5.00
Forfeited		(497,500	)		6.84
Outstanding at December 31, 2006		1,021,000			6.58	$	—		7.0 years
Exercisable at December 31, 2006		636,000			7.03	$	—		5.9 years

The following table summarizes certain information with respect to the Company’s stock option activity during the years ended December 31, 2006, 2005 and 2004:

	2006		2005		2004
Weighted average grant-date fair value of options granted	$	3.71	$	6.00	$	4.22
Total intrinsic value of options exercised	$	291,000	$	1,858,000	$	441,000
Compensation expense recognized	$	687,000		—		—
Cash received from the exercise of stock options	$	694,000	$	957,000	$	428,000
Stock-based compensation expense capitalized		—		—		—
Tax benefits recognized related to stock-based compensation		—		—		—

As of December 31, 2006, the Company had unrecognized compensation cost of $578,000 related to unvested stock options, which will be recognized over the next 10 months, subject to estimated forfeiture rates.

F-18

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table illustrates the effect on net loss and net loss per share if the Company had applied the fair value recognition provisions of SFAS No. 123(R) to options granted under stock option plans in the years ended December 31, 2005 and 2004:

	2005			2004
	(In thousands, except share amounts)
Net loss as reported	$	(13,577	)	$	(4,633	)
Deduct: Total stock-based employee compensation expense, determined under fair value based method for all awards		(3,177	)		(1,703	)
Pro forma net loss	$	(16,754	)	$	(6,336	)
Basic and diluted loss per share — as reported	$	(1.05	)	$	(0.49	)
Basic and diluted loss per share — as reported	$	(1.30	)	$	(0.67	)

Note 7 — Income Taxes

The (provision) benefit for income taxes consists of the following:

	For the Years Ended December 31,
	2006			2005			2004
	(In thousands)
Current income tax provision	$	—		$	—		$	—
Deferred income tax benefit		1,616			(5,464	)		(1,784	)
Change in valuation allowance and other		(1,616	)		5,464			1,784
Total income tax (provision) benefit	$	—		$	—		$	—
								��

The effective income tax rate varies from the statutory federal income tax rate as follows:

	For the Years Ended December 31,
	2006			2005			2004
	(In thousands)
Federal income tax rate		34.0	%		34.0	%		34.0	%
State income tax rate		4.5			4.5			6.0
Non-deductible debt extinguishment expenses		(51.3	)		—			—
Non-deductible / taxable change in derivative fair value		46.5			(1.9	)		—
Non-deductible interest expense and debt discount		(21.4	)		—			—
Other temporary and permanent differences		1.0			3.6			—
Change in valuation allowance and other		(13.3	)		(40.2	)		(40.0	)
Effective tax rate		—	%		—	%		—	%

F-19

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The significant temporary differences and carry-forwards and their related deferred tax asset (liability) and deferred tax asset valuation allowance balances are as follows:

	December 31,
	2006			2005
	(In thousands)
Deferred tax assets
Accruals and other	$	262		$	214
Property and equipment		9,101			—
Alternative minimum tax credit carry-forward		500			—
Net operating loss carry-forward		3,541			13,635
Gross deferred tax assets		13,404			13,849
Deferred tax liabilities
Property and equipment		—			1,185
Derivative liabilities		—			1,375
Gross deferred tax liabilities		—			2,560
Net deferred tax asset		13,404			11,289
Less valuation allowance		(13,404	)		(11,289	)
Deferred tax asset	$	—		$	—

For income tax purposes, the Company has net operating loss carry-forwards of approximately $9,198,000, which expire from 2016 through 2026, and an alternative minimum tax credit carryforward of $500,000. The Company has provided for a valuation allowance of $13,404,000 due to the uncertainty of realizing the tax benefits from its net deferred tax asset.

During the years ended December 31, 2006, 2005 and 2004, the Company realized certain tax benefits related to stock option plans in the amounts of $275,000, $505,000 and $172,000, respectively. Such benefits were recorded as a deferred tax asset as they increased the Company’s net operating losses and an increase in additional paid in capital. The recognition of the valuation allowance offset the impact of this benefit.

Note 8 — Commitments and Contingencies

Delivery Commitments

Effective September 2001, the Company entered into a gas gathering and transportation contract with a third-party gatherer and processor in which the third-party gatherer and processor built gas gathering laterals and installed compression facilities to deliver gas produced from the Company’s Pipeline Field to the Overland Trail Transmission pipeline. During 2002, the contract was amended to include additional compression and gathering facilities to be installed by the third-party gatherer and processor and delivery points for the additional production being generated by the Company. The Company pays a gathering fee of approximately $0.40 per Mcf until 7,500,000 Mcf have been produced at which time the fee is to be reduced to $0.25 per Mcf. Additionally, the Company had annual volume commitments for five years starting September 1, 2001. If the Company exceeded the minimum in any year, the excess reduced the following year’s commitment. If the Company did not meet the minimum in any year, the shortfall was added to the following years’ commitments. Through December 31, 2006, the Company has delivered approximately 4,545,000 Mcf under this contract. The Company’s sales volumes from the Pipeline Field are also subject to a $0.15 per MMBtu charge for access onto the Overland Trail Transmission line. While the Company has failed to deliver the volumes required under the terms of the contract, the third-party gatherer and processor has also not provided the compression and gathering capabilities they were required to provide under the contract. Management is currently negotiating revised volume commitments under a lengthened contract with the third-party gatherer and processor.

F-20

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In June 2005, the Company entered into a long-term gas gathering contract for natural gas production from the Company’s properties in Erath County, Texas, under which the Company pays a gathering fee of $0.35 per Mcf gathered. The contract contains minimum delivery volume commitments through June 30, 2015 associated with firm transportation rights. Under provisions of the contract, in December 2006 the Company reduced the minimum daily delivery volumes by 50%. As of December 31, 2006 and 2005, the Company had accrued approximately $71,000 and $248,000, respectively, as a delivery commitment shortfalls under the contract.

Lease Agreements

The Company leases office space under an operating lease with a lease term through April 20, 2010. Future minimum lease payments under the non-cancelable operating lease are as follows at December 31, 2006:

Year Ending December 31,	Operating Lease
	(In thousands)
2007	$	198
2008		198
2009		198
2010		61
Total minimum lease payments	$	655

Rental expense for the years ended December 31, 2006, 2005 and 2004 was $114,000, $98,000 and $112,000, respectively.

Regulations

The Company’s oil and gas operations are subject to various Federal, state and local laws and regulations. The Company could incur significant expense to comply with new or existing laws and non-compliance could have a material adverse effect on the Company’s operations.

Environmental

The Company uses injection wells to dispose of water into underground rock formations. If future wells produce water of lesser quality than allowed under state laws or if water is produced at rates greater than can be injected, the Company could incur additional costs to dispose of its water.

Note 9 — Retirement Plan

The Company has a 401(k) plan covering substantially all of its employees. Effective January 1, 2004, the Company began matching, dollar for dollar, employee contributions up to 4% of gross pay. The Company recognized expense of $51,000, $45,000 and $34,000 related to such contributions during the years ended December 31, 2006, 2005 and 2004, respectively.

Note 10 — Significant Customers

During 2006, sales to three unrelated customers represented 40%, 28% and 17% of total revenue. During 2005, sales to four unrelated customers represented 32%, 25%, 19% and 14% of total revenue. During 2004, sales to two unrelated customers represented 76% and 22% of total revenue.

Note 11 — Fair Value of Financial Instruments

The carrying values of the Company’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities represent the fair value due to the short-term nature of the accounts.

The fair value of the Company’s non-current derivative liabilities, all of which relate to the Warrants, is estimated using various models and assumptions related to the term of the instruments, estimated volatility of the price of the Company’s common stock and interest rates, among other items.

F-21

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 12 — Earnings Per Share

For the years ended December 31, 2006, 2005 and 2004, all of the Company’s common stock equivalents were anti-dilutive. Therefore, the impact of 8,490,980, 5,501,659 and 5,320,892 common stock equivalents outstanding as of December 31, 2006, 2005 and 2004, respectively, were not included in the calculation of diluted loss per share because their effect was anti-dilutive.

Note 13 — Subsequent Event — Credit Facility

On January 10, 2007, the Company entered into a $50 million reserve-based revolving credit facility (the “Credit Facility”) with Amegy Bank N.A. (“Amegy”). Under the related loan agreement (the “Loan Agreement”) between Infinity, Infinity Oil and Gas of Texas, Inc. and Infinity Oil & Gas of Wyoming, Inc. and Amegy, Infinity may borrow, repay and re-borrow on a revolving basis up to the lesser of (i) the aggregate sums permitted under the borrowing base, initially set at $27 million, or (ii) $50 million. As of March 9, 2007, the Company had drawn $9.5 million under the Credit Facility. The Credit Facility has an initial term of two (2) years. Amounts borrowed bear interest at graduated variable rates based on LIBOR or the prime rate, which rates shall be adjusted based on the percentage of the applicable borrowing base used by Infinity from time to time. LIBOR rates can range between LIBOR plus 2.50% and LIBOR plus 3.25%, and prime rates can range between prime and prime plus 0.50%. Interest payments are due on a monthly basis beginning in February 2007, and principal payments may be required to meet a borrowing base deficiency or monthly borrowing commitment reductions. The borrowing base under the Credit Facility and the applicable interest rate are subject to adjustment at least once every six months. Amounts borrowed under the Credit Facility are collateralized by substantially all of the assets of Infinity and its subsidiaries and is guaranteed by Infinity’s subsidiaries. The Credit Facility contains certain standard continuing covenants and agreements and requires Infinity to maintain certain financial ratios and thresholds.

Note 14 — Supplemental Oil and Gas Information

Estimated Proved Oil and Gas Reserves (Unaudited)

Proved oil and gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered.

F-22

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

All of the Company’s proved reserves are located in the United States. The following information about the Company’s proved and proved developed oil and gas reserves was developed from reserve reports prepared by independent reserve engineers:

	Natural Gas			Crude Oil
	(Mcf)			(Barrels)
Proved reserves as of January 1, 2004		7,510,895			193,139
Purchases of reserves in place		1,476,067			—
Revisions of previous estimates		(1,230,288	)		16,535
Extension, discoveries and other additions		1,239,700			17,571
Production		(953,428	)		(33,668	)
Proved reserves as of December 31, 2004		8,042,946			193,577
Purchases of reserves in place		—			140,591
Revisions of previous estimates		(2,887,783	)		550,832
Extension, discoveries and other additions		6,819,586			20,262
Production		(875,543	)		(68,497	)
Proved reserves as of December 31, 2005		11,099,206			836,765
Purchases of reserves in place		—			—
Revisions of previous estimates		(7,778,519	)		(111,442	)
Extension, discoveries and other additions		1,600,803			4,342
Production		(1,142,305	)		(81,203	)
Proved reserves as of December 31, 2006		3,779,185			648,462
Proved Developed Reserves as of:
December 31, 2004		3,773,033			117,031
December 31, 2005		5,031,235			712,094
December 31, 2006		3,779,185			648,462

Costs Incurred in Oil and Gas Activities

Costs incurred in connection with the Company’s oil and gas acquisition, exploration and development activities are shown below.

	For the Years Ended December 31
	2006		2005		2004
	(In thousands)
Property acquisition costs
Proved	$	—	$	330	$	516
Unproved		4,844		5,745		3,625
Total property acquisition costs		4,844		6,075		4,141
Development costs		892		17,099		6,156
Exploration costs		24,865		17,583		5,294
Asset retirement costs		77		907		93
Total costs	$	30,678	$	41,664	$	15,684

F-23

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unproved property acquisition costs in the table above includes costs related to the Company’s approximately 1,400,000 acre concessions offshore Nicaragua of approximately $832,000, $234,000 and $40,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Aggregate Capitalized Costs

Aggregate capitalized costs relating to the Company’s oil and gas producing activities, and related accumulated depreciation, depletion, amortization and ceiling write-down are as follows:

	December 31,
	2006			2005
	(In thousands)
Proved oil and gas properties	$	101,920		$	75,484
Unproved oil and gas properties		26,803			22,849
Total		128,723			98,333
Less accumulated depreciation, depletion, amortization and ceiling write-down		(77,339	)		(31,785	)
Net capitalized costs	$	51,384		$	66,548

Costs Not Being Amortized

Oil and gas property costs not being amortized at December 31, 2006, by year that the costs were incurred are as follows:

Year Ended December 31,	(In thousands)
2006	$	8,557
2005		9,200
2004		1,716
Prior		7,330
Total costs not being amortized	$	26,803

Unevaluated costs include $5,964,000 related to the Company’s Labarge prospect in southwest Wyoming. Substantially all of the acreage in the prospect is subject to an ongoing Bureau of Land Management environmental impact statement (“EIS”). The EIS must be completed before the field can be developed. Unevaluated costs include approximately $1,991,000 related to the Company’s approximate 1,400,000 acre concessions offshore Nicaragua. The Company anticipates that the majority of the unproved costs in the table above will be classified as proved costs within the next five years.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

Future oil and gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, except in those instances where the sale of oil and natural gas is covered by contracts, as required by SFAS No. 69,Disclosures about Oil and Gas Producing Activities. SFAS No. 69 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and gas reserves assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to the Company’s proved oil and gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company’s proved oil and gas reserves.

F-24

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of the Company’s proved reserves.

	For the Years Ended December 31
	2006			2005			2004
	(In thousands)
Future cash inflows	$	52,897		$	141,982		$	56,585
Future production costs		(20,386	)		(49,010	)		(18,552	)
Future development costs		(300	)		(16,785	)		(3,450	)
Future income tax expense		—			(656	)		(400	)
Future net cash flows		32,211			75,531			34,183
10% annual discount for estimated timing on cash flows		(10,835	)		(32,014	)		(10,471	)
Standardized measure of discounted future cash flows	$	21,376		$	43,517		$	23,712

The following table presents the average year-end spot market gas price and oil price used to compute future cash inflows for each period:

	For the Years Ended December 31
	2006		2005		2004
Weighted average gas price per Mcf	$	5.66	$	8.21	$	6.07
Weighted average oil price per barrel	$	48.56	$	60.74	$	40.25

The following table reconciles the change in the standardized measure of discounted future net cash flow for the periods indicated:

	For the Years Ended December 31
	2006			2005			2004
Beginning of period	$	43,517		$	23,712		$	20,822
Extensions, discoveries and other additions		4,788			12,328			2,912
Purchases of reserves in place		—			442			2,840
Net change in sales and transfer prices, net of production costs		(18,284	)		(1,305	)		(4,118	)
Revision of previous quantity estimates		(15,735	)		12,809			241
Development costs incurred during the period		—			1,525			5,023
Sales of oil and gas, net of production costs and taxes		(6,879	)		(4,767	)		(3,632	)
Changes in future development costs		15,718			402			(3,026	)
Net change in income taxes		462			(156	)		1,817
Changes in production rates and other		(6,609	)		(3,875	)		(1,462	)
Accretion of discount		4,398			2,402			2,295
End of period	$	21,376		$	43,517		$	23,712

F-25

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 15 — Quarterly Consolidated Financial Information (Unaudited)

The following table provides selected quarterly consolidated financial results for the years ended December 31, 2006 and 2005.

	Quarter
	First			Second			Third			Fourth
	(In thousands, except per share amounts)
2006
Total revenue	$	2,364		$	3,356		$	3,742		$	2,830
Gross profit	$	1,020		$	2,184		$	2,586		$	1,113
Net income (loss)	$	(11,306	)	$	2,655		$	(28,289	)	$	24,253
Earnings (loss) per share from continuing operations	$	(1.06	)	$	(0.08	)	$	(2.15	)	$	(0.61	)
Earnings (loss) per diluted share from continuing operations	$	(1.06	)	$	(0.08	)	$	(2.15	)	$	(0.61	)
Earnings per share from discontinued operations	$	0.24		$	0.26		$	0.28		$	2.05
Earnings per diluted share from discontinued operations	$	0.24		$	0.26		$	0.28		$	2.05
2005
Total revenue	$	1,445		$	2,204		$	2,906		$	2,637
Gross profit	$	837		$	993		$	1,569		$	1,368
Net income (loss)	$	(9,463	)	$	4,356		$	646		$	(9,116	)
Earnings (loss) per share from continuing operations	$	(0.89	)	$	0.19		$	(0.08	)	$	(0.81	)
Earnings (loss) per diluted share from continuing operations	$	(0.89	)	$	0.18		$	(0.08	)	$	(0.81	)
Earnings (loss) per share from discontinued operations	$	0.08		$	0.14		$	0.13		$	0.13
Earnings (loss) per diluted share from discontinued operations	$	0.08		$	0.13		$	0.13		$	0.13

The Company recorded full cost ceiling writedowns of $9,100,000, $2,500,000, $15,000,000, $11,200,000 and $13,450,000 during the first, second, third and fourth quarters of 2006 and fourth quarter of 2005, respectively.

In the third quarter of 2006, the Company recognized $26,951,000 of early extinguishment expense related to two amendments to its then outstanding senior secured notes.

On December 15, 2006 the Company completed the sale of its oilfield services subsidiaries (see Note 2). As a result, the quarterly information presented above has been restated from its original presentation to reflect the results of the Company’s oilfield services subsidiaries as discontinued operations. Net income for the fourth quarter of 2006 includes a gain on the sale of discontinued operations of $33,351,000.

F-26

EXHIBIT INDEX

Exhibit
Number			Description of Exhibits
	10	.9	Acknowledgement and Termination Agreement between Infinity Energy Resources, Inc., Consolidated Oil Well Services, Inc. and Stephen D. Stanfield, dated December 15, 2006
	21		Subsidiaries of the Registrant
	23	.1	Consent of Ehrhardt Keefe Steiner & Hottman PC
	23	.2	Consent of Netherland Sewell & Associates, Inc.
	31	.1	Certification of Chief Executive Officer of Periodic Report Pursuant to Rule 13a14(a) andRule 15d-14(a) (Section 302 of the Sarbanes-Oxley act of 2002)
	31	.2	Certification of Chief Financial Officer of Periodic Report Pursuant to Rule 13a14(a) andRule 15d-14(a) (Section 302 of the Sarbanes-Oxley act of 2002)
	32	.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350 (Section 906 of the Sarbanes-Oxley Act of 2002)
	32	.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 (Section 906 of the Sarbanes-Oxley Act of 2002)

E-1