UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORMForm 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:fiscal year ended December 31, 20042005 |
|
OR |
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 File No. 0-17204
Commission file number 0-17204
INFINITY, INC.
Infinity Energy Resources, Inc.
(Exact Name of Small Business IssuerRegistrant as Specified in its Charter)
| | | |
ColoradoDelaware | | 84-107006620-3126427 |
(State of Incorporation or of Incorporation)Organization) | | (I.R.S. Employer Identification Number)No.) |
950 Seventeenth Street, Suite 800
Denver, Colorado | |
80202 |
| (Address of principal executive office) | | (Zip Code) |
1401 West Main Street, Suite C, Chanute, Kansas 66720(720) 932-7800
(Address of Principal Executive Offices, Including Zip Code)
(620) 431-6200
(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 Registrantregistrant (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 Registrantregistrant 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’sregistrant’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-212b-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, 20042005, was approximately $31,600,000$105 million, based upon aon the closing price of $3.87$8.48 per share as reported on the NASDAQ National Market.
As of March 23, 2005, 12,632,9276, 2006, 14,010,134 shares of the Registrant’s $0.0001 par value Common Stockregistrant’s common stock were issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statementregistrant’s definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A in connection with the 2005 Annual Meeting2006 annual meeting of Shareholdersstockholders are incorporated by reference in Part III of this Report onForm 10-K.
TABLE OF CONTENTS
1
1
FORWARD-LOOKING STATEMENTS
This report onForm 10-K, 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 and the completion of the Comanche and Nicaragua acquisitions;acquisition; |
| |
| | • | commencement and progress of exploration, drilling and completion activities in the Barnett Shale, Niobrara Shale, Caribbean shelf, Lower Marble Falls formation and the Forth Worth and Greater Green River Basins;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 closure of wells and the costs associated therewith; |
| |
| | • | demand for oilfield services; |
| |
| | • | the availability of financing on acceptable terms; |
| |
| | • | the impact of governmental regulation; and |
| |
| | • | the timing of engineering and environmental impact studies and permitting, |
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, |
| |
| | • | incorrect 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 or oilfield services, and |
| |
| | • | changes in general economic conditions. |
2
2
PART I
| |
| ITEM 1. | AND ITEM 2. | BUSINESS AND PROPERTIES |
GENERAL
Infinity Energy Resources, Inc. (“Infinity,”Infinity” or the “Company”) 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 Centralnorth central Texas and in the Rocky Mountain region in the Greater Green River Basin in Southwestsouthwest Wyoming and the Sand Wash and Piceance Basins in Northwestnorthwest Colorado. Infinity is also pursuing an oil and gas exploration opportunity offshore Nicaragua in the Caribbean Sea. In addition, we provide oilfield services in Easterneastern Kansas, Northeastnortheast Oklahoma and Northeastnortheast Wyoming through our wholly-owned subsidiary, Consolidated Oil Well Services, Inc. (“Consolidated”). As used in this report,Infinity, weandourrefer collectively to Infinity Energy Resources, Inc., its predecessors and subsidiaries or one or more of them as the context may require.
Effective September 9, 2005, our predecessor, Infinity, Inc. merged with and into its wholly-owned subsidiary Infinity Energy Resources, Inc., for the purpose of changing its domicile from Colorado to Delaware.
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 25 wells,69%, or 69%,25 of the total wells we drilled. Beginning in 2005, the Company’s primary exploration focus shifted to the Fort Worth Basin in north central Texas. Our total proved reserves as of December 31, 20042005 were an estimated 9.216.1 billion cubic feet of gas equivalent (“Bcfe”) with aPV-10 Value (as defined below) of $24.0$44.0 million (after-taxPV-10 Value of $23.7$43.5 million). During 2004,2005, we addedpurchased reserves in place of approximately 2.80.8 Bcfe, todiscovered proved reserves of approximately 6.9 Bcfe, produced approximately 1.2 Bcfe, and experienced negativenet positive revisions of approximately 1.10.4 Bcfe for a net increase of approximately 0.56.9 Bcfe.
Subsequent to December 31, 20042005 and through March 23, 2005,3, 2006, we have drilled four additional wells and completed the drillingtwo of an additional sixthose wells (fouras producers and two are waiting completion (all in the Fort Worth basin, and one each in the Sand Wash and Greater Green River basin). Activities subsequent to December 31, 2004 in the Fort Worth, Sand Wash and Greater Green River Basins2005 were not taken into account in the proved reserve estimate as of December 31, 2004,2005, but maywill be reflected in future estimates.
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%.
Our corporate office is located at 1401 West Main950 Seventeenth Street, Suite C, Chanute, Kansas 66720.800, Denver, Colorado 80202. Our telephone number is (620) 431-6200.(720) 932-7800. Our website ishttp://www.infinity-res.com.www.infinity-res.com. The information on the website does not constitute part of this Annual Report onForm 10-K.
| |
| Senior Secured Notes Facility |
On January 13, 2005, we entered into a securities purchase agreement (the “Senior Secured Notes Facility”) with affiliates of Promethean Asset Management, LLC and Angelo, Gordon & Co., L.P. (collectively, the “Buyers”), pursuant to which Infinity sold, and the Buyers purchased, $30 million aggregate principal amount of senior secured notes (the “Notes”) due January 13, 2009 and five-year warrants to purchase 924,194 shares of common stock at an exercise price of $9.09 per share and 732,046 shares of common stock at an exercise price of $11.06 per share (collectively, the “Warrants”). The Notes have an initial maturity of 48 months subject to extension for an additional twelve months upon the mutual agreement of Infinity and the Buyers. The Notes bear interest at 3-month LIBOR (London Interbank Offered Rate) plus 675 basis points, adjusted the first business day of each calendar quarter. The Notes are secured by essentially all of the assets of Infinity and its subsidiaries and are guaranteed by each of Infinity’s active subsidiaries. The Notes are redeemable by Infinity for cash at any time during the first year at 105% of par value, declining by 1% per year thereafter (101% during any extended maturity period), together with any accrued and unpaid interest. Under certain circumstances, Infinity has the option to repay the Notes with direct issuances of shares of registered common stock in lieu of cash.
3
At quarterly intervals and over a three-year period, commencing in the third quarter of 2005, Infinity has the option to sell additional notes (the “Additional Notes”), along with additional warrants, in amounts of up to $15 million in any rolling twelve-month period and up to a maximum of $45 million. The Additional Notes would have an initial maturity of 42 months (54 months if the maturity of the Initial Notes is extended). The issuance of Additional Notes is subject to Infinity’s future satisfaction of various closing conditions. The ability to issue Additional Notes or the requirement to prepay Notes prior to maturity will depend upon a maximum Notes balance calculated quarterly based generally upon a combination of the financial performance of Consolidated and the SEC after-tax PV-10% value of our proved reserves.
In connection with the issuance of the Notes and Warrants, Infinity also entered into a registrations rights agreement with the Buyers pursuant to which Infinity agreed to file a shelf registration statement covering resales of the ordinary shares issuable upon exercise of the Warrants.
Infinity-Texas
Infinity used approximately $9.2 million of the proceeds from the sale of the Notes and Warrants to repay all amounts outstanding pursuant to a Loan and Security Agreement between LaSalle Bank N.A. and Consolidated, a Credit Agreement between U.S. Bank National Association and Infinity-Wyoming, and certain other secured lending agreements, and those credit agreements have been terminated. Infinity is using the remainder of the proceeds to pay costs and expenses related to the sale of the Notes and Warrants and to fund its oil and gas exploration and development activities.
| |
| Acquisition of Additional Acreage in the Fort Worth Basin |
In February 2005, we entered into a definitive agreement for the acquisition of approximately 24,500 gross and net acres in Comanche County in the Fort Worth Basin of Texas, subject to customary closing conditions. The agreement, as amended, also provides for a right of first refusal on all acres acquired by the seller in Comanche County. We expect to close the Comanche transaction on or before April 19, 2005. Upon closing, including acreage previously owned, Infinity-Texas will own and operate approximately 67,500 gross acres (approximately 56,300 acres net to Infinity’s interest) of leasehold in Erath, Hamilton and Comanche Counties, Texas. We believe the Comanche County acreage offers prospective vertical and horizontal drilling and production opportunities, targeting the Barnett Shale and Lower Marble Falls formations. The leased properties are located approximately 30 miles southwest of Infinity-Texas’ existing acreage in Erath and Hamilton Counties, Texas. Infinity-Texas agreed to drill at least one test well on the Comanche acreage during the next twelve months.
| |
| Redemption of All Subordinated Convertible Debt |
Pursuant to requirements of the Senior Secured Notes Facility, on January 13, 2005, Infinity called for redemption the remaining $2.5 million of 8% Subordinated Convertible Notes due 2006 outstanding on February 28, 2005. During January and February 2005, the holders of all of the 8% subordinated convertible notes converted the debt and accrued interest into 517,296 shares of the Company’s common stock.
Based on the volume weighted average stock price for Infinity’s common stock from February 18, 2005 to February 24, 2005 and pursuant to requirements of the Senior Secured Notes Facility, on February 25, 2005, Infinity called for redemption the remaining $8.2 million of 7% Subordinated Convertible Notes due 2007 outstanding on April 22, 2005 at a redemption price of 102.8% plus accrued and unpaid interest. During 2005, through March 23, the holders of $5,950,538 of 7% subordinated convertible notes have converted the debt and accrued interest into 783,779 shares of the Company’s common stock. Approximately $5.6 million of principal amount remains outstanding as of March 23, 2005. The Company has cash available to redeem the remaining 7% notes should they not be presented for conversion prior to the redemption date.
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.
4
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. The reserve profile from productive wells drilled in the Barnett Shale region is shorter-lived compared to the typical reserve profile from wells drilled by Infinity-Wyoming in the Rocky Mountain region. 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 typically federally-owned leases in the Rocky Mountain region that involve a higher degree ofmore operating restrictions and regulations.
3
At December 31, 2004, Infinity-Texas had no proved reserves or production since no wells had been drilled, completed and hooked up for production at that point. 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. Subsequent to December 31, 2004,During 2005, Infinity-Texas has drilled an additional 25 wells (1.9(4.9 net) and completed fourseven wells (3.7(6.7 net). It is anticipated that the, six as producers and one as a water disposal well. The initial wells will bewere connected to an existing third-party pipeline system duringbeginning in May 2005. 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, 2005, Infinity-Texas had total estimated proved reserves of 6.7 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 properties.
At December 31, 2004,2005, Infinity-Wyoming had total estimated proved reserves of 9.2 Bcfe with a PV-10 Value of $24.0 million (after-tax PV-10 Value of $23.7 million). This valuation reflected average wellhead prices of $6.07 per thousand cubic feet (“Mcf”) of natural gas and $40.25 per barrel of crude oil at year-end.9.4 Bcfe.
Approximately 97%5.3 Bcfe of our proved oil and gas reserves were associated with tight sand properties onin the Wamsutter Arch Pipeline Field in the Greater Green River Basin in Southwestsouthwest Wyoming (the “Pipeline Field”). The balanceApproximately 4.1 Bcfe of our proved reserves related to one proved undeveloped well locationfractured Niobrara shale properties in the Sand Wash Basin in Colorado (the “Sand Wash Prospect”). The proved undeveloped location at the Sand Wash Prospect was drilling at December 31, 2004, was subsequently completed in early 2005, and had an initial flow rate of approximately 150 barrels of oil per day net to the company’s interest. Proved reserves at December 31, 2004 reflect only those quantities associated with a vertical wellbore.
At December 31, 2004,2005, Infinity-Wyoming operated all of theits proved developed oil and gas locations. During the year ended December 31, 2004,2005, Infinity-Wyoming drilled fiveseven gross (4.0(and net) wells and completed threesix gross (2.0(and net) of such wells. Infinity-Wyoming also completed an additional eightone gross (and net) well drilled during 2004. At December 31, 2005, Infinity-Wyoming had one gross (and net) well awaiting completion in the Sand Wash Basin of Colorado and six gross (and net) wells drilled during 2003 and prior. Subsequent to December 31, 2004, Infinity-Wyoming finished the drilling of three gross (and net) wells andawaiting completion of two of those wells, one eachor abandonment operations in the Sand Wash and Greater Green River Basins.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.
During 2004, Infinity-Wyoming produced 1.2 Bcfe of gas, comprised of 1.0 Bcf of natural gas and 34,000 barrels of crude oil. Approximately 98% of this production was from the Pipeline Field and 2% of this production was from the Labarge Field in Big Piney area of the Greater Green River Basin in Wyoming (the “Labarge Field”). Total revenue from product sales totaled $6.3 million, comprised of natural gas sales of $4.9 million, or $5.12 per Mcf, and crude oil sales of $1.4 million, or $41.15 per barrel.
5
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 entered into negotiations with INE to finalize the initial exploration and production contract for the two underlying prospects (Tyra and Perlas). Infinity anticipates the completion of the negotiations and execution of the contract during 2005.2006.
Consolidated
Consolidated acquired assets necessary to provide oilfield services in Easterneastern Kansas and Northeastnortheast Oklahoma in January 1994. Consolidated expanded its operations into Northeastnortheast Wyoming during September 1999. Consolidated provides pressure-pumping services associated with drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, nitrogen pumping and water hauling. In April 2004, Consolidated expanded its presence in the Mid-Continent region with the acquisition of substantially all of the assets and liabilities of Blue Star Acid Services, Inc., a provider of acid and cementing services in Easterneastern and Centralcentral Kansas and North Centralnorth central Oklahoma, for $1.2 million in cash and the assumption of $0.2 million in liabilities. In September 2004, Consolidated sold selected assets in Easterneastern Kansas, including real property and facilities in Chanute, Kansas, to an exploration and production company
4
and customer for $4.1 million in cash. A wholly-owned subsidiary of Infinity, CIS Oklahoma, Inc. (“CIS”), owns the real property and facilities that we occupy in Ottawa and Thayer, Kansas; Bartlesville, Oklahoma; and Gillette, Wyoming and leases itsour Eureka facility.
BUSINESS STRATEGY
Our principal objective is to create shareholderstockholder value through the execution of a business strategy, the key elements of which include:
| | |
| | • | Exploration and Production. 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 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. |
| |
| | • | Oilfield Services. We will seek to grow Consolidated through: (i) the expansion of its pressure-pumping fleet through construction or fabrication, (ii) selected acquisitions in our existing operating areas and (ii)(iii) selected acquisitions in new geographical operating areas. We will seek to improve and increase our product and service offerings and increase our operating margins, utilizing increasing efficiencies of scale as they present themselves. Ultimately, as the proved and producing reserve base in our exploration and production operations reaches a point at which we believe we no longer require cash flow contributions from our oilfield services operations, and dependent upon industry conditions, we may explore potential opportunities to monetize our investment in Consolidated, which monetization may include: (i) a sale to an industry acquiror; (ii) a sale to a financial buyer or investor; or (iii) spin-off, split-off or other such corporate transaction with the intended consequence of Consolidated standing on its own asbecoming a separate publicly-tradedpublicly traded entity. |
We intend to finance our business strategies through employment of cash on hand, freeworking capital, cash flow from our 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 theour Senior Secured Notes Facility, and as such, any disposition of material assets would require the approval of the Buyers.note holders.
6
RISK FACTORSOILFIELD SERVICES
| |
| We have a history of operating losses and we may be unable to achieve long-term profitability. |
We incurred a net loss in our fiscal years ended December 31, 2004, 2003 and 2002 of approximately $4.6 million, $9.9 million and $1.6 million, respectively. Our history of losses may impair our ability to obtain financing for drilling and other business activities at all or on favorable terms. 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.
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 orConsolidated provides pressure-pumping 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. For the period from January 1, 2004 through December 31, 2004 we received revenue per barrel of oil as low as $33.35 in January 2004 and as high as $52.58 in October 2004. During that period, the Inside FERC, first of the month CIG Index, the pricing index on which our gas sales are based, fluctuated from a low of $4.17 per MMBtu or approximately $4.59 per Mcf in April 2004 to a high of $6.98 per MMBtu or approximately $7.68 per Mcf during November 2004. Based on fourth quarter 2004 production levels, each $1.00 decrease in the price of crude oil would reduce Infinity’s oil revenue by approximately $2,500 per month and if none of the gas produced were being sold under fixed price contracts, each $0.10 decrease in natural gas price would reduce Infinity’s gas revenue by approximately $7,500 per month.
Revenue generated from oilfield services provided by Consolidated is indirectly affected by the price of oil and gas. Consolidated has historically experienced higher revenue in periods of high oil and gas prices and lower revenue in periods of low oil and gas prices.
Most of our proved reserves are natural gas. Therefore, the volatility in the price of natural gas will have the greatest 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; |
7
| | |
| • | 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; |
|
| • | limiting our ability to finance planned capital expenditures; |
|
| • | reducing our revenue, operating income and profitability; |
|
| • | reducing the carrying value of our oil and natural gas properties; and |
|
| • | reducing demand for our oilfield service business. |
A charge to earnings and book value would occur if there is a further ceiling write-down of the carrying value of Infinity’s 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 adjusted for future cash flows related to asset retirement obligations from proved reserves, after giving effect to cash flow from hedges, 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, 2004, the carrying amount of oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $8,900,000 based upon a natural gas price of approximately $6.07 per Mcf and an oil price of approximately $40.25 per barrel in effect at that date. However, due to significant 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. In 2003, the Company recorded a ceiling writedown of $2,975,000. 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, Colorado 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 processing infrastructure exists in the region. Based on recent experience, regional differences could cause a negative basis differential of between $0.30 per Mcf and $1.50 per Mcf in Wyoming between the published indices generally used to establish the price received for regional natural gas production and the actual price received by us for our natural gas production.
8
| |
| Forward sales transactions may limit our potential gains or expose us to loss. |
To manage our exposure to price risks in the marketing of our natural gas, we enter into natural gas fixed price physical delivery contracts from time to time with respect to a portion of our current or future production. These transactions could limit our potential gains if natural gas prices were to rise substantially over the price 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 futures contracts fail to perform under the contracts; or |
|
| • | our production costs on the hedged 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 Infinity’s 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 activities are cash generated by operations, future sales of equity securities or subordinated debt securities, obtaining additional subordinated debt financing or the sale of additional senior secured debt securities under the terms of an existing securities purchase agreement. Under that agreement, we can borrow up to $15 million per twelve-month period for the next three years, commencing in the third quarter of 2005, depending on our satisfaction of certain closing conditions and on our maximum balance of notes outstanding, based generally on a combination of performance of Infinity’s oilfield service business and the after-tax PV-10 Value of Infinity’s proved reserves.
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 shareholders. 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 gas production.
9
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 Senior Secured Note Facility may adversely affect our cash flow and our ability to raise additional capital. |
Our Senior Secured Notes Facility is secured by a pledge of substantially all of our natural gas and oil properties and oilfield services business assets, is guaranteed by our subsidiaries and contains covenants that limit additional borrowings, dividends to shareholders, the incurrence of liens, investments, sales or pledges of assets, changes in control and other matters. The Senior Secured Notes Facility also requires that specified financial ratios be maintained. The restrictions of our Senior Secured Notes 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 |
|
| • | 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 23, 2005, we had total long-term debt of approximately $37.8 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 Senior Secured Notes 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 shareholders; |
|
| • | 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 ceiling write-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
10
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 will begin producing this year, other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir will be 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, the estimated proved reserves will be redetermined on an annual basis 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.
In addition, 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. Such factors could cause us to write down the value of our properties in future periods.
As of December 31, 2004, Infinity-Wyoming had approximately $6.9 million invested in unproved oil and gas properties not subject to amortization on its Labarge Field. During 2004, Infinity-Wyoming performed completion or recompletion operations on five wells in the Labarge Field.
For the period ended December 31, 2005, or during 2006, 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 is an activity that 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
11
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 |
|
| • | 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
12
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; |
|
| • | 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 adequate 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 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, 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.
13
| |
| 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. Legislationwells, including cementing, acidizing, fracturing, and regulations affectingwater hauling. Consolidated provides these services out of service facilities it owns or leases in Ottawa, Eureka, and Thayer, Kansas; Bartlesville, Oklahoma; and Gillette, Wyoming. In April 2004, Consolidated expanded its presence in the industry are under constant reviewMid-Continent region with the acquisition of substantially all of the assets and liabilities of Blue Star Acid Services, Inc., a provider of acid and cementing services in eastern and central Kansas and north central Oklahoma, for amendment or expansion, raising$1.2 million in cash and the possibilityassumption of changes that may adversely affect, among other things, the pricing,$0.2 million in liabilities. In September 2004, Consolidated sold selected assets from its Chanute, Kansas location, including real property and facilities, to an exploration and production or marketingcompany and customer for $4.1 million in cash.
Consolidated operates a fleet of approximately 100 vehicles specifically designed to provide service to oil and gas well operators working at depths ranging from 100 to 5,000 feet, as is usually the case in eastern Kansas, northeast Oklahoma, and oilfield services. 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 estimates it will spend approximately $1.0 million to drill and equip one water disposal well to handle water produced from gas wells in 2005. It costs Infinity approximately $50,000 per year to operate each disposal well. In addition to the environmental costs that will be incurred by our oil and gas production operations, Consolidated will incur an estimated $50,000 in costs associated with operating within current environmental regulations this fiscal year. 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; |
|
| • | 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; |
14
| | |
| • | releases or discharges of hazardous materials; |
|
| • | well reclamation costs; |
|
| • | oil spill clean-up costs; |
|
| • | other remediation and clean-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 oilfield service operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. 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.
Large volumes of water produced from coalbedcoal bed methane wells and discharged onto the surfacedevelopment in the Powder River Basin of Wyoming have drawnWyoming. The service vehicles are part of the attention of government agencies, gas producers, citizens and environmental groups which may result in new regulationscollateral for the disposal of produced water. Infinity intends to use injection wells to dispose of water into underground rock formations at certain of its fields and intends 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, Infinity could incur costs of up to $7.50 per barrel of water to dispose of the produced water. At December 2004 production rates, this would cost us an additional $100,000 per month in average water disposal costs. If our wells produce water in excess of the limits of its disposal facilities, we may have to drill additional disposal wells. Each additional disposal well could cost us up to $1.0 million.Company’s Senior Secured Note Facility.
5
15
| |
| The oil and gas industry is highly competitive. |
We operate in the highly competitive areas of oil and natural gas exploration, exploitation, acquisition, production and oilfield services 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 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 currently maintain “key man” life insurance on the lives of Stanton E. Ross and Stephen D. Stanfield in the amount of $250,000 each. 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.
16
SIGNIFICANT PROJECTEXPLORATION AND PROSPECT AREASPRODUCTION
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 |
Erath and Hamilton Counties, Texas
At December 31, 2004,2005, Infinity-Texas held leases on approximately 32,00040,000 gross (approximately 27,00029,000 net) acres in this area located in the southwest portion of the Fort Worth Basin in North Centralnorth 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 March 23,December 31, 2005, Infinity-Texas operates fiveoperated eight gross (4.6(7.6 net) wells in the area, all of which have been completedsix were active producers, one wasshut-in, and are waiting installation of gathering and flow lines and hookup toone was a third-party pipeline system.water disposal well. Infinity-Texas has an averagea 90% working interest and an average 72% net revenue interest in the acreage in this area. During 2005, Infinity-Texas produced approximately 190,000 thousand cubic feet (“Mcf”) of natural gas from the field.
During 2004, Infinity-Texas expectshorizontally drilled three wells, completing one of those wells prior to begin production from its initialyearend 2004. During 2005, Infinity-Texas horizontally drilled an additional four wells as early as late April 2005. Based on initial drilling and completion efforts, Infinity-Texas has reserved a drilling rig as early as June 2005 and currently expects to drill approximately one horizontal well per month with accompanying completion operations to follow the drilling.completed six wells. Infinity-Texas also plans to drillvertically drilled a water disposal well for the disposal of frac flowback fluids and water produced from its wells in the area during 2005.area. During 2005, Infinity-Texas acquired and interpreted approximately 25 square miles of3-D seismic data over the northern 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 series of one year commitments and is currently drilling approximately one horizontal well every three weeks, with accompanying completion operations following the drilling. Infinity-Texas expects to be able to drill and complete between 18 and 20 horizontal wells per year with this rig. Infinity-Texas has contracted for a second drilling rig to drill a limited number of exploration wells in Erath and Comanche Counties, Texas during 2006. Dependent upon the success of early operations in 2005,2006, Infinity-Texas may elect to extend the contract to accelerate drilling and completion operations in the Erath and Hamilton Counties area in 2006.
In the first two months of 2006, Infinity-Texas has vertically drilled one well, horizontally drilled three wells, and commenced drilling on a fourth horizontal well. Through such date two of the horizontal wells have been completed as producers and one horizontal well and the vertical well are waiting completion operations. Infinity-Texas recently completed micro-seismic operations in connection with the completion of one of the horizontal wells. During 2006, Infinity-Texas intends to acquire approximately 30 square miles of3-D seismic data generally over the southern portion of its Erath County acreage.
In February
Comanche County, Texas
At December 31, 2005, Infinity-Texas signed a definitive agreement for the acquisition ofheld leases on approximately 24,50030,000 gross (and net) acres in this area, located approximately 30 miles southwest of the Erath and Hamilton County properties. The agreement, as amended, also provides for a right of first refusal on most of the acres acquired by the seller in Comanche County. We expect to close the Comanche transaction on or before April 19, 2005. Upon closing,During 2006, Infinity-Texas expects to explore for natural gas and natural gas liquids 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.
Infinity-Texas agreed to drill at least one test well on the Comanche acreage during the next twelve months. Dependent upon the availability of drilling rigs and other support equipment,by April 9, 2006. Infinity-Texas expects to commence drilling operations during the second half of 2005.by April 1, 2006.
6
Greater Green River Basin
| |
| 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, 2004,2005, Infinity-Wyoming held leases on approximately 22,00020,500 gross acres (approximately 19,00018,100 net acres) located on the Wamsutter Arch in the Greater Green River Basin of Southwestsouthwest 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, 2004,2005, Infinity-Wyoming operated
17
40 37 wells in the field, of which 1921 were active producers, 138 wereshut-in, one was waiting completion operations, three 3 were water disposal wells, and four5 were waitingawaiting completion or plugging and abandonment.abandonment operations.
During 2004,2005, Infinity-Wyoming produced approximately 929,800670,000 Mcf of natural gas and 33,70025,000 barrels of crude oil, or 1,131,800820,000 thousand cubic feet of natural gas equivalent (“Mcfe”) from the field, compared to 1,051,200930,000 Mcf of natural gas and 57,40033,000 barrels of crude oil, or 1,395,7001,130,000 Mcfe produced from the field during 2003.in 2004. Production during 20042005 represented a 19%27% decrease from 2003.2004. Production has generally declined since peaking in the quarter ended March 31, 2003, when2003.
Production from our Wamsutter Arch Pipeline Field during January and February 2006 was negatively impacted byfreeze-ups, mechanical failures of third-party gathering and compression facilities, and chronic shortages of third-party pulling units and other equipment and services needed to restore production. Beginning in March 2006, production reached 408,100 Mcfe.levels at the Pipeline Field have returned to near-normal levels.
Infinity-Wyoming plans to drill up to seven additional well locations in the field during 2005, subject to rig availability and the completion of an ongoing federal environmental assessment. Infinity-Wyoming believes it may have up to an additional 20 drilling locations available to drill, including the planned wells for 2005.
Labarge Field
At December 31, 2004,2005, Infinity-Wyoming held leases on approximately 12,00011,500 gross (and 11,000 net) acres located on the northern extension of the Moxa Arch in Southwestsouthwest 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, 2004,2005, Infinity-Wyoming operated 12 wells in the field, of which five10 were active producers, five were shut-in, and two2 were water disposal wells. Infinity-Wyoming intends to recommence production operations in the spring of 2006 following the winter snow melt.
Infinity-Wyoming produced approximately 24,00012,000 Mcf of natural gas from the field during 2004,2005, as compared to approximately 29,00024,000 Mcf of natural gas during 2003.2004. Production during 20042005 represented a 17%50% decrease as compared to 2003.2004. 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 uneconomic, despite modest completion and recompletion efforts in 2004 to re-establish economic production.generally uneconomic. The completed and recompleted wells from 2004 continue to undergo dewatering operations, which may increase the level of future gas production.
Infinity-Wyoming is subject to an ongoing Bureau of Land Management environmental impact study (“EIS”) on the Labarge Field federal acreage. The EIS must be completed before Infinity-Wyoming can continue development of the acreage. The EIS was commenced in 2002 and was originally anticipated to be completed in six to eight months. Infinity-Wyoming currently anticipates that the EIS will be completed during 2005.2006. Depending on the results of dewatering and and the availability of equipment, we may commence drilling and completion activities during the fourth quarter of 2005.2006.
Northwest Colorado
For purposes of presentation, we divide our Northwestnorthwest Colorado operations into two main property areas: Sand Wash Prospect and Piceance Basin Prospect.
Sand Wash Prospect
At December 31, 2004,2005, Infinity-Wyoming held leases on approximately 104,00053,700 gross acres (approximately 67,00046,900 net acres) located in the Sand Wash Basin of Northwestnorthwest Colorado and South Centralsouth central Wyoming. Infinity-WyomingInfinity-
7
Wyoming currently seeks to explore and develop hydrocarbons in the fractured Niobrara calcareous shale between 5,500 and 6,500 feet. Secondary objectives include exploiting the Williams Fork and Iles coals at varying depths between 2,500 and 3,000 feet. Infinity-Wyoming continues to seek offers from other industry operators for interests in the acreage in exchange for cash and a carried interest in drilling operations. No assurance can be given that any such transactions will be consummated.
At December 31, 2004,2005, Infinity-Wyoming operated two producing oil properties and fourshut-in wells in the field which were completed in the coals. Drilling was in progress atsuspended for the winter on one fractured Niobrara proved undeveloped location, which was subsequently completed as a producer in February 2005.
18
Infinity-Wyoming plans to drill one additional well targeting the fractured Niobrara shaleshale. Infinity-Wyoming intends to attempt a completion of this well during the summer of 2006. Infinity-Wyoming continues to seek the acquisition of additional geophysical data in order to better delineate future prospective drilling locations.
During 2005, subjectInfinity-Wyoming produced approximately 53,000 gross barrels (43,000 net barrels) of oil from this field.
Infinity-Wyoming plans to rig availability, and 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 of two wells at the original pilot location in 2004 due to the onset of winter and the resultant 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 during 2004 prior to determining what additional operations, if any, to perform.
Piceance Basin Prospect
At December 31, 2004,2005, Infinity-Wyoming held leases on approximately 20,0009,100 gross and net(and net) acres in the northeastern corner of the Piceance Basin in Northwestnorthwest Colorado. Infinity-Wyoming originally sought to exploitThe acreage is located along the Williams Fork and Iles coals at varying depths between 1,000 and 3,000 feet. Under the termsnorthern rim of the lease agreement covering a substantial portionPiceance Basin and the southern extent of the acreage, Infinity-Wyoming is required to drill and complete five wells by November 20, 2005, or relinquish the acreageAxial Basin Arch. Immediately adjacent to the seller. Infinity-Wyoming drilled one pilot wireline coring well during 2004prospect 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 results ofDakota and Morrison-Brushy Creek sandstone formations. Secondary reservoir targets might include the ensuing core analysisMesaverde sands and gas desorption analysis indicated coalbed methane gas content in the coals, was below the level believed by management to be commercial. In 2005,Morrison-Salt Wash, Entrada, Shinarump, Moenkopi, Weber and Morgan-Minturn formations. Infinity-Wyoming expects to re-evaluate its plans to explore for coalbed methane or otherconduct additional geological and potentially geophysical studies in 2006 to identify potential conventional and deeper formation targets at this prospect. Management believes it is unlikely that the2007 drilling commitments will be met during 2005.opportunities.
Nicaragua
Since being awarded the two concessions in 2003, Infinity has negotiated a number of key terms and conditions of thean 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 as currently negotiated, contemplates an exploration period of up to six years with four sub-phases and a production period of up to 30 additional years (with a potential five year extension). The contract is in final negotiations and is expected to be executed in 2005,2006, following final approvals by the Nicaraguan government. Upon execution, the initial capital costs during the first twelve months, for which Infinity would post a performance bond, are expected to be up to approximately $800,000,total less than $1.0 million, with up to an additional $1,600,000a 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.
Exploration offshore Nicaragua willwould focus on Eocene and Cretaceous carbonateCarbonate 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-interestcarried interest in exploration and development operations. No assurance can be given that any such transactions will be consummated.
In February 2000, Infinity Oil and Gas of Kansas, Inc. (“Infinity-Kansas”) acquired a 100% working interest in a property in Eastern Kansas, through a joint venture with an operator in which a former director of Infinity is a partner and operations manager. Infinity-Kansas’ total investment in the property was approximately $1,100,000. In addition, Infinity-Kansas had an active oil lease in the Owl Creek Field in Woodson County, Kansas which was acquired for $510,000. Effective May 1, 2002, Infinity-Kansas sold its interest in oil and gas properties in Eastern Kansas for $180,000 cash and a $1,620,000 note receivable due in May 2005. The issuer of the note has the option to return the underlying interests to Infinity-Kansas in lieu of repaying the note receivable. Infinity-Kansas does not anticipate the return of the underlying interests based on its belief that the value of these interests currently exceeds the balance of the note receivable. Infinity-Kansas does not currently have any material investment in any other oil and gas prospects.
19
OILFIELD SERVICESOil and Natural Gas Reserves
Consolidated provides numerous services associated with drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, nitrogen pumping and water hauling. Consolidated provides these services out of service facilities it owns or leases in Ottawa, Eureka, and Thayer, Kansas; Bartlesville, Oklahoma; and Gillette, Wyoming. Due to the decrease in the number of wells being drilled and the schedule on which wells would be drilled by Infinity-Wyoming and an increase in service requests and equipment demand in other services areas, Consolidated closed its Rock Springs, Wyoming facility, terminated its lease on the operating facilities and transferred its service equipment to its other locations in December 2003. In April 2004, Consolidated expanded its presence in Mid-Continent region with the acquisition of substantially all of the assets and liabilities of Blue Star Acid Services, Inc., a provider of acid and cementing services in Eastern and Central Kansas and North Central Oklahoma, for $1.2 million in cash and the assumption of $0.2 million in liabilities. In September 2004, Consolidated sold selected assets from its Chanute, Kansas location, including real property and facilities, to an exploration and production company and customer, for $4.1 million in cash.
Consolidated operates a fleet of approximately 100 vehicles specifically designed to provide service to oil and gas well operators working at depths ranging from 100 to 5,000 feet, as is usually the case in Eastern Kansas, Northeast Oklahoma, and for coal bed methane development in the Powder River Basin of Wyoming. The service vehicles are part of the collateral for the Senior Secured Note Facility closed in January 2005.
Consolidated leases property near Cheyenne, Wyoming, which is the site of the brine water treatment facility. Rent on this land lease is $1,000 per year. The lease is for a term of twenty five years beginning July 1994, but may be terminated by Consolidated at any time on written notice. In February of 2003 Consolidated signed a letter of intent to sell these facilities and transfer the lease on the property to the new owner. However, the potential purchaser to the letter of intent was unable to finance the acquisition and the sale has not been completed. Consolidated is working with the potential purchaser to identify a structure which will allow the sale to be completed. We do not know when or if the sale might be completed.
| |
| Oil and Natural Gas Reserves |
Infinity-Wyoming 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, 2004 and 2003.2005. 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, 20042005 were utilized. Activity subsequent to December 31, 20042005 in the Fort Worth, Sand Wash and Greater Green River Basins was not taken into consideration in the proved reserve estimate as of December 31, 2004,2005, but maywill be reflected in future estimates.
The following table sets forth estimates as of December 31, 20042005 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 19-17 — Supplemental Oil and Gas Information (Unaudited) in the Notes to the Consolidated Financial Statements.
| | | | | | | | | | | | | |
| | | Developed | | | Undeveloped | | | Total | |
| | | | | | | | | | |
| Natural gas (Mcf) | | | 3,773,033 | | | | 4,269,913 | | | | 8,042,946 | |
| Crude oil (barrels) | | | 117,031 | | | | 76,546 | | | | 193,577 | |
| Total (Mcfe) | | | 4,475,219 | | | | 4,729,189 | | | | 9,204,408 | |
| Future net revenue before income taxes | | $ | 18,037,000 | | | $ | 16,545,500 | | | $ | 34,582,500 | |
| Present value of future net revenue before income taxes | | $ | 13,168,500 | | | $ | 10,850,900 | | | $ | 24,019,400 | |
20
| | | | | | | | | | | | | |
| | | Developed | | | Undeveloped | | | Total | |
| |
| Natural gas (Mcf) | | | 5,031,235 | | | | 6,067,971 | | | | 11,099,206 | |
| Crude oil (barrels) | | | 712,094 | | | | 124,671 | | | | 836,765 | |
| Total (Mcfe) | | | 9,303,799 | | | | 6,815,997 | | | | 16,119,796 | |
| Future net revenue before income taxes (in thousands) | | $ | 54,851 | | | $ | 21,336 | | | $ | 76,187 | |
| Present value of future net revenue before income taxes (in thousands) | | $ | 35,291 | | | $ | 8,689 | | | $ | 43,980 | |
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, 20042005 were $6.07$8.21 per Mcf of natural gas and $40.25$60.74 per barrel of crude oil.
9
Production, Prices and Production Costs
| |
| Production, Prices and Production Costs |
The following table sets forth Infinity’s net oil and gas production, average sales prices realized, and costs and expenses associated with such production during the years indicated.
| | | | | | | | | | | | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
Production: | | | | | | | | | | | | |
| | Natural gas (Mcf) | | | 953,428 | | | | 1,080,456 | | | | 676,879 | |
| | Crude oil (barrels) | | | 33,668 | | | | 57,654 | | | | 53,122 | |
| | Total (Mcfe) | | | 1,155,436 | | | | 1,426,380 | | | | 995,611 | |
Average daily production: | | | | | | | | | | | | |
| | Natural gas (Mcf) | | | 2,612 | | | | 2,960 | | | | 1,854 | |
| | Crude oil (barrels) | | | 92 | | | | 158 | | | | 145 | |
| | Total (Mcfe) | | | 3,164 | | | | 3,908 | | | | 2,727 | |
Average sales price per unit: | | | | | | | | | | | | |
| | Natural gas ($per Mcf) | | $ | 5.12 | | | $ | 4.47 | | | $ | 1.88 | |
| | Crude oil ($per barrel) | | $ | 41.15 | | | $ | 30.51 | | | $ | 17.14 | |
| | Total ($per Mcfe) | | $ | 5.42 | | | $ | 4.62 | | | $ | 2.38 | |
Production costs per Mcfe | | $ | 2.28 | | | $ | 2.05 | | | $ | 1.83 | |
| | | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| |
Production: | | | | | | | | | | | | |
| Natural gas (Mcf) | | | 875,543 | | | | 953,428 | | | | 1,080,456 | |
| Crude oil (barrels) | | | 68,497 | | | | 33,668 | | | | 57,654 | |
| Total (Mcfe) | | | 1,286,525 | | | | 1,155,436 | | | | 1,426,380 | |
Average daily production: | | | | | | | | | | | | |
| Natural gas (Mcf) | | | 2,399 | | | | 2,612 | | | | 2,960 | |
| Crude oil (barrels) | | | 188 | | | | 92 | | | | 158 | |
| Total (Mcfe) | | | 3,525 | | | | 3,164 | | | | 3,908 | |
Average sales price per unit: | | | | | | | | | | | | |
| Natural gas ($per Mcf) | | $ | 6.06 | | | $ | 5.12 | | | $ | 4.47 | |
| Crude oil ($per barrel) | | $ | 56.74 | | | $ | 41.15 | | | $ | 30.51 | |
| Total ($ per Mcfe) | | $ | 7.14 | | | $ | 5.42 | | | $ | 4.62 | |
Production costs per Mcfe | | $ | 3.44 | | | $ | 2.28 | | | $ | 2.05 | |
Infinity owned 2428 gross (22(25.7 net) producing wells and 56 gross (5(6 net) service wells as of December 31, 2004.2005. Infinity owned an additional 2826 gross (27.7(25.9 net) wells which were shut in, waitingawaiting completion or plugging and abandonment operations as of December 31, 2004.2005.
21
| |
| Development, Exploration and Acquisition Capital Expenditures |
Development, Exploration and Acquisition Capital Expenditures
The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities.activities (in thousands):
| | | | | | | | | | | | | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Property acquisition costs | | | | | | | | | | | | |
| | Proved | | $ | 516,239 | | | $ | 1,099,120 | | | $ | 72,383 | |
| | Unproved | | | 3,717,280 | | | | 661,224 | | | | 2,279,587 | |
| | | | | | | | | | |
| | | Total property acquisition costs | | | 4,233,519 | | | | 1,760,344 | | | | 2,351,970 | |
| Development costs | | | 6,056,131 | | | | 3,167,700 | | | | 786,095 | |
| Exploration costs | | | 5,294,148 | | | | 3,491,953 | | | | 11,955,351 | |
| | | | | | | | | | |
| Total costs | | $ | 15,583,798 | | | $ | 8,419,997 | �� | | $ | 15,093,416 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| |
| Property acquisition costs | | | | | | | | | | | | |
| Proved | | $ | 330 | | | $ | 516 | | | $ | 1,099 | |
| Unproved | | | 5,745 | | | | 3,625 | | | | 661 | |
| | | | | | | | | | | | | |
| Total property acquisition costs | | | 6,075 | | | | 4,141 | | | | 1,760 | |
| Development costs | | | 17,099 | | | | 6,156 | | | | 3,168 | |
| Exploration costs | | | 17,583 | | | | 5,294 | | | | 3,492 | |
| Asset retirement costs | | | 907 | | | | 93 | | | | 503 | |
| | | | | | | | | | | | | |
| Total costs | | $ | 41,664 | | | $ | 15,684 | | | $ | 8,923 | |
| | | | | | | | | | | | | |
10
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 wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
| | | | | | | | | | | | | | | | | | | |
| Exploratory Wells | | | | | | | | | | | | | | | | | | | | | | | | |
| | Productive | | | 3 | | | | 2.9 | | | | — | | | | — | | | | 13 | | | | 13 | |
| | Nonproductive | | | — | | | | — | | | | — | | | | — | | | | 9 | | | | 9 | |
| | | | | | | | | | | | | | | | | | | |
| | | Total | | | 3 | | | | 2.9 | | | | — | | | | — | | | | 22 | | | | 22 | |
| | | | | | | | | | | | | | | | | | | |
| Development Wells | | | | | | | | | | | | | | | | | | | | | | | | |
| | Service | | | — | | | | — | | | | 1 | | | | 1 | | | | 2 | | | | 2 | |
| | Productive | | | 9 | | | | 8.0 | | | | — | | | | — | | | | 2 | | | | 2 | |
| | Nonproductive | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| | | Total | | | 9 | | | | 8.0 | | | | 1 | | | | 1 | | | | 4 | | | | 4 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
| |
| Exploratory Wells | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | | 6 | | | | 5.7 | | | | 3 | | | | 2.9 | | | | — | | | | — | |
| Nonproductive | | | 1 | | | | 1.0 | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 7 | | | | 6.7 | | | | 3 | | | | 2.9 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Development Wells | | | | | | | | | | | | | | | | | | | | | | | | |
| Service | | | 1 | | | | 1.0 | | | | — | | | | — | | | | 1 | | | | 1 | |
| Productive | | | 5 | | | | 5.0 | | | | 9 | | | | 8.0 | | | | — | | | | ��� | |
| Nonproductive | | | 1 | | | | 1.0 | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 7 | | | | 7.0 | | | | 9 | | | | 8.0 | | | | 1 | | | | 1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
As of December 31, 2004,2005, Infinity had an additional nine7 wells which were drilled in 2005 or prior awaiting completion, including five4 wells waiting likely plugging and abandonment operations and four which were completed as producers by March 23, 2005.operations.
22
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, 2004.2005. 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 | | | — | | | | — | | | | 32,108 | | | | 26,634 | |
Greater Green River Basin | | | | | | | | | | | | | | | | |
| | Wamsutter Arch | | | 4,000 | | | | 3,840 | | | | 18,210 | | | | 15,490 | |
| | Labarge | | | 1,763 | | | | 1,763 | | | | 9,967 | | | | 9,436 | |
Sand Wash Prospect | | | 640 | | | | 640 | | | | 103,592 | | | | 66,285 | |
Piceance Basin Prospect | | | — | | | | — | | | | 20,020 | | | | 20,020 | |
| | | | | | | | | | | | | |
| | | Total | | | 6,403 | | | | 6,243 | | | | 183,897 | | | | 137,865 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Developed
| | | | |
| | | Acreage | | | Undeveloped Acreage | |
| | | Gross | | | Net | | | Gross | | | Net | |
| |
| Fort Worth Basin | | | 1,916 | | | | 1,724 | | | | 68,418 | | | | 57,578 | |
| Greater Green River Basin | | | | | | | | | | | | | | | | |
| Wamsutter Arch | | | 4,480 | | | | 4,080 | | | | 16,093 | | | | 14,045 | |
| Labarge | | | 1,763 | | | | 1,763 | | | | 9,715 | | | | 9,184 | |
| Sand Wash Prospect | | | 960 | | | | 960 | | | | 52,752 | | | | 45,906 | |
| Piceance Basin Prospect | | | — | | | | — | | | | 9,063 | | | | 9,063 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 9,119 | | | | 8,527 | | | | 156,041 | | | | 135,776 | |
| | | | | | | | | | | | | | | | | |
Infinity-Wyoming held options on an additional approximately 18,000 gross acres in the Labarge field as of December 31, 2004.2005. The table does not reflect any reclassification of our acreage to reflect the wells completed by Infinity-Texas and Infinity-Wyoming after December 31, 2004.2005.
Customers and Markets
| |
| Exploration and Production |
Infinity-Wyoming sells
Exploration and Production
The majority of Infinity-Wyoming’s gas production from the Pipeline Field is sold to Duke Energy Field Services (“Duke”). Approximately 55% of its gas was sold to Duke onunder a forward contract, basis during the nine months ended December 31, 2004, with the remainder being sold 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 thefixed price contracts to hedge its production when market conditions are deemed favorable in
11
order to manage price fluctuations and achieve a more predictable cash flow. The following table identifies the contracts that wereone contract in place during the year endedat December 31, 2004:2005:
| | | | | | | | | | | | | | |
| | | | | Daily |
| | |
Beginning Date | Contract Term | | Ending Date | Contract Volume(1) | | Contract Volume (1) | | | Contract Price | |
| | | | | | | | | | | |
| April 1, 2004 | | | | 2005 — March 31, 2005 | 2006 | | | 2,000 MMBtu | | | $ | 4.40/MMBtu | |
| April 1, 2005 | | | | March 31, 2006 | | | | 2,000 MMBtu | | | $ | 4.15/MMBtu | |
| | |
| (1) | | MMBtu of gas is equivalent to one million British thermal units (“Btu”), a standard measure of the heating value of the gas. The gas produced from the Pipeline project contains about 1100 Btu per cubic foot of gas.) |
Oil production from the Pipeline Field is sold at the average daily NYMEX posted price less $0.50 per barrel. For December 2004,2005, this was a price of $42.84$58.80 per barrel of oil.
The following table shows exploration and production revenue and the percentage of consolidated revenue that the value represented for each of the years ended December 31, 2005, 2004 2003 and 2002.2003:
| | | | | | | | | |
| | | Oil and Gas | | | Percentage of | |
| Period | | Revenue | | | Total Revenue | |
| | | | | | | |
| 2004 | | $ | 6.3 million | | | | 30% | |
| 2003 | | $ | 6.6 million | | | | 36% | |
| 2002 | | $ | 2.4 million | | | | 22% | |
| | | | | | | | | |
| | | Oil and Gas
| | Percentage of
|
Period | | Revenue | | Total Revenue |
| |
| 2005 | | $ | 9.2 million | | | | 30 | % |
| 2004 | | $ | 6.3 million | | | | 30 | % |
| 2003 | | $ | 6.6 million | | | | 36 | % |
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.
23
Oilfield Services
Consolidated provides its services to oil and gas developers and lease operators throughout Easterneastern Kansas and Northeastnortheast Oklahoma, which includes the Cherokee, Forest City and CherokeeSalina Basins, and in the Powder River Basin of Northeastnortheast Wyoming. Consolidated also provides its services in the Arkoma basin of Easterneastern Oklahoma and provides well cementing services to water well drillers in Missouri, Kansas and Oklahoma.
Consolidated provided services to more than 500 customers during 2005, to approximately 475 customers during 2004 and to approximately 400 customers during 2003 and to approximately 380 customers during 2002.2003. The following table sets out information about Consolidated’s major customers during each of these periods:
| | | | | | | | | | | | | | | | |
| | | | | | | Percent | | | Percent of | |
| Customer | | Area of Operation | | Revenue | | | of Total | | | Oilfield Service | |
| | | | | | | | | | | | |
2004 | | | | | | | | | | | | | | |
| | Qwest Cherokee LLC | | Eastern Kansas/Northeast Oklahoma | | $ | 2.1 million | | | | 10% | | | | 14% | |
| | | | Northeast Wyoming | | $ | 1.5 million | | | | 7% | | | | 10% | |
| | | | Northeast Oklahoma | | $ | 1.4 million | | | | 7% | | | | 10% | |
| |
2003 | | | | | | | | | | | | | | |
| | | | Northeast Oklahoma | | $ | 1.1 million | | | | 6% | | | | 10% | |
| | | | Eastern Kansas | | $ | 0.9 million | | | | 5% | | | | 8% | |
| |
2002 | | | | | | | | | | | | | | |
| | Devon Energy | | Eastern Kansas/Northeast Oklahoma | | $ | 1.6 million | | | | 14% | | | | 18% | |
| | | | | | | | | | | | | | | | | |
| | | | | | | Percent
| | Percent of
|
Customer | | Area of Operation | | Revenue | | of Total | | Oilfield Service |
| |
2005 | | | | | | | | | | | | | | | | |
| Yates Petroleum | | | northeast Wyoming | | | $ | 3.0 million | | | | 10 | % | | | 14 | % |
| Newfield Exploration | | | northeast Oklahoma | | | $ | 2.7 million | | | | 9 | % | | | 12 | % |
2004 | | | | | | | | | | | | | | | | |
| Qwest Cherokee LLC | | | eastern Kansas/northeast Oklahoma | | | $ | 2.1 million | | | | 10 | % | | | 14 | % |
| | | | northeast Wyoming | | | $ | 1.5 million | | | | 7 | % | | | 10 | % |
| | | | northeast Oklahoma | | | $ | 1.4 million | | | | 7 | % | | | 10 | % |
2003 | | | | | | | | | | | | | | | | |
| Equity | | | northeast Oklahoma | | | $ | 1.1 million | | | | 6 | % | | | 10 | % |
| Dart | | | eastern Kansas | | | $ | 0.9 million | | | | 5 | % | | | 8 | % |
Consolidated alsohas provided services to Infinity-Wyoming which resulted in eliminated inter-company revenue of approximately $2.1 million in 2002.from time to time. The amount of revenue earned by Consolidated from inter-company sales was less than $20,000 during 2003. There were no inter-company sales during 2004.2004 and 2005. Consolidated has no long-term service contracts with any customers and we do not believe that a loss of any one of our customers will have a prolonged material adverse effect on Consolidated’s business. However, the loss of several customers in any location or a rapid, significant change in oil and gas prices to the extent that customers curtail their development activities could have a material adverse impact on our financial and operating results.
12
Competition
Infinity and its subsidiaries compete in virtually all facets of their businesses with numerous other companies, 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. The oilfield service competitors may be able to invest more resources in research and development of new completion techniques and acquire additional equipment to allow them to dedicate resources to a customer in a way that Consolidated is unable to.
| |
| Exploration and Production |
Exploration and Production
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 |
24
| | |
| | • | 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.
Oilfield Services
Consolidated’s competition for cementing services in Easterneastern Kansas consistand northeast Oklahoma consists mainly of Superior Well Services, Inc., United Cementing & Acid Co., Inc., and Oilwell Cementers Inc. Consolidated’s competition for fracturing and acidizing services in eastern Kansas and northeast Oklahoma consists mainly of Cudd Pumping Services. In Northeast Oklahoma, Consolidated competes with Cudd Pumping Services, Superior Well Services, Inc., Oilwell Fracturing Services, Inc. and Maverick Stimulation Company, LLC. Other less significant competitors in these areas include BJ Services Company, Oilwell Fracturing Services, Inc.a major service company, and several small local companies. Consolidated believes that its bulk materials facilities, experienced work force, and well maintained fleet of service vehicles puts it in a competitive position to maintain revenues in these locations. In northeast Wyoming, Consolidated continues to see competition from three major service companies, Halliburton Company, BJ Services Company, and Schlumberger Ltd., and numerous smaller cementing companies, in Northeast Wyoming.including Basic Energy Services, Inc., Bison Oil Well Cementing Inc. and M & S Oil Well Cementing. Consolidated may be at a competitive disadvantage when compared to the major companies that are well established with substantial financial resources. These companies can redirect assets and manpower, much like Consolidated has done, to insureensure that resources to meet the growing demand are available. Some of the exploration and development companies in this area also have the resources available to developservice their own service providers.oil and gas operations. Consolidated’s ability to provide services that meet the market demand in a timely manner while providing quality service to the wells will be crucial to its ability to compete in this market.
Delivery Commitments
Effective September 2001, Infinity-Wyoming entered into a gas gathering and transportation contract with Duke in which Duke 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 Duke and delivery points for the additional production being generated by Infinity-Wyoming. Infinity-Wyoming pays a gathering fee of $0.40 per Mcf until 7,500,000 Mcf have been produced at which time the fee will be reduced to $0.25 per Mcf. Infinity-WyomingAdditionally, the Company had annual volume commitments for five years starting September 1, 2001. If the Company exceeded the
13
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 obligatedadded to deliver 600,000 Mcf the first year, 1,600,000 Mcf the second year, 2,000,000 the third year, 1,800,000 the fourth year, and 1,500,000 in the fifth and final year of the contract.following years. To date, Infinity-Wyoming has delivered approximately 3,137,0004,000,000 Mcf under this contract. The Pipeline sales volumes willare also be 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 operator hasoperators have also not provided the compression and gathering capabilities they were required to provide under the contract. Management has received a verbal commitment from the operator that the volume commitments willwould be adjusted and management does not expect that there will be a contract shortfall under the renegotiated volumes.volumes although the contract term will likely be lenghtened.
Beginning April 1, 2003 and effective through March 31, 2004, Infinity-Wyoming had contracted to sell 3,500 MMBtu per day to Duke at a price of $4.71 per MMBtu, which equates to approximately $5.16 per Mcf. In 2004, Infinity-Wyoming entered into two additional contracts with Duke for the sale of 2,000 MMBtu per day. The first contract iswas for the period April 1, 2004 through March 31, 2005 and setsat a price of $4.40 per MMBtu (approximately $4.84 per Mcf). The second contract is for the period beginning April 1, 2005 and ending March 31, 2006 and is for $4.15 per MMBtu (approximately $4.57 per Mcf). Infinity-Wyoming will receive the Colorado Interstate Gas (CIG) Pipeline first of the month index price for each Mcf of gas in excess of the contracted volume delivered onto the Overland Trail Transmission line. Infinity and its subsidiaries had no agreements or commitments at December 31, 2004,2005, other than those shown above, to provide quantities of oil or gas in the future.
25
| |
| Government Regulation of the Oil and Gas Industry |
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. The Company may, at its discretion and with notice, reduce the minimum daily delivery volumes by up to 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 |
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 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.
14
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 Bureau of Land Management (“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
26
governing the valuation of gas produced from federal leases. This rule, which becomes effective June 1, 2005, 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.
| |
| Environmental and Land Use Regulation |
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; |
15
| | |
| | • | 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
27
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 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
16
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
28
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 |
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, Infinity-Wyoming, and Consolidated 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 and for other uses associated with the oil and gas industry. 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.
The operations of Consolidated routinely involve the handling of significant amounts of oilfield related materials, some of which are classified as hazardous substances. Consolidated’s transportation operations are regulated under the Federal Motor Carrier Safety Regulations of the Department of Transportation as administered by the Kansas Department of Transportation, Oklahoma Department of Transportation, and Wyoming Department of Transportation. The operation of salt-water disposal wells by Consolidated is regulated by the Kansas Department of Health and Environment. Consolidated will incur an estimated $100,000 in costs associated with
17
operating within current environmental regulations this fiscal yearduring 2006 primarily related to transportation of hazardous substances.
During December 2004, Infinity-Wyoming produced an average of 430 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 $100,000 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 $1,000,000. It costs Infinity-Wyoming approximately $50,000 per year 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
29
plans to drill a drilled one disposal well in Erath County, Texas during 2005. Each disposal well is expected to2005 at a cost Infinity-Texasof approximately $1,000,000.
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 as described in this offering memorandum.respects.
| |
| Operating Hazards and Insurance |
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, such as those described under “Risk Factors — Risks Related to Our Business — Our business involves significant operating risks.”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, 2004,2005, Infinity and its subsidiaries had approximately 111143 employees. Consolidated had 96125 employees in its oilfield services business; Infinity-Texas and Infinity-Wyoming had 914 employees in their exploration and production business; and Infinity had 64 employees in executive and administrative positions.
| |
ITEM 3.1A. | LEGAL PROCEEDINGSRISK FACTORS |
We have a history of operating losses and we may be unable to achieve long-term profitability.
We incurred a net loss in our fiscal years ended December 31, 2005, 2004 and 2003 of approximately $13.6 million, $4.6 million and $9.9 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
18
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.
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 $4.21 per Mcf, gas price realizations ranged from a low of $5.81 to a high of $12.04 per Mcf during the year ended December 31, 2005. Oil price realizations ranged from a low of $43.12 per barrel to a high of $65.02 per barrel during the year. Based on fourth quarter 2005 production levels, each $1.00 decrease in the price of crude oil would reduce Infinity’s oil revenue by approximately $7,000 per month and if none of the gas produced were being sold under fixed price contracts, each $0.10 decrease in natural gas price would reduce Infinity’s gas revenue by approximately $6,500 per month.
Revenue generated from oilfield services provided by Consolidated is indirectly affected by the price of oil and gas. Consolidated has historically experienced higher revenue in periods of high oil and gas prices and lower revenue in periods of low oil and gas prices.
Approximately 69% of our proved reserves are natural gas. Therefore, the volatility in the price of natural gas will have the greatest 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; |
19
| | |
| • | 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; |
|
| • | limiting our ability to finance planned capital expenditures; |
|
| • | reducing our revenue, operating income and profitability; |
|
| • | reducing the carrying value of our oil and natural gas properties; and |
|
| • | reducing demand for our oilfield service business. |
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, 2005, the carrying amount of 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. In 2004 and 2003, the Company also recorded ceiling writedowns of $4,100,000 and $2,975,000. 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 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 natural gas production and the actual price received by us for our natural gas production.
Forward sales transactions may limit our potential gains or expose us to loss.
To manage our exposure to price risks in the marketing of our natural gas, we enter into fixed price natural gas physical delivery contracts from time to time with respect to a portion of our current or future production. 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. |
20
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 activities are cash generated by operations, future sales of equity securities, subordinated debt securities, or the sale of additional senior secured debt securities under the terms of an existing securities purchase agreement. Under that agreement, we can borrow up to $15 million per twelve-month period for the next two years, depending on our satisfaction of certain closing conditions and on our maximum balance of notes outstanding, based generally on a combination of performance of our oilfield service business and the after-taxPV-10 Value of our proved reserves.
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 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 Senior Secured Note Facility may adversely affect our cash flow and our ability to raise additional capital.
Our Senior Secured Notes Facility is secured by a pledge of substantially all of our natural gas and oil properties and oilfield services business assets, 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 Senior Secured Notes Facility also requires that specified financial ratios be maintained. The restrictions of our Senior Secured Notes 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; |
21
| | |
| • | 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 |
|
| • | 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 3, 2006, the principal amount of our long-term debt totaled approximately $42.1 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 Senior Secured Notes 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 ceiling write-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 been producing for less than a year, 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.
22
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.
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 2005, 2004 and 2003 we recorded ceiling write downs of $13,450,000, $4,100,000 and $2,975,000, respectively. These factors could cause us to write down the value of our properties in future periods.
As of December 31, 2005, we had approximately $22.8 million invested in unproved oil and gas properties not subject to amortization. During 2006, 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; |
23
| | |
| • | 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 |
|
| • | 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
24
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; |
|
| • | 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 adequate 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 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, 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, production or marketing of oil and gas and oilfield services. 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 approximately $50,000 per year to operate each disposal well. In addition to the environmental costs that will be incurred by our oil and gas production operations, Consolidated will incur an estimated $50,000 in costs associated with operating within current environmental regulations during 2006. 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.
25
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; |
|
| • | 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 oilfield service operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. 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; |
26
| | |
| • | 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.
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 2005 production rates, this would cost us an additional $125,000 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 exploration, exploitation, acquisition, production and oilfield services 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 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
27
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.
| |
| 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 |
No matters were
On November 7, 2005, Infinity held a special meeting of stockholders (the “Special Meeting”) at its office in Denver, Colorado. The matter voted upon at the Special Meeting was set forth in Infinity’s Proxy Statement dated October 11, 2005. The proposal submitted to a vote of stockholders sought approval to issue shares of common stock upon conversion of Infinity’s senior secured notes, if any, and upon the Company’s shareholders duringexercise of Infinity’s warrants issued in connection with the fourth quarterissuance of 2004.the senior secured notes, to the extent that the issuance of common stock would require stockholder approval under the NASDAQ Marketplace Rules.
The following table sets forth the votes cast for or against the proposal presented at the Special Meeting, as well as the number of abstentions:
| | | | | | | | | |
| For | | Against | | Abstain |
| |
| 6,903,033 | | | 252,543 | | | | 46,477 | |
28
30
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 Small-Cap 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 23, 20053, 2006 was $10.45$9.40 per share.
| | | | | | | | | |
| Quarter Ended | | High | | | Low | |
| | | | | | | |
| March 31, 2003 | | $ | 9.74 | | | $ | 7.75 | |
| June 30, 2003 | | | 8.83 | | | | 5.50 | |
| September 30, 2003 | | | 6.01 | | | | 4.30 | |
| December 31, 2003 | | | 4.90 | | | | 3.31 | |
| |
| March 31, 2004 | | $ | 5.15 | | | $ | 2.75 | |
| June 30, 2004 | | | 5.00 | | | | 3.00 | |
| September 30, 2004 | | | 5.85 | | | | 3.87 | |
| December 31, 2004 | | | 8.49 | | | | 4.75 | |
| | | | | | | | | |
Quarter Ended | | High | | | Low | |
| |
| March 31, 2004 | | $ | 5.15 | | | $ | 2.75 | |
| June 30, 2004 | | | 5.00 | | | | 3.00 | |
| September 30, 2004 | | | 5.85 | | | | 3.87 | |
| December 31, 2004 | | | 8.49 | | | | 4.75 | |
| 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 | |
Approximate Number of Holders of Common Stock
At March 23, 2005,3, 2006, there were 235approximately 190 stockholders of record holders of Infinity’s $0.0001 par value Common Stock.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 Senior Secured Notes Facility, Infinity is prohibited from paying dividends.
29
31
| |
| ITEM 6. | SELECTED FINANCIAL DATA |
The selected consolidated financial information presented below for the years ended December 31, 2005, 2004, 2003 and 2002, and March 31, 2001, and the nine month transition period ended December 31, 2001 is derived from the audited consolidated financial statements of Infinity. Infinity changed its fiscal year end to December 31 fiscal year end31st from a March 31 fiscal year end31st effective December 31, 2001. 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 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.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Period Ended | |
| | | | |
| | | December 31, | | | |
| | | | | | March 31, | |
| | | 2004 | | | 2003 | | | 2002 | | | 2001 | | | 2001 | |
| | | | | | | | | | | | | | | | |
| | | (In thousands, except per share amounts) | |
Statement of Operations Data | | | | | | | | | | | | | | | | | | | | |
| Revenue: | | | | | | | | | | | | | | | | | | | | |
| | Oil field service operations | | $ | 14,721 | | | $ | 11,634 | | | $ | 8,570 | | | $ | 9,854 | | | $ | 8,476 | |
| | Exploration and production | | | 6,267 | | | | 6,589 | | | | 2,368 | | | | 1,759 | | | | 376 | |
| | | | | | | | | | | | | | | | |
| | | Total revenue | | | 20,988 | | | | 18,223 | | | | 10,938 | | | | 11,613 | | | | 8,852 | |
| | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| | Oil and gas service operations | | | 7,890 | | | | 6,223 | | | | 4,621 | | | | 5,154 | | | | 4,666 | |
| | Oil and gas production expense | | | 1,914 | | | | 2,161 | | | | 1,583 | | | | 1,074 | | | | 207 | |
| | Production taxes | | | 722 | | | | 759 | | | | 238 | | | | 66 | | | | 14 | |
| | General and administrative expenses | | | 5,462 | | | | 5,311 | | | | 4,647 | | | | 2,789 | | | | 2,460 | |
| | Depreciation, depletion and amortization | | | 5,198 | | | | 3,074 | | | | 1,783 | | | | 1,063 | | | | 922 | |
| | Ceiling write-down of oil and gas properties | | | 4,100 | | | | 2,975 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| | | Total expenses | | | 25,286 | | | | 20,503 | | | | 12,872 | | | | 10,146 | | | | 8,269 | |
| | | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | | | | | | | |
| | Interest expense/amortization of loan costs | | | (3,329 | ) | | | (7,794 | ) | | | (837 | ) | | | (1,866 | ) | | | (1,062 | ) |
| | Impairment of other assets | | | — | | | | — | | | | — | | | | (600 | ) | | | — | |
| | Gain (loss) on sale of assets | | | 2,824 | | | | 20 | | | | (34 | ) | | | 5,128 | | | | 2,780 | |
| | Other, net | | | 170 | | | | 129 | | | | 104 | | | | 1 | | | | 176 | |
| Income (loss) before income taxes | | | (4,633 | ) | | | (9,925 | ) | | | (2,701 | ) | | | 4,130 | | | | 2,477 | |
| Income tax (expense) benefit | | | — | | | | — | | | | 1,144 | | | | (1,590 | ) | | | (710 | ) |
| | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | (4,633 | ) | | $ | (9,925 | ) | | $ | (1,557 | ) | | $ | 2,540 | | | $ | 1,767 | |
| | | | | | | | | | | | | | | | |
| Basic income (loss) per common share | | $ | (0.49 | ) | | $ | (1.23 | ) | | $ | (0.22 | ) | | $ | 0.39 | | | $ | 0.29 | |
| Diluted income (loss) per common share | | | (0.49 | ) | | | (1.23 | ) | | | (0.22 | ) | | | 0.37 | | | | 0.27 | |
Statement of Cash Flows Data | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | |
| | Operating activities | | $ | 5,463 | | | $ | 2,845 | | | $ | 136 | | | $ | 1,361 | | | $ | 1,157 | |
| | Investing activities | | | (9,942 | ) | | | (6,902 | ) | | | (16,218 | ) | | | (3,232 | ) | | | (715 | ) |
| | Financing activities | | | 6,804 | | | | 3,917 | | | | 16,283 | | | | 2,381 | | | | (1,003 | ) |
Balance Sheet Data | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 3,052 | | | $ | 727 | | | $ | 867 | | | $ | 666 | | | $ | 155 | |
| Accounts receivable, net of allowance | | | 3,493 | | | | 1,767 | | | | 1,514 | | | | 1,600 | | | | 1,488 | |
| Investment in securities | | | — | | | | — | | | | — | | | | — | | | | 8,509 | |
| Net property and equipment | | | 8,764 | | | | 10,044 | | | | 10,315 | | | | 10,343 | | | | 6,107 | |
| Net oil and gas properties | | | 44,387 | | | | 36,162 | | | | 32,284 | | | | 17,191 | | | | 8,127 | |
| Net intangible assets | | | 1,497 | | | | 3,953 | | | | 5,300 | | | | 1,527 | | | | 305 | |
| Total assets | | | 64,048 | | | | 55,266 | | | | 53,130 | | | | 33,097 | | | | 26,013 | |
| Current portion of long-term debt | | $ | 284 | | | $ | 1,763 | | | $ | 2,227 | | | $ | 3,342 | | | $ | 3,520 | |
| Accounts payable | | | 4,001 | | | | 2,645 | | | | 2,876 | | | | 2,591 | | | | 1,879 | |
| Long-term debt, net of current portion | | | 25,340 | | | | 26,230 | | | | 24,247 | | | | 10,421 | | | | 5,552 | |
| Stockholders’ equity | | | 28,822 | | | | 22,911 | | | | 22,810 | | | | 15,207 | | | | 13,596 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | For the Period Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | |
| | | (In thousands, except per share amounts) | |
| |
Statement of Operations Data | | | | | | | | | | | | | | | | | | | | |
| Revenue: | | | | | | | | | | | | | | | | | | | | |
| Oilfield service operations | | $ | 21,583 | | | $ | 14,721 | | | $ | 11,634 | | | $ | 8,570 | | | $ | 9,854 | |
| Exploration and production | | | 9,192 | | | | 6,267 | | | | 6,589 | | | | 2,368 | | | | 1,759 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total revenue | | | 30,775 | | | | 20,988 | | | | 18,223 | | | | 10,938 | | | | 11,613 | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Oilfield service operations | | | 10,769 | | | | 7,890 | | | | 6,222 | | | | 4,621 | | | | 5,154 | |
| Oil and gas production expense | | | 3,548 | | | | 1,914 | | | | 2,162 | | | | 1,583 | | | | 1,074 | |
| Production taxes | | | 877 | | | | 722 | | | | 759 | | | | 238 | | | | 66 | |
| General and administrative expenses | | | 5,836 | | | | 5,462 | | | | 5,311 | | | | 4,647 | | | | 2,789 | |
| Depreciation, depletion and amortization | | | 7,451 | | | | 5,198 | | | | 3,074 | | | | 1,783 | | | | 1,063 | |
| Ceiling write-down of oil and gas properties | | | 13,450 | | | | 4,100 | | | | 2,975 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total expenses | | | 41,931 | | | | 25,286 | | | | 20,503 | | | | 12,872 | | | | 10,146 | |
| | | | | | | | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | | | | | | | |
| Financing costs | | | (4,828 | ) | | | (3,329 | ) | | | (7,795 | ) | | | (837 | ) | | | (1,866 | ) |
| Change in derivative fair value | | | 2,908 | | | | — | | | | — | | | | — | | | | — | |
| Gain (loss) on sale of assets | | | (96 | ) | | | 2,824 | | | | 20 | | | | (34 | ) | | | 5,128 | |
| Other, net | | | (405 | ) | | | 170 | | | | 130 | | | | 104 | | | | (599 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income (loss) before income taxes | | | (13,577 | ) | | | (4,633 | ) | | | (9,925 | ) | | | (2,701 | ) | | | 4,130 | |
| Income tax (expense) benefit | | | — | | | | — | | | | — | | | | 1,144 | | | | (1,590 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | (13,577 | ) | | $ | (4,633 | ) | | $ | (9,925 | ) | | $ | (1,557 | ) | | $ | 2,540 | |
| | | | | | | | | | | | | | | | | | | | | |
| Basic income (loss) per common share | | $ | (1.05 | ) | | $ | (0.49 | ) | | $ | (1.23 | ) | | $ | (0.22 | ) | | $ | 0.39 | |
| Diluted income (loss) per common share | | | (1.05 | ) | | | (0.49 | ) | | | (1.23 | ) | | | (0.22 | ) | | | 0.37 | |
Statement of Cash Flows Data | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 9,650 | | | $ | 5,463 | | | $ | 2,845 | | | $ | 136 | | | $ | 1,361 | |
| Investing activities | | | (42,454 | ) | | | (9,942 | ) | | | (6,902 | ) | | | (16,218 | ) | | | (3,232 | ) |
| Financing activities | | | 37,694 | | | | 6,804 | | | | 3,917 | | | | 16,283 | | | | 2,381 | |
Balance Sheet Data | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 7,942 | | | $ | 3,052 | | | $ | 727 | | | $ | 867 | | | $ | 666 | |
| Accounts receivable, net of allowance | | | 4,748 | | | | 3,494 | | | | 1,767 | | | | 1,514 | | | | 1,600 | |
| Net property and equipment | | | 11,489 | | | | 8,764 | | | | 10,044 | | | | 10,315 | | | | 10,343 | |
| Net oil and gas properties | | | 66,548 | | | | 44,387 | | | | 36,162 | | | | 32,284 | | | | 17,191 | |
| Net intangible assets | | | 2,514 | | | | 1,497 | | | | 3,953 | | | | 5,300 | | | | 1,527 | |
| Total assets | | | 94,284 | | | | 64,048 | | | | 55,266 | | | | 53,130 | | | | 33,097 | |
| Note payable and current portion of long-term debt | | | 288 | | | | 284 | | | | 1,763 | | | | 2,227 | | | | 3,342 | |
| Accounts payable | | | 5,035 | | | | 4,001 | | | | 2,645 | | | | 2,876 | | | | 2,591 | |
| Accrued liabilities | | | 6,314 | | | | 4,497 | | | | 967 | | | | 890 | | | | 391 | |
| Long-term debt, net of current portion | | | 39,874 | | | | 25,340 | | | | 26,230 | | | | 24,247 | | | | 10,421 | |
| Derivative liabilities | | | 9,837 | | | | — | | | | — | | | | — | | | | — | |
| Stockholders’ equity | | | 30,217 | | | | 28,822 | | | | 22,911 | | | | 22,810 | | | | 15,207 | |
30
32
| |
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Effective September 9, 2005, Infinity, Inc. merged with and into its wholly-owned subsidiary Infinity Energy Resources, Inc., a Delaware corporation, for the purpose of changing its domicile from Colorado to Delaware. As a result of the merger, the legal domicile of Infinity, Inc. was changed to Delaware and its name was changed to Infinity Energy Resources, Inc. At the effective time of the merger, shares of Infinity, Inc. were converted into an equal number of shares of common stock of Infinity Energy Resources, Inc. The reincorporation did not result in any change in headquarters, business, jobs, location of any facilities, number of employees, assets, liabilities, or net worth. Management, including all directors and officers, remain the same as prior to the reincorporation.
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, Infinity-Wyoming and Consolidated are engaged in identifying and acquiring oil and gas acreage, exploring and developing acquired acreage, oil and gas production, and providing oilfield services. Infinity’s primary focuses are on: (i) the acquisition, exploration and development of and production from its properties in the Fort Worth Basin of North Centralnorth central Texas and Greater Green River, Sand Wash and Piceance Basins of Southwestsouthwest Wyoming and Northwestnorthwest Colorado; and (ii) providing oilfield services in the Mid-Continent region and the Powder River Basin of Northeastnortheast Wyoming. 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 subject to consummation of the long-term explorationdevelopment and production contract governing such activity.
Overview of Oil and Gas Exploration and Production Activity
Infinity, through Infinity-Texas, expanded its exploration and production operations into the Fort Worth Basin of Texas during the year ended December 31, 2004.2005. Successful exploratory drilling during 2005 increased Infinity-Texas’ reserves to 6.7 Bcfe at December 31, 2005. As such, Infinity expects increased natural gas production from Infinity-Texas during 2006 as compared to 2005. The opportunity to operate in Texas was attractive to Infinity due to year-round access to exploration and development locations, ease of permitting, better weather, and less restrictive government and environmental laws and regulations. In addition, early results for other operators in the Fort Worth Basin were encouraging to Infinity-Texas, and its minority joint interest partners, who were experienced in other successful parts of the basin. Meanwhile, Infinity-Wyoming continued to explore and develop the various projects and prospects in the Rocky Mountains, but wascontinues to be hampered by weather, governmental and environmental restrictions and regulations, as well as various operational issues at the Labarge, FieldPipeline and Pipeline Field. Infinity-Wyoming began initial exploration efforts for coalbed methane in the Sand Wash and Piceance Basins, and also commenced development drilling for oil at its Sand Wash Prospect.fields.
Infinity expects to continue to explore and develop its Fort Worth Basin acreage and its Rocky Mountain projects and prospects. Infinity expects its Rocky Mountain projects to proceed more slowly, due in part to governmental restrictions. In addition to reducing and refinancing indebtedness, Infinity raised incremental debt and equity and debt capital during 2004 (and early 2005) to fund its exploration operations from the net proceeds of the Senior Secured Notes Facility and production operations.from the proceeds of option and warrant exercises during 2005. In addition to expected increases in cash flows from operating activities, Infinity expects to be able to continue to raise capitalwill likely require external financing during 20052006 and beyond to fund its exploration and production operations, although the type, timing, cost and amounts of such financing, if any, will depend upon general energy and capital markets conditions and the success of the Company’sInfinity’s operations.
Infinity-Wyoming has selected
The Company engaged Netherland, Sewell and Associates, Inc. to prepare its December 31, 2005, 2004 and 2003 third party reserve evaluations. Results of these evaluations are disclosed in the “Supplemental Oil and Gas Disclosures” in Infinity’s Consolidated Financial ReportsStatements and in the “Oil and Natural Gas Reserves” section of Item 1. and Item 2. Business and Properties. Another engineering firm prepared
31
The following table provides statistical information for the reserve evaluationyears ended December 31, 2005, 2004 and 2003:
| | | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| |
Production: | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 875.5 | | | | 953.4 | | | | 1,080.5 | |
| Oil (thousands of barrels) | | | 68.5 | | | | 33.7 | | | | 57.7 | |
| Total (MMcfe) | | | 1,286.5 | | | | 1,155.4 | | | | 1,426.4 | |
Financial Data (in thousands): | | | | | | | | | | | | |
| Total revenue | | $ | 9,192.0 | | | $ | 6,267.5 | | | $ | 6,589.3 | |
| Production expenses | | | 3,547.8 | | | | 1,913.7 | | | | 2,161.7 | |
| Production taxes | | | 877.1 | | | | 722.2 | | | | 758.8 | |
Financial Data per Mcfe: | | | | | | | | | | | | |
| Total revenue | | $ | 7.14 | | | $ | 5.42 | | | $ | 4.62 | |
| Production expenses | | | 2.76 | | | | 1.66 | | | | 1.52 | |
| Production taxes | | | 0.68 | | | | 0.63 | | | | 0.53 | |
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. At December 31, 2002.2005, the carrying value of the Company’s oil and gas properties 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. In 2004 and 2003, the Company also recorded ceiling writedowns of $4,100,000 and $2,975,000, 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. Subsequent to December 31, 2005, oil prices have increased slightly, while natural gas prices have generally declined.
Overview of Oilfield Service Operations
Consolidated continued to develop its business relationships as the largest oilfield service provider in Easterneastern Kansas and Northeast Oklahoma by serving approximately 475 customers during 2004.northeast Oklahoma. The continued strong price of natural gas and crude oil and the focus on development of the coal bed methane
33
potential of the Cherokee basin in Easterneastern Kansas and Northeastnortheast Oklahoma and the Powder River Basin in northeastern Wyoming contributed to thean overall increase in activity for Consolidated. During 2004the year ended December 31, 2005, Consolidated achieved several operational milestones:
| | |
| | • | revenue of $14.7$21.6 million; |
| |
| | • | subsidiary level earnings before interest, taxes, depreciation and amortizationgross profit of approximately $6.5$10.8 million; |
| |
| | • | provided services to approximately 475more than 500 customers; and |
| |
| | • | subsidiary level income before taxes of approximately $4.7 million; and |
|
| • | the acquisition of a Kansas oilfield service provider and the divestiture of relatively low-margin assets and operations to a customer.$6.3 million |
During 2005 Consolidated is actively seekingexpanded its pressure-pumping fleet through the fabrication and construction of additional equipment. Consolidated also seeks opportunities, through acquisitions or mergers, to expand its service area increase its market share or enhance the services it provides to its customers.
32
The following table details gross revenue, before discounts, for the years ended December 31, 2005, 2004 and 2003, based on the number and type of core service jobs performed:
| | | | | | | | | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
Job Type | | Jobs | | Revenue | | | Jobs | | Revenue | | | Jobs | | Revenue | |
| | | | | | | | (Dollars in thousands) | | | | | | |
| |
| Cementing | | 3,445 | | $ | 10,890 | | | 3,059 | | $ | 8,213 | | | 1,955 | | $ | 4,801 | |
| Acidizing | | 1,899 | | | 1,960 | | | 1,260 | | | 1,403 | | | 1,201 | | | 1,431 | |
| Fracturing | | 1,303 | | | 9,556 | | | 790 | | | 5,992 | | | 1,015 | | | 6,108 | |
| Discounts | | | | | (823 | ) | | | | | (887 | ) | | | | | (706 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | | | $ | 21,583 | | | | | $ | 14,721 | | | | | $ | 11,634 | |
| | | | | | | | | | | | | | | | | | | |
2006 Operational and Financial Objectives
Exploration and Production
Infinity-Wyoming plans to focus on increasing production through development of acreage. Infinity-Wyoming anticipates 2006 capital expenditures will be approximately $1 million to complete 1 well in progress at December 31, 2005, 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 2006 capital expenditures will be approximately $40 million to drill between 18 and 20 wells, complete 1 well in progress at December 31, 2005, conduct additional geological and geophysical analysis on its acreage and acquire additional acreage. Through March 3, 2006, Infinity-Texas has vertically drilled one well, horizontally drilled three wells, and drilling is ongoing on a fourth horizontal well. Through such date two of the horizontal wells have been completed as producers and one horizontal well and the vertical well are waiting completion operations. Infinity-Texas may increase its capital expenditures and drilling activity through the contracting of a second drilling rig.
The Company’s ability to complete these activities is dependent on a number of factors including, but not limited to:
| | |
| Subsequent Events• | The availability of the capital resources required to fund the activity; |
|
| • | The availability of third party contractors for drilling rigs and completion services (although the Company has one rig under contract and operating in Texas during the first quarter of 2006); and |
|
| • | The approval by regulatory agencies of applications for permits to drill in a timely manner. |
Oilfield Services
Consolidated plans to increase its oilfield service revenue during 2006 as a result of the expansion of its fleet during 2005 and due to the expected increase in the number of wells to be drilled and completed by property owners in its service areas. Strategic acquisitions, if any, made in the future would be made in order to:
| | |
| Senior Secured Notes Facility• | expand the services that are provided; |
|
| • | expand the area that is serviced; and |
|
| • | gain market share by providing complementary services to Consolidated’s existing services. |
Revenue from oilfield services are expected to be approximately $28 million in 2006. Management believes that if it is able to identify strategic acquisitions during 2006, it would expect to fund any such acquisitions, which could individually cost up to $15 million, through external financings, which may include the issuance of subordinated debt or equity securities. Excluding acquisitions and related capital expenditures, Consolidated also expects capital expenditures to approximate $4 million in 2006 related to equipment and facilities. Management expects these capital expenditures to be financed through Consolidated’s cash flow from operations and cash on hand.
33
Corporate Activities
Infinity continues to negotiate the final development and production agreement with the Instituto Nicaraguense de Energia for the Perlas and Tyra blocks offshore Nicaragua. Management expects to execute a definitive contract during 2006. Upon execution, Infinity would be required to post a performance bond of less than $1 million for the initial work on the leases which will include an environmental study and the development of geological information from reprocessing and additional evaluation of existing2-D seismic data to be acquired.
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 revenue of $30.8 million in 2005 compared to $21.0 million in 2004. The $9.8 million, or 47%, increase in revenue consisted of a $6.9 million increase in oilfield service revenue and a $2.9 million increase in oil and gas revenue. The increase in oilfield service revenue was principally attributable to an increase in the number of jobs completed in 2005 compared to 2004, particularly fracturing jobs, which generate the highest per job revenue of the services provide by Consolidated. 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.
Cost of Revenue
Infinity’s cost of revenue increased to $15.2 million in 2005, from $10.5 million in 2004. Oilfield service costs increased to $10.8 million during 2005, from $7.9 million in the prior year. The increase was principally attributable to increased materials, maintenance, fuel and labor costs resulting largely from the increase in the number of jobs performed in 2005 compared to 2004. 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. 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.
Gross Profit
Infinity earned a gross profit of $15.6 million during 2005, a $5.1 million or 49% increase from $10.5 million gross profit in the prior year. Gross profit from oilfield services was $10.8 million, or 50% of oilfield services revenue, during 2005, compared to $6.8 million, or 46% of oilfield services revenue, in the prior year. The improvement in gross profit as a percentage of revenue was due principally to increased utilization of personnel and equipment during 2005. Gross profit from oil and gas operations for 2005 increased to $4.8 million from $3.6 million in 2004 primarily as a result of increased revenue as discussed above.
General and Administrative Expenses
General and administrative expenses increased slightly to $5.8 million for 2005, from $5.5 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.
34
Depreciation, Depletion, Amortization and Accretion
Infinity recognized depreciation, depletion, amortization and accretion (“DD&A”) expense of approximately $7.5 million during 2005, an increase of approximately $2.3 million compared to DD&A expense of approximately $5.2 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, increased oil and gas production and increased investment in Consolidated’s fleet.
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.
Other Income (Expense)
Other income and expense was a net expense of $2.4 million in 2005 compared to a net expense of $0.3 million in the prior year. The change of $2.1 million was principally due to (i) a $1.3 million increase in interest expense due to an increase in average debt outstanding and higher average interest rates during 2005, (ii) $0.9 million of additional early extinguishment of debt expense resulting from additional debt retired during 2005, (iii) an impairment of approximately $0.4 million related to the sale of a note receivable in 2005, and (iv) decreases in gains on sales of assets of approximately $2.9 million related to gains recognized in 2004 primarily in connection with the sale of certain oilfield services assets in September 2004, partially offset by a $0.7 million decrease in amortization costs resulting from loan costs written off in connection with debt retirement in 2005 and $2.9 million income resulting from the decrease in the fair value of derivative liabilities (see Note 7 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 9 of the consolidated financial statements.
Results of operations for the year ended December 31, 2004 compared to the year ended December 31, 2003
Net Loss
Infinity incurred a net loss after taxes of $4.6 million, or $0.49 per diluted share, in 2004 compared to a net loss after taxes of $9.9 million, or $1.23 per diluted share, in 2003. The change between periods was the result of the items discussed below.
Revenue
Infinity achieved total revenue of $21.0 million in 2004 compared to $18.2 million in 2003. The $2.8 million increase in revenue was attributable to a $3.1 million increase in oilfield service revenue, partially offset by a $0.3 million decrease in oil and gas production revenue. The increase in oilfield services revenue was primarily due to the acquisition of a pressure-pumping business located in Eureka, Kansas in April 2004. The decrease in oil and gas production revenue was primarily due to a decrease in production volumes during 2004 as compared to 2003.
35
Cost of Revenue
Infinity’s cost of revenue increased to $10.5 million in 2004, from $9.1 million in 2003. Oilfield service costs increased to $7.9 million during 2004, from $6.2 million in the prior year. The increase was principally attributable to increased materials, maintenance, fuel and labor costs resulting largely from the increase in the number of jobs performed in 2004 compared to 2003. Oil and gas production expenses decreased to $1.9 million during 2004, from $2.2 million in the prior year. The decrease in production expenses was attributable to the 19% decrease in equivalent production in 2004 compared to the prior year. Oil and gas production taxes for 2004 decreased to $0.7 million from $0.8 million in 2003 as a result of the decrease in equivalent production discussed above, partially offset by increased commodity price realizations in 2004.
Gross Profit
Infinity earned a gross profit of $10.5 million during 2004, a $1.4 million or 15% increase from $9.1 million gross profit in the prior year. Gross profit from oilfield services was $6.8 million, or 46% of oilfield services revenue, during 2004, compared to $5.4 million, or 47% of oilfield services revenue, in the prior year. Gross profit from oil and gas operations for 2004 decreased slightly to $3.6 million from $3.7 million in 2003 primarily as a result of decreased production expenses as discussed above.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2004 increased $0.2 million from $5.3 million in 2003 to $5.5 million in 2004. In 2003, Infinity incurred approximately $0.6 million in expenses associated with detailed negotiations relating to a potential merger and the process leading up to negotiations in which Infinity solicited and reviewed strategic alternatives. The increase between years was primarily due to increased personnel and related personnel costs.
Depreciation, Depletion, Amortization and Accretion
Infinity recognized additional DD&A expense of approximately $2.1 million during 2004, an increase to approximately $5.2 million compared to DD&A expense of approximately $3.1 million for 2003. The increase in DD&A expense was due to the increase in the depletion rate on and increased investment in oil and gas producing properties and the increase in the investment in Consolidated’s fleet in 2004.
Ceiling Write Down
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. During 2003, the Company recorded a ceiling writedown of $2,975,000 as a result of significant revisions to its December 31, 2003 year end reserves and other economic decisions made by the Company.
Other Income (Expense)
Other income and expense was a net expense of $0.3 million in 2004 compared to a net expense of $7.6 million in the prior year. The change of $7.3 million was principally due to (i) the recognition in 2003 of $5.6 million of amortization of loan costs associated with the value of warrants and options granted in conjunction with obtaining new debt financing and the amortization of $0.6 million of cash loan costs paid when those same loans were obtained, compared to $2.1 million of amortization of loan costs in 2004, and (ii) a $0.3 million decrease in interest expense in 2004 compared to 2003 due to a decrease in average debt outstanding, lower interest rates on certain indebtedness and an increase in interest capitalized to undeveloped properties.
36
Income Tax
Infinity reflected no net tax benefit or expense in 2004 and 2003. 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, 2004 and 2003, the Company recorded a full valuation allowance for its net deferred tax asset.
Liquidity and Capital Resources
Infinity’s primary sources of liquidity are cash provided by operations and debt and equity financing. Infinity’s primary needs for cash are for the operation, development, production, exploration and acquisition of oil and gas properties, for fulfillment of working capital obligations, and for the operation and development of the oilfield service business.
As of December 31, 2005, the Company had working capital of $1.6 million, compared to a working capital of $0.3 million at December 31, 2004. The $1.3 million increase in working capital is largely the result of cash provided by operations (prior to changes in working capital components) during 2005 of $7.2 million, and cash provided by financing activities of $37.7 million, partially offset by cash used in investing activities of $43.7 million, adjusted for the proceeds from a note receivable that was included in working capital at December 31, 2004.
During the year ended December 31, 2005, cash provided by operating activities was $9.7 million, compared to $5.5 million in 2004. The increase in cash provided by operating activities of $4.2 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 2005, Infinity used $42.5 million in investing activities, compared to $9.9 million used in 2004. The increase in cash used in investing activities of $32.6 million was primarily attributable to a $27.6 million increase in exploration and production capital expenditures related to the Company’s exploration and development program, a $3.0 million increase in oilfield services capital expenditures and a $4.6 million decrease in proceeds from the sale of assets, partially offset by a decrease of $1.4 million in oilfield services and exploration and production acquisition costs and proceeds of $1.2 million related to the Company’s sale of a note receivable in 2005.
During 2005, cash provided by financing activities was $37.7 million, compared to $6.8 million provided by financing activities during 2004. The increase in cash provided by financing activities of $30.9 million was principally due to an increase of $39.2 million in debt proceeds related to the net cash proceeds provided by the sale of $45.0 million of Senior Secured Notes, discussed below, partially offset by a $5.0 million decrease in proceeds from the sale of common stock and exercise of options and warrants during 2005, increased debt and equity issuance costs of $2.4 million and increased debt repayments of $1.3 million.
On January 13, 2005, weInfinity entered into a securities purchase agreement (the “Senior Secured Notes Facility”) with affiliates of Promethean Asset Management, LLC and Angelo, Gordon & Co., L.P. (collectively, the “Buyers”), pursuant to which Infinity sold and the Buyers purchased $30 million aggregate principal amount of senior secured notes (the “Notes”“Initial Notes”) due January 13, 2009 and five-year warrants to purchase 924,194 shares of the Company’s common stock at an exercise price of $9.09 per share and 732,046 shares of the Company’s common stock at an exercise price of $11.06 per share (collectively, the “Warrants”).share. The Initial Notes have an initial maturity of 48 months subject to extension for an additional twelve months upon the mutual agreement of Infinity and the Buyers.holders. Pursuant to the terms of the Senior Secured Notes Facility, on September 7, 2005 and December 9, 2005, the Company sold $9.5 million and $5.5 million, respectively, of additional principal amount of senior secured notes (the “Additional Notes” and together with the Initial Notes, the “Notes”) due March 7, 2009 and June 9, 2009, respectively, and five-year warrants to purchase 283,051 shares, 224,202 shares, 191,882 shares and 151,988 shares of the Company’s common stock at exercise prices of $9.40 per share, $11.44 per share, $8.03 per share and $9.77 per share, respectively. The Additional Notes have initial maturities of 42 months (54 months if the maturity of the Initial Notes is extended). The Notes bear interest at the3-month LIBOR (London Interbank Offered Rate) plus 675 basis points, adjusted the first business day of each calendar quarter. quarter (11.23% at December 31, 2005).
The Notes are secured by essentially all of the assets of Infinity and its subsidiaries and are guaranteed by each of Infinity’s active subsidiaries. The Notes are redeemable by Infinity for cash at any time during the first year at 105% of par value, declining by 1% per year thereafter (101% during any extended maturity period), together with
37
any accrued and unpaid interest. Under certain circumstances, Infinity has the option to repay the Notes with direct issuances of shares of registered common stock in lieu of cash.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 accordance with terms of the Senior Secured Notes Facility, in January 2006, the Company elected to settle approximately $861,000 of interest due January 3, 2006 through the issuance of 126,084 shares of common stock. In addition, also in accordance with terms of the Senior Secured Notes Facility, in 2006, through March 3, 2006, the Company had converted $3 million principal amount of Notes, along with accrued interest of $37,000, into 382,062 shares of common stock.
At
Under certain circumstances at quarterly intervals and over a three-yearthree year period, commencing in the third quarter of 2005, Infinity has the option to sell additional notes (the “Additional Notes”),Notes, along with additional warrants,Warrants, in amounts of up to $15 million in any rolling twelve-month period, and up to a maximum of $45an additional $30 million. The Additionaladditional Notes would have an initial maturity of 42 months (54 months if the maturity of the Initial Notes is extended). The issuance of Additionaladditional Notes is subject to Infinity’s future satisfaction of various closing conditions. The ability to issue Additionaladditional Notes or the requirement to prepay Notes prior to maturity will depend upon a maximum Notes balance calculated quarterly based generally upon a combination of financial performance of Consolidated and (ii) the SEC after-taxPV-10% value of ourthe Company’s proved reserves. The maximum Notes balance at December 31, 2005 exceeded the Notes outstanding on that date.
Infinity used approximately $9.2
During the first quarter of 2005, all $2.5 million of the proceeds from the sale of Notes and Warrants to repay all amounts outstanding pursuant to a Loan and Security Agreement between LaSalle Bank N.A. and Consolidated, a Credit Agreement between U.S. Bank National Association and Infinity-Wyoming, and certain other secured lending agreements, and those credit agreements have been terminated. Infinity is using the remainder of the proceeds to pay costs and expenses related to the sale of the Notes and Warrants and to fund its oil and gas exploration and development activities.
| |
| Acquisition of Additional Acreage in the Fort Worth Basin |
In February 2005, we entered into a definitive agreement for the acquisition of approximately 24,500 gross and net acres in Comanche County in the Fort Worth Basin of Texas, subject to customary closing conditions. The agreement, as amended, also provides for a right of first refusal on all acres acquired by
34
the seller in Comanche County. We expect to close the Comanche transaction on or before April 19, 2005. Upon closing, including acreage previously owned, Infinity-Texas will own and operate approximately 67,500 gross acres (approximately 56,300��acres net to Infinity’s interest) of leasehold in Erath, Hamilton and Comanche Counties, Texas. We believe the Comanche County acreage offers prospective vertical and horizontal drilling and production opportunities, targeting the Barnett Shale and Lower Marble Falls formations. The leased properties are located approximately 30 miles southwest of Infinity-Texas’ existing acreage in Erath and Hamilton Counties, Texas. Infinity-Texas agreed to drill at least one test well on the Comanche acreage during the next twelve months.
| |
| Redemption of All Subordinated Convertible Debt |
Pursuant to requirements of the Senior Secured Notes Facility, on January 13, 2005, Infinity called for redemption the remaining $2.5 million ofCompany’s 8% Subordinated Convertible Notes due 2006 outstanding on February 28, 2005. During January and February 2005, the holdersas of all of the 8% subordinated convertible notes converted the debtDecember 31, 2004, and accrued interest on those notes, were converted in their entirety into 517,296 shares of the Company’s common stock.
Based on During the volume weighted average stock price for Infinity’s common stock from February 18,first and second quarters of 2005, to February 24, 2005 and pursuant to requirementsan aggregate of $11.5 million of the Senior Secured Notes Facility, on February 25, 2005, Infinity called for redemption the remaining $8.2 million ofCompany’s 7% Subordinated Convertible Notes due 2007 outstanding on April 22, 2005 at a redemption price of 102.8% plus accrued and unpaid interest. During 2005, through March 23, the holders of $5,950,538 of 7% subordinated convertible notes have converted the debt and accrued interest into 783,779 shares of the Company’s common stock. Approximately $5.6 million of principal amount remains outstanding as of March 23, 2005. The Company has cash on deposit in excess of the amount outstanding at March 23, 2005, should the remaining 7% notes not be presented for conversion prior to the redemption date.
| |
| 2005 Operational and Financial Objectives |
| |
| Exploration and Production |
Infinity-Wyoming plans to focus on increasing production through development of acreage. Infinity-Wyoming anticipates capital expenditures will be approximately $10 million to drill approximately eight wells, and complete four wells in progress at December 31, 2004, and conduct additional geological and geophysical analysis on its acreage positions.
Infinity-Texas will focus on increasing its acreage position and commencing production in the Fort Worth Basin of central Texas. Infinity-Texas anticipates its capital expenditures will be approximately $30 million to acquire additional acreage, drill approximately fifteen wells, complete three wells in progress at December 31, 2004, and conduct additional geological and geophysical analysis on its acreage positions.
The ability of Infinity-Wyoming and Infinity-Texas 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. Infinity-Wyoming expects to generate approximately $4 million in cash flow from operations in 2005. Infinity-Texas expects to generate cash flow from operations in 2005 subsequent to the hook up of its initial wells in the Fort Worth basin; however management is currently unable to predict with accuracy an estimate of this amount; |
|
| • | The availability of third party contractors for drilling rigs and completion services; |
|
| • | The completion of environmental studies by the Bureau of Land Management covering federal acreage in the Pipeline and Labarge fields; and |
|
| • | The approval by regulatory agencies of applications for permits to drill in a timely manner. |
35
Consolidated expects to increase its oilfield service revenue during 2005 due to the increase in the number of wells being drilled and completed by property owners in our service areas and through strategic acquisitions. These acquisitions would be done in order to:
| | |
| • | expand the services that are provided; |
|
| • | expand the area that is serviced; and |
|
| • | gain market share by providing complementary services to our existing services. |
Revenues from oilfield services are expected to be between $14 million and $15 million. Management expects that it could make acquisitions that will cost between $10 million and $20 million during 2005 and expects to fund the acquisitions through the issuance of subordinated debt or common stock. Excluding acquisitions and related capital expenditures, Consolidated also expects to have capital expenditures of about $2 million related to equipment and facilities. These capital expenditures would be financed through cash flow and cash on hand.
Infinity continues to negotiate the final exploration and production agreement with INE for the Perlas and Tyra blocks offshore Nicaragua. Management expects to complete the negotiations and execute the agreement in 2005. Upon execution, Infinity would be required to post a performance bond of approximately $0.7 million for the initial work on the leases which will include an environmental study and the development of geological information developed from additional seismic evaluation. Infinity expects to incur additional costs to complete the negotiations and finalize the leases of approximately $0.1 million.
| |
| Results of operations for the year ended December 31, 2004 compared to the year ended December 31, 2003 |
Infinity incurred a net loss after taxes of $4.6 million, or $0.49 per diluted share, in 2004 compared to a net loss after taxes of $9.9 million, or $1.23 per diluted share, in 2003.
Infinity achieved total revenue of $21.0 million in 2004 compared to $18.2 million in 2003. The $2.8 million increase in revenue was attributable to a $3.1 million increase in oilfield service operations, partially offset by a $0.3 million decrease in oil and gas production revenue. Infinity earned a gross profit of $10.5 million during 2004, a $1.4 million, or 15% increase in gross profit from $9.1 million in 2003. Gross profit from exploration and production was $3.6 million during both 2004 and 2003.
General and administrative expenses for the year ended December 31, 2004 increased $0.2 million from $5.3 million in 2003 to $5.5 million in 2004. In 2003, Infinity incurred approximately $0.6 million in expenses associated with the detailed negotiations relating to a potential merger and the process leading up to negotiations in which Infinity solicited and reviewed strategic alternatives. Infinity and its subsidiaries also recognized additional depreciation, depletion and amortization (“DD&A”) expense of approximately $2.1 million during 2004, an increase to approximately $5.2 million compared to DD&A of approximately $3.1 million for 2003. The increase in DD&A was due to the increase in the depletion rate on and increased investment in oil and gas producing properties and the increase in the investment in Consolidated’s fleet in 2004. During 2004, Infinity-Wyoming also recognized a $4.1 million ceiling write-down of its oil and gas properties based on the full cost ceiling test for oil and gas properties subject to depletion, as compared to $3.0 million in 2003. As a result, Infinity recognized an operating loss of $4.3 million for 2004, compared to an operating loss of $2.3 million for 2003.
Interest expense and finance charges and amortization of loan costs decreased by $4.5 million to $3.3 million for 2004 compared to $7.8 million for 2003. The decrease was primarily due to the recognition in 2003 of $5.6 million of amortization of loan costs associated with the value of warrants and options granted in conjunction with obtaining new debt financing and the amortization of $0.6 million of cash loan costs paid when those same loans were obtained, compared to $2.1 million of amortization of loan costs in 2004. Infinity
36
also experienced a $0.3 million decrease in interest expense in 2004 compared to 2003 due to a decrease in average debt outstanding, lower interest rates on certain indebtedness and an increase in interest capitalized to undeveloped properties.
| |
| Exploration and Production |
The following table provides statistical information for the year ended December 31, 2004, 2003 and 2002 (due to rounding and other operating expenses the sum of the individual amounts presented may not equal the totals):
| | | | | | | | | | | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
Production: | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 953.4 | | | | 1,080.5 | | | | 676.9 | |
| Oil (thousands of barrels) | | | 33.7 | | | | 57.7 | | | | 53.1 | |
| Total (MMcfe) | | | 1,155.4 | | | | 1,426.4 | | | | 995.6 | |
Financial Data (in thousands): | | | | | | | | | | | | |
| Total revenue | | $ | 6,267.5 | | | $ | 6,589.3 | | | $ | 2,367.7 | |
| Production expenses | | | 1,913.7 | | | | 2,161.7 | | | | 1,582.8 | |
| Production taxes | | | 722.2 | | | | 758.8 | | | | 237.9 | |
Financial Data per Mcfe: | | | | | | | | | | | | |
| Total revenue | | | $5.42 | | | $ | 4.62 | | | $ | 2.38 | |
| Production expenses | | | 1.66 | | | | 1.52 | | | | 1.59 | |
| Production taxes | | | 0.63 | | | | 0.53 | | | | 0.24 | |
During 2004, Infinity-Wyoming recorded approximately $1.4 million in revenue on the sale of 33,668 barrels of oil, (201,828 Mcfe) and approximately $4.9 million in revenue on gas sales of 953,428 Mcf from its Pipeline and Labarge projects. Infinity-Wyoming incurred $1.9 million in oil and gas production expenses and $0.7 million in production taxes to produce oil and gas during the year ended December 31, 2004. The total production expenses and production taxes of approximately $2.6 million equate to approximately $2.28 in lifting costs on total production of 1,155,436 Mcfe. The 19% decrease in equivalent production in 2004 as compared to 2003 was primarily a result natural declines in production rates for wells in the Pipeline field.
Infinity-Wyoming also incurred $0.7 million in general and administrative costs and $3.6 million in DD&A expense, or depletion expense of $3.06 per Mcf equivalent for 2004 compared to $0.92 per Mcf equivalent for 2003. DD&A costs for 2004 increased by $2.1 million due to the increased depletion rate associated with the increased investment in developed oil and gas properties without a corresponding increase in proved reserve quantities. The higher depletion rate in 2004 was partially offset by lower oil and gas production in 2004 compared to 2003.
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 un-escalated 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. Infinity-Wyoming is also required to evaluate the value of its unproved oil and gas properties and adjust the value to the lower of the cost or market value of the properties.
At December 31, 2004, the carrying amount of oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $8.9 million based upon a natural gas price of approximately $6.07 per Mcf and an oil price of approximately $40.25 per barrel in effect at that date. However, due to significant 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, Infinity was required to record a ceiling writedown of $4.1 million in the quarter and year ended December 31, 2004. In 2003, the Company recorded a ceiling writedown of approximately $3.0 million.
37
During 2003 Infinity recorded $1.8 million in revenue on the sale of 57,654 barrels of oil, (345,924 Mcf equivalent) and $4.8 million in revenue on the sale of 1,080,456 Mcf of natural gas from its Pipeline and Labarge projects. Infinity-Wyoming incurred approximately $2.2 million in production expenses and $0.8 million in production taxes to produce the oil and gas during 2003. The total production expenses and production taxes of approximately $2.9 million equate to $2.05 in lifting costs on total Mcf equivalents of 1,426,380. Infinity-Wyoming also incurred approximately $0.8 million in general and administrative costs and $1.6 million in DD&A expense.
Sales for 2004 increased 27% to $14.7 million from $11.6 million in 2003. Sales of cementing services increased by approximately $1.7 million due to the acquisition of Blue Star Acid Services in April 2004 and by approximately $0.7 million due to an increase of 200 jobs at the Gillette, Wyoming camp. In 2004, the Chanute, Kansas camp cemented an additional 160 wells and generated an additional $0.7 million in revenue compared to its 2003 activity, prior to its sale in September 2004. The following table details the increase in gross revenue in millions of dollars, before discounts and inter-company eliminations, for the years shown, based on the number and type of core service jobs performed (due to rounding the sum of the individual amounts presented may not equal the totals):
Oilfield Service Statistics
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | | 2003 | | | Change | |
| | | | | | | | | | |
| Job Type | | Jobs | | | Revenue | | | Jobs | | | Revenue | | | Jobs | | | Revenue | |
| | | | | | | | | | | | | | | | | | | |
| | | ($ in millions, before discounts) | |
| Cementing | | | 3,059 | | | $ | 8.2 | | | | 1,955 | | | $ | 4.8 | | | | 1,104 | | | $ | 3.4 | |
| Acidizing | | | 1,260 | | | | 1.4 | | | | 1,201 | | | | 1.4 | | | | 59 | | | | — | |
| Fracturing | | | 790 | | | | 6.0 | | | | 1,015 | | | | 6.1 | | | | (225 | ) | | | (0.1 | ) |
| Discounts and eliminations | | | | | | | (0.9 | ) | | | | | | | (0.7 | ) | | | | | | | (0.2 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | $ | 14.7 | | | | | | | $ | 11.6 | | | | | | | $ | 3.1 | |
| | | | | | | | | | | | | | | | | | | |
The increase in the number of cementing jobs performed reflects the increase in the number of wells being drilled in Eastern Kansas and Northeast Oklahoma as well as in Northeast Wyoming. As well testing is completed on the newly drilled wells, completion and stimulation activities such as acidizing and fracturing should increase. Management believes that the increase in the number of wells cemented by Consolidated during the year and the continued high prices for oil and natural gas are good indicators of future increases in its acidizing and fracturing activities as well.
The additional activity also led to a 27% increase in the cost of goods sold of approximately $1.7 million. The increase in cost of goods sold was primarily due to the increase in materials of approximately $0.9 million, labor expense of approximately $0.4 million, and an increase in equipment operating costs and maintenance of approximately $0.4 million. General and administrative expenses for oilfield services of $2.8 million for 2004 was comparable to the same period in 2003.
Infinity and its subsidiaries incurred approximately $2.1 million in expenses associated with corporate activities during 2004 and 2003.
| |
| Other Income and Expenses |
Other income and expense was a net expense of $0.3 million for 2004 compared to $7.6 million for 2003. Infinity recognized a $4.5 million decrease in interest expense of which $4.2 million was associated with the amortization of financing costs. There was also a $0.3 million decrease in interest expense in 2004 compared to 2003 period due to a decrease in average debt outstanding, lower interest rates on certain indebtedness and an increase in the amount of interest capitalized to undeveloped properties.
38
Infinity reflected no net tax benefit or expense in 2004 and 2003. The net operating losses generated in 2004 and 2003 increased Infinity’s net deferred tax asset. Due to uncertainty as to the ultimate utilization of the net operating losses, the net deferred tax asset has been fully reserved by a valuation allowance as described in Note 11 of the consolidated financial statements.
| |
| Results of operations for the year ended December 31, 2003 compared to the year ended December 31, 2002 |
Infinity incurred a net loss after taxes of $9.9 million, or $1.23 per fully diluted share, in 2003 compared to a net loss after taxes of $1.6 million, or $0.22 per fully diluted share in 2002.
Infinity achieved a $4.6 million increase in gross profit to $9.1 million in 2003 from $4.5 million for 2002. The increase in gross profit during 2003 compared to 2002 was the result of a $3.0 million, or approximately 36%, increase in oilfield service revenue to $11.6 million from $8.6 million. The increase in revenue was partially offset by a $1.6 million, or 35%, increase in oilfield service cost of services provided (see “Oilfield Services” discussion below). Oilfield service revenue for 2002 was reduced by the elimination of $2.1 million of oilfield service sales that were provided to Infinity-Wyoming by Consolidated for the development of its oil and gas properties and the cost of services provided was reduced by $1.1 million for the cost of those services provided to Infinity-Wyoming. The oilfield service subsidiary provided minimal services to Infinity-Wyoming in 2003. Additionally, gross profit comparisons were affected by a $4.2 million, or approximately 178%, increase in sales of oil and gas from $2.4 million for 2002 to $6.6 million in 2003 with a corresponding increase of $0.6 million in oil and gas production costs and $0.5 million increase in production taxes in 2003 (see “Oil and Gas Production” discussion below).
General and administrative expenses for 2003 increased $0.7 million from $4.6 million in 2002 to $5.3 million in 2003. In 2003, Infinity incurred approximately $0.6 million in expenses associated with the detailed negotiations relating to a potential merger, which negotiations were terminated in April 2003, and the process leading up to those negotiations in which Infinity solicited and reviewed strategic alternatives. Infinity and its subsidiaries also recognized additional DD&A expense of approximately $1.3 million during 2003, an increase to approximately $3.1 million for the period compared to DD&A of approximately $1.8 million for 2002. The increase in DD&A was due to the increase in the investment in Consolidated’s fleet in 2002 and the increase in the depletion rate on the oil and gas producing properties. Infinity-Wyoming also recognized a $3.0 million ceiling write-down of its oil and gas properties based on the full cost ceiling test for oil and gas properties subject to depletion. As a result, Infinity recognized an operating loss of $2.3 million for 2003, compared to an operating loss of $1.9 million for 2002.
Interest expense and finance charges increased by $7.0 million to $7.8 million for 2003 compared to $0.8 million for 2002. The increase was primarily due to the recognition of $5.6 million of amortization of loan costs associated with the value of warrants and options granted in conjunction with obtaining debt financing and the amortization of $0.6 million of cash loan costs paid when those same loans were obtained. Infinity also experienced a $0.9 million increase in interest expense in 2003 period compared to 2002 due to the increase in debt outstanding, higher interest rates on certain notes issued in 2003 and a decrease in the amount of interest that was capitalized to undeveloped properties as Infinity experienced a period of development inactivity during a significant portion of 2003.
Infinity recognized a deferred income tax benefit of $1.1 million in 2002. The net operating losses generated in 2003 increased Infinity’s net deferred tax asset. Due to uncertainty as to the ultimate utilization of the net operating losses, the net deferred tax asset has been fully reserved by a valuation allowance as discussed in Note 11 of the consolidated financial statements. Therefore, Infinity has reflected no net tax expense or benefit for 2003.
39
| |
| Exploration and Production |
See the table above for statistical information for 2003 and 2002 (due to rounding and other operating expenses the sum of the individual amounts presented may not equal the totals).
During 2003, Infinity-Wyoming recorded approximately $1.8 million in revenue on the sale of 57,654 barrels of oil, (345,924 Mcf equivalents) and approximately $4.8 million in revenue on the gas sales of 1,080,456 Mcf from its Pipeline and Labarge projects. Infinity-Wyoming incurred $2.1 million in production expenses and $0.8 million in production taxes to produce the oil and gas during 2003. The total production expenses and production taxes of approximately $2.9 million equate to approximately $2.04 in lifting costs on total Mcf equivalents of 1,426,380. Infinity-Wyoming also incurred $0.8 million in general and administrative costs and $1.6 million in DD&A expense, or approximately $1.63 per Mcf equivalent for the period. The general and administrative expense included approximately $0.2 million in costs associated with the detailed negotiations relating to a potential merger, which negotiations were terminated in May 2003, and the process leading up to those negotiations in which Infinity solicited and reviewed strategic alternatives. Excluding these costs, general and administrative expenses for Infinity-Wyoming were unchanged when compared to the prior year period. DD&A costs for the period increased by $1.3 million due to the increased depletion rate associated with the investment in developed oil and gas properties. The higher rate was the result of the increase in oil and gas production and the decrease in the proved reserves from 2002 to 2003.
Infinity also recognized in 2003 a ceiling write-down of its oil and gas properties under the full cost ceiling test of approximately $3.0 million. Due to the limited availability of capital for development of its properties, the decision not to re-new a portion of Infinity-Wyoming’s leases during 2004, and the condemnation of leases due to geological and geophysical evaluation, Infinity-Wyoming re-classified approximately $5.0 million of its investment in oil and gas properties not subject to depletion to subject to amortization.
During 2002 Infinity-Wyoming recorded $0.9 million in revenue on the sale of 42,525 barrels of oil, (255,150 Mcf equivalent) and $1.3 million in revenue on the sale of 648,160 Mcf of natural gas from its Pipeline and Labarge projects. Infinity-Wyoming incurred approximately $1.1 million in lease operating expenses, $0.2 million in production taxes and $0.3 million in transportation fees to produce the oil and gas during 2002. The total production expenses and production taxes of approximately $1.6 million equate to $1.79 in lifting costs on total Mcf equivalents of 903,310. Infinity-Wyoming also incurred approximately $0.7 million in general and administrative costs and $0.2 million in DD&A expense, or approximately $1.00 per Mcf equivalent for the period.
The increase in production was primarily a result of the increased production time for wells in each period. Several wells began production in the third and fourth quarters of 2002. These wells produced for all of 2003 while producing for only a short period and at lower volumes during 2002.
Infinity-Kansas recorded net revenue of $0.2 million from its Kansas properties and operating expenses and production taxes of $0.2 million during 2002. Effective May 1, 2002 Infinity-Kansas sold its interest in the Owl Creek and Manson properties to West Central Oil, LLC for cash and a note receivable. Under the full cost method of accounting for oil and gas properties, Infinity and its subsidiaries did not recognize a gain or loss on the sale of its oil and gas properties since the sale did not have a material impact on the relationship between the oil and gas property values and the value of the reserves associated with those properties. Infinity reduced its investment in the remaining oil and gas properties by approximately $244,000 on the sale of the property.
During 2003, production, oil and gas prices, operating expenses and development expenditures for Infinity-Wyoming’s Labarge and Pipeline projects varied from those estimated in reserve reports at December 31, 2002 and additional geological, geophysical, and engineering data became available and was analyzed. Production at Labarge continued to be uneconomic, possibly due in part to down-hole operational problems. Quantities of proved oil and gas reserves as evaluated by Netherland Sewell and Associates at December 31, 2003 were substantially less than our previous estimates which in turn resulted in a higher depletion rate for the last part of 2003.
40
The 58% increase in production during 2003 combined with the significant reduction in proved reserves at January 1, 2004 resulted in a $1.2 million increase in depletion of developed oil and gas properties in 2003 compared to the 2002 period.
Infinity-Wyoming experienced a $0.3 million increase in administrative expenses in 2003 compared to 2002. This increase in administrative expense was primarily legal, accounting, and consulting fees associated with the detailed negotiations relating to a potential merger, which negotiations were terminated in May 2003, and the process leading up to those negotiations in which Infinity solicited and reviewed strategic alternatives.
Sales for 2003 increased to $11.6 million from $8.6 million, net of inter-company eliminations, in 2002. Infinity eliminated oilfield services sales of $2.1 million from revenues for sales of services to Infinity-Wyoming during 2002. There were no material inter-company sales in 2003. Sales of cementing services from Consolidated’s Bartlesville, Oklahoma camp increased by approximately $0.8 million and revenue from fracturing services from that camp increased by approximately $1.3 million in 2003 compared to 2002. The increase in revenue was primarily due to an increase in development activity during the second and third quarters of 2003 as customers moved from the evaluation of their prospects to the full scale development of their prospects in areas serviced from the Bartlesville facility. Revenue from cementing services provided from Consolidated’s Gillette, Wyoming facility increased by approximately $1.3 million, due to increased coalbed methane development activity in the Powder River Basin of Wyoming. Crews from the Gillette facility cemented over 400 wells in 2003 compared to 78 in 2002. The following table details the increase in gross revenue in millions of dollars, before discounts and inter-company eliminations, for the periods, based on the number and type of core service jobs performed (due to rounding the sum of the individual amounts presented may not equal the totals):
Oilfield Service Statistics
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003 | | | 2002 | | | Change | |
| | | | | | | | | | |
| Job Type | | Jobs | | | Revenue | | | Jobs | | | Revenue | | | Jobs | | | Revenue | |
| | | | | | | | | | | | | | | | | | | |
| | | ($ in millions, before discounts) | |
| Cementing | | | 1,955 | | | $ | 4.8 | | | | 1,454 | | | $ | 3.4 | | | | 501 | | | $ | 1.4 | |
| Acidizing | | | 1,201 | | | $ | 1.4 | | | | 1,029 | | | $ | 1.1 | | | | 172 | | | $ | 0.3 | |
| Fracturing | | | 1,015 | | | $ | 6.1 | | | | 1,015 | | | $ | 6.5 | | | | 0 | | | $ | (0.4 | ) |
| Discounts and eliminations | | | | | | | (0.7 | ) | | | | | | | (2.4 | ) | | | | | | | 1.7 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | $ | 11.6 | | | | | | | $ | 8.6 | | | | | | | $ | 3.0 | |
| | | | | | | | | | | | | | | | | | | |
The increase in the number of cementing jobs performed reflects the increase in the number of wells being drilled in Eastern Kansas and Northeast Oklahoma as well as in Wyoming. The additional activity also led to an increase in the cost of goods sold of approximately $1.6 million. The increase in cost of goods sold was primarily due to the increase in materials of approximately $0.7 million, labor expense of approximately $0.4 million, and an increase in equipment operating costs and maintenance of approximately $0.3 million. General and administrative expenses for oilfield services for 2003 were comparable to 2002.
Infinity and its subsidiaries incurred approximately $2.1 million in expenses associated with corporate activities during 2003 compared to approximately $1.9 million in 2002. Included in the $0.2 million increase was approximately $0.3 million in legal, accounting, and consulting fees associated with the detailed negotiations relating to a potential merger, which negotiations were terminated in May 2003, and the process leading up to those negotiations in which Infinity solicited and reviewed strategic alternatives.
41
| |
| Other Income and Expenses |
Other income and expense was a net expense of $7.6 million for 2003 compared to $0.8 million for 2002. Infinity recognized a $7.0 million increase in interest expense of which $6.0 million was associated with the amortization of financing costs. $5.4 million of the increase in amortization of loan costs related to options and warrants granted in conjunction with obtaining new debt financing and the remainder of the increase was related to cash loan costs paid when those same loans were obtained. There was also a $0.9 million increase in interest expense in 2003 compared to 2002 due to the increase in debt outstanding, higher interest rates on notes issued in 2003 and a decrease in the amount of interest that was capitalized to undeveloped properties as Infinity experienced a period of development inactivity during a significant portion of 2003.
Infinity recognized a deferred tax benefit of approximately $1.1 million in 2002. The net operating losses generated in 2003 increased Infinity’s net deferred tax asset. Due to uncertainty as to the ultimate utilization of the net operating losses, the net deferred tax asset has been fully reserved by a valuation allowance as described in Note 11 of the consolidated financial statements. Therefore, Infinity has reflected no net tax expense or benefit for 2003.
| |
| Liquidity and Capital Resources |
Infinity’s primary sources of liquidity are cash provided by operations and debt and equity financing. Infinity’s primary needs for cash are for the operation, development, production, exploration and acquisition of oil and gas properties, for fulfillment of working capital obligations, and for the operation and development through acquisitions of oilfield service businesses.
As of December 31, 2004, the Company had working capital of $0.3 million, compared to a working capital deficit of $2.2 million at December 31, 2003. Working capital increased by approximately $2.5 million due to an approximate $5.9 million increase in current assets due primarily to (i) a $2.3 million increase in cash; (ii) a $1.7 million increase in net accounts receivable; and (iii) an approximate $1.6 million increase in the current portion of a note receivable, offset by an approximate $3.4 million increase in current liabilities due to (i) a $1.5 million increase in accounts payable and (ii) a $3.5 million increase in accrued liabilities; offset by (iii) a $1.4 million decrease in current portion of long-term debt.
During the year ended December 31, 2004, cash provided by operating activities was $5.5 million, compared to $2.8 million in 2003. The increase in cash provided by operating activities of $2.7 million was primarily due to the $5.3 million decrease in net loss.
During 2004, Infinity used $9.9 million in investing activities, compared to $6.9 million used in 2003. The increase in cash used in investing activities of $3.0 million was primarily attributable to a $6.0 million increase in exploration and production capital expenditures and a $1.7 million increase in oilfield services capital expenditures, partially offset by a $4.6 million increase in proceeds of sale of fixed assets.
During 2004, Infinity financing activities provided $6.8 million, compared to $3.9 million from financing activities during 2003. The increase in cash provided by financing activities of $2.9 million was due to an $8.5 million increase in proceeds from equity issuances, net of issuance costs, offset by a $5.3 million decrease in proceeds from borrowings and a $0.3 million increase in debt repayments.
Effective June 13, 2001, Infinity sold $6,475,000 in 8% Subordinated Convertible Notes in a private placement. During the year ended December 31, 2004, $308,276 of the notes and interest accrued on those notes was converted into 63,179 shares of common stock, leaving an outstanding balance on the notes of $2,493,000 at December 31, 2004. The remaining notes and accrued interest were converted in their entirety by February 28, 2005 into 517,296 shares of the Company’s common stock.
Effective April 17, 2002, Infinity sold $12,540,000 in 7% Subordinated Convertible Notes in a private placement. Infinity issued $391,000 in additional notes for the payment of accrued interest due April 15, 2004 and $404,000 in additional notes for the payment of accrued interest due October 15, 2004. In addition, during
42
the year ended December 31, 2004, $487,472 of the notes and interest accrued on notes were converted into 62,685 shares of common stock, leaving an outstanding balance on the notes of $11,516,698 at December 31, 2004. During 2005, through March 23, the holders of $5,950,538 of 7% have converted the debt and accrued interest into 783,779aggregate 1,498,940 shares of the Company’s common stock. The remaining notes are currently subject to redemption by Infinitybalance of $38,000 plus accrued interest was paid in full on April 22, 2005 and the outstanding balance of the notes on March 23, 2005 was approximately $5.6 million. Infinity has cash available to redeem the remaining 7% notes should they not be presented for conversion prior to the redemption date.2005.
Effective November 25, 2002, Infinity issued $3,000,000 in notes to a stockholder. These notes were secured with a first or second priority security interest in certain gas properties and accrued interest at 7% per annum. On January 15, 2004, Infinity issued 125,000 shares of common stock valued at $4.00 per share and paid $750,000 in cash, as partial payment on the $3,000,000 bridge note.
As a result of the private placement of common stock on November 15, 2004, the note was repaid in full during November 2004.
In January 2002, Consolidated established a term loan collateralized by substantially all of its oilfield service equipment, a revolving line of credit secured by the eligible receivables of Consolidated and a $1.0 million capital expenditures line of credit with LaSalle Bank, N.A. (“LaSalle Bank”). Effective July 9, 2004, Consolidated borrowed $5.4 million under this facility. As a result of the13, 2005 closing of the Senior Secured Notes Facility, the indebtednessan aggregate of $8.6 million outstanding at December 31, 2004 under the LaSalle facilitytwo separate bank facilities was repaid in full on January 13, 2005.
In September 2003, Infinity-Wyoming established a Secured Revolving Borrowing Base Credit Facility with U.S. Bank National Association (“U.S. Bank”). The facility provided
Outlook for funding of up to $25.0 million, and the initial amount made available under the facility and drawn by the Company was $5.5 million. At December 31, 2004 $5.0 million of debt under the U.S. Bank facility is reflected as long-term debt as it was repaid using the long-term credit facility. As a result of the closing of the Senior Secured Notes Facility, the indebtedness under the U.S. Bank facility was repaid in full on January 13, 2005.2006
Infinity issued 1,000,000 shares of common stock in January 2004 in a private placement for which it received net proceeds after offering costs of approximately $3.9 million. The net proceeds of this offering, after making a $750,000 payment on notes, were used to pay costs associated with the completion of the Pipeline Field wells drilled in the fourth quarter of 2003, to pay for the Labarge Field well completion activities, and for working capital.
Infinity issued 1,027,000 shares of common stock in November 2004 in a private placement for which it received net proceeds after offering costs of approximately $4.9 million. The net proceeds of this offering, after making a $1,750,000 payment on notes, were used to pay costs associated with the initial drilling of the Fort Worth Basin wells drilled in the fourth quarter of 2004 and for working capital.
Depending on 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 $42$46 million during 2005. Capital2006. Approximate capital expenditures by operating entity wouldare anticipated to be approximately $30$40 million by Infinity-Texas; $10$1 million by Infinity-Wyoming; and $2$4 million by Consolidated.Consolidated 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.
Following the sale of the Senior Secured Notes and Warrants to Buyers in January 2005, Infinity used approximately $9.2 million of the proceeds to repay all amounts outstanding pursuant to the Loan and Security Agreement between LaSalle Bank N.A. and Consolidated, the Credit Agreement with U.S. Bank National Association and Infinity-Wyoming, and certain other secured lending agreements, and those credit agreements have been terminated. No principal on the Notes is due until 2009. Following the repayment of debt and transaction expenses of approximately $2.3 million, Infinity had approximately $18.5 million available for oil and gas exploration and development expenditures. In addition, at
At quarterly intervals and over a three year period, commencing in the third quarter of 2005, Infinity has the option under the Senior Secured Notes Facility to sell additional notes,Notes, along with warrants,additional Warrants, in amounts up to $15 million in any rolling twelve-month period.period, up to a maximum Notes balance of $75 million. The ability to issue
43
Additional additional Notes will depend upon a maximum Notesnotes balance calculated quarterly based generally upon a combination of financial performance of Consolidated and the SEC after-taxPV-10% value of our proved reserves. Management of the Company is of the opinion that it is reasonably likely that the Company will be eligible to sell $15 million in additionalThe maximum Notes and Warrants during the second half of 2005.
In January 2005, Infinity called for the redemption of the remaining 8% Subordinated Convertible Notes due 2006 outstanding on February 28, 2005. All $2.5 million outstanding on the 8% notes converted into common stock prior to the redemption date.
In February 2005, Infinity has called for redemption of the remaining 7% Subordinated Convertible Notes due 2007 outstanding on April 22, 2005. Approximately $5.6 million of principal remains outstandingbalance or Free Cash Flow Amount as of March 23, 2005. The Company has cash on deposit in excess of the amount outstanding at March 23,December 31, 2005 should the remaining 7% notes not be presented for conversion prior to the redemption date.was approximately $61 million.
Depending on the market price for crude oil and natural gas during 2005,2006, stabilized production levels from wells not yet placed on line during 2005 and 2006, and continued demand for and acceptance of our oilfield service operations in the geographic areas we serve,served by Consolidated, Infinity would expect to generate at least $10 millioncash flow from operating activities during 2005.2006 of between $15 million and $20 million.
Through March 23,
During 2005, Infinity has received approximately $4 million inrealized proceeds from the exercise of options and warrants. Management expects to receive proceeds from additional exercises during 2005, but is unable towarrants of approximately $5 million. Although it cannot predict with certainty the amount or timinglevel of such proceeds.activity in any given period, Infinity believes it can expect a similar level of activity in 2006.
In summary, Infinity believes that it will have approximately $47.5at least $37 million available to it in 2006 from working capital at December 31, 2005 from(approximately $1.6 million), external financing, including the net proceeds from thepotential sale of additional Notes ($18.5 million),under the sale of AdditionalSenior Secured Notes ($15.0 million),Facility, and cash from operating activities, (at least $10.0 million), and proceeds from the exerciseto fund its 2006 planned capital
38
expenditures of options and warrants (at least $4.0 million),approximately $46 million. Infinity will require external financing in 2006 to fund its planned capital expenditures of approximately $42 milliondrilling and redeem the 7% notes should none of the balance outstanding at March 23, 2005 be presented for conversion.exploration activities.
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 sell additional notesNotes and warrantsWarrants under the Senior Secured Notes 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.shortfalls, or, because Infinity’s planned capital expenditures are largely discretionary, Infinity could decrease the level of its planned capital expenditures.
| |
| Critical Accounting Policies and Estimates |
Critical Estimates
Infinity believes the following critical accounting policies affect its more significant judgments and
Following is a discussion of estimates used in the preparation of its consolidatedInfinity’s financial statements.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 estimated quantitiesestimate of proved reserves at December 31, 2004 and 2003 were prepared by independent petroleum engineers Netherland, Sewell and Associates, Inc. and at December 31, 2002 were prepared by independent petroleum engineers Wells Chappell and Company, Inc. Infinity’s estimatesis based on the quantities of oil and natural gas reserves, by necessity, are projections based on geologicwhich geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulation of oil and natural gas that are difficult to measure.operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. EstimatesFor example, the Company must estimate the amount and timing of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance, ad valoremproduction and exciseproperty taxes, development costs, and work-over and remedialworkover costs, all of which may, in fact, vary
44
considerably from actual results. For these reasons, estimatesIn addition, as prices and cost levels change from year to year, the estimate of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of suchproved reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially.also changes. Any significant variance in thethese 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 which could affect the carrying value ofare 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.
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 are to provide a measure of stability to the Company’s cash flows in an environment of
39
volatile oil and gas prices and to manage the exposure to commodity price risk. The Company’s senior secured notes (see Note 6) include certain terms, conditions and features that are separately accounted for as embedded derivatives at estimated fair value. In addition, the related warrants issued with the senior secured notes and non-employee options and warrants are also 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, interest rates and the rateprobability of depletionconversion, redemption or exercise, 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 properties. Actual production, revenuesproperty 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 expenditures with respectliability 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, as of December 31, 2005 and 2004, management was not able to concluded that it is more likely than not that the Company will realize the benefits of these deductible differences. As such, at December 31, 2005 and 2004, the Company recorded a full valuation allowance for its net deferred tax asset.
Critical Policies
The accounting for Infinity’s reserves will likely vary from estimates,business is subject to special accounting rules that are unique to the oil and suchgas 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 may be material.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 |
Oil and Gas Properties, Depreciation and Full Cost Ceiling Test
Infinity follows
Under the full cost method of accounting for oil and gas properties. Under this method,properties, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalizedCapitalized costs include lease acquisition costs, geological and geophysical work, delay rentals, the cost of drilling, completing
40
and equipping oil and gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. The capitalized costs are amortizeddepleted over the life of the reserves associated with the assets with the amortization being expensed as 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. Costs associated with production
The costs of wells in progress and general corporate activitiesunevaluated properties, including any related capitalized interest, are expensednot amortized. On a quarterly basis, such costs are evaluated for inclusion in the period incurred. Interestcosts 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 unproved properties and properties under development are also capitalized to oil and gas properties.
If the net investment inproved oil and gas properties, less asset retirement obligations, exceedswith 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 amount equal toimpairment test prescribed by SECRegulation S-XRule 4-10. The test determines a limit, or ceiling, on the sumnet book value of (1)oil and gas properties. That limit is basically the standardized measureafter tax present value of discountedthe future net cash flows from proved oil and natural gas reserves, includingas adjusted for asset retirement obligations and the effect of cash flow hedges, and (2)hedges. This ceiling is compared to the lower of cost or fair marketnet book value of properties in process of development and unexplored acreage, the excess is charged to expense as additional depletion. Infinity is required to review the carrying value of its oil and gas properties each quarter underreduced by any related net deferred income tax liability. If the full cost accounting rules ofnet book value reduced by the Securities and Exchange Commission. Under these rules, capitalized costs of proved oil and gas properties, excludingrelated 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 cash outflows associated with settling asset retirement obligations that have been accrued in the full cost pool, less accumulateddepletion, depreciation and amortization and related deferred taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the un-escalated prices in effect as of the last day of the quarter, including the effects of cash flow hedges, and requires a write down for accounting purposes if the ceiling is exceeded. Unproved oil and gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.rate would be reduced.
At December 31, 2004,2005, the carrying amount of oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $8,900,000$13,450,000 based upon aan average natural gas price of approximately $6.07$8.21 per Mcf and an average oil price of approximately $40.25$60.74 per barrel in effect at that date. However, due to significant subsequent price increases to approximately $6.53 per Mcf of gasIn 2004 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. In 2003, the Company also recorded a ceiling writedownwritedowns of $2,975,000.$4,100,000 and $2,975,000, respectively.
A decline
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 prices received for oilhigher capitalized costs and gas sales or an increase in operating costs subsequenthigher depletion rates compared to the measurement date or reductionssuccessful 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 estimated economically recoverable quantities could result in a requirement that Infinity recognize an additional ceiling write-downdiscovering and developing proved reserves.
Contractual Obligations
The following table summarizes by period the Company’s contractual obligations as of oil and gas properties in a future period. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized.December 31, 2005.
| | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
| | | Total | | | 2006 | | | 2007 and 2008 | | | 2009 and 2010 | | | Thereafter | |
| | | (In thousands) | |
| |
| Senior Secured Notes(a) | | $ | 45,000 | | | $ | — | | | $ | — | | | $ | 45,000 | | | $ | — | |
| Note payable to seller(b) | | | 2,203 | | | | 118 | | | | 203 | | | | 183 | | | | 1,699 | |
| Asset retirement obligations(c) | | | 1,413 | | | | 284 | | | | 697 | | | | 60 | | | | 372 | |
| Capital lease | | | 181 | | | | 93 | | | | 88 | | | | — | | | | — | |
| Operating leases | | | 166 | | | | 97 | | | | 69 | | | | — | | | | — | |
| Gas gathering commitments(d) | | | 4,954 | | | | 400 | | | | 1,680 | | | | 1,916 | | | | 958 | |
| Non-current production and property taxes | | | 401 | | | | — | | | | 401 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total contractual obligations | | $ | 54,318 | | | $ | 992 | | | $ | 3,138 | | | $ | 47,159 | | | $ | 3,029 | |
| | | | | | | | | | | | | | | | | | | | | |
45
41
| | |
| (a) | Property, Equipment | The amounts included in the table above represent principal maturities only. The Senior Secured Notes accrue interest at the3-month LIBOR (London Interbank Offered Rate) plus 675 basis points, adjusted the first business day of each calendar quarter (11.23% at December 31, 2005). See Note 6 of Notes to Consolidated Financial Statements. |
|
| (b) | | This note payable was given by the Company in connection with the acquisition of a 50% interest in an aircraft in 2003. In February 2006, the Company sold its 50% interest in the aircraft and Depreciationsettled the related note payable. The table above reflects the Company’s obligation under the note payable as of December 31, 2005. See Note 16 of Notes to Consolidated Financial Statements. |
|
| (c) | | The table above reflects the Company’s best 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. |
|
| (d) | | 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 contract related to the Company’s Pipeline field. The Pipeline contract is subject to certain delivery commitments that Infinity-Wyoming has not met. However, the gas gatherer has also not been able to supply the additional system capacity to allow Infinity-Wyoming to meet its delivery obligations and, Infinity-Wyoming expects that the contract will be amended to reflect volume requirements that are consistent with deliveries, although the contract term will likely be lengthened. See Note 10 of Notes to Consolidated Financial Statements. |
Equipment utilized in the oilfield service business and to support operations on Infinity’s oil and gas properties is stated at cost. This equipment is depreciated using the straight line method over the estimated useful lives of the assets of three to 30 years.
The deferred tax assets and liabilities represent the future tax return consequences of those temporary differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that are not expected to be realized based on available evidence that is more likely than not to be realized in the form of a deferred tax valuations allowance.
| |
| Off-Balance Sheet Arrangements |
Infinity has no material off-balance sheet arrangements.
Infinity’s contractual obligations, including those of its consolidated subsidiaries, include long-term debt, equipment and operating leases and other non-current obligations. The following table lists Infinity’s significant contractual obligations at December 31, 2004.
| | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
| | | | |
| | | Total | | | <1 Year | | | 1-3 Years | | | 3-5 Years | | | >5 Years | |
| | | | | | | | | | | | | | | | |
| | | (In thousands) | |
| 8% subordinated convertible notes | | $ | 2,493 | | | $ | — | | | $ | 2,493 | | | $ | — | | | $ | — | |
| 7% subordinated convertible notes | | | 11,517 | | | | — | | | | 11,517 | | | | — | | | | — | |
| Revolving credit facilities and term loans | | | 9,288 | | | | 3,150 | | | | 5,980 | | | | 103 | | | | 55 | |
| Note payable to seller | | | 2,326 | | | | 124 | | | | 216 | | | | 194 | | | | 1,792 | |
| Asset retirement obligations | | | 635 | | | | — | | | | — | | | | — | | | | 635 | |
| Office lease | | | 355 | | | | 122 | | | | 200 | | | | 33 | | | | — | |
| Non-current production and property taxes | | | 469 | | | | 469 | | | | — | | | | — | | | | — | |
| Total contractual obligations | | $ | 27,083 | | | $ | 3,865 | | | $ | 20,406 | | | $ | 330 | | | $ | 2,482 | |
For purposes of this table, Infinity is assuming that the holders of the 7% and 8% subordinated convertible notes will not exercise the conversion feature. In addition periodic interest payments required under the credit facilities and the 7% and 8% subordinated convertible notes are not reflected in the table. In January 2005, the Company repaid the revolving credit facility and term loans using proceeds from the Senior Secured Notes facility. However, the table above reflects the original maturity of the debt.Recently Issued Accounting Pronouncements
This table does not reflect the obligations associated with the gas gathering contract related to the Pipeline property. That contract is subject to certain delivery commitments that Infinity-Wyoming has not met. However, the gas gatherer has also not been able to supply the additional system capacity to allow Infinity-Wyoming to meet its delivery obligations and, Infinity-Wyoming expects that the contract will be amended to reflect volume requirements that are consistent with deliveries.
| |
| Recently Issued Accounting Pronouncements |
In December 2004, the FASBFinancial Accounting Standards Board (“FASB”) issued SFASStatement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-BasedShare-Based Payment”, which is a revision of SFAS No. 123, “AccountingAccounting for Stock-Based Compensation”.Compensation. SFAS No. 123(R) is effective for public companies for interim or annual periods beginning after June 15, 2005, supersedes APBAccounting Principals Board (“APB”) Opinion No. 25, “AccountingAccounting for Stock Issued to Employee’s,”Employees, and amends SFAS No. 95, “StatementStatement of Cash Flows.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values, beginning with the first interim or annual
46
period after June 15, 2005, with early adoption encouraged.values. The pro forma disclosures previously permitted under SFAS No. 123 are no longer will be an alternative to financial statement recognition. SFAS No. 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce the Company’s future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future.
The Company is required to adopt
SFAS No. 123(R) inmust be adopted no later than January 1, 2006 and permits public companies to adopt its third quarterrequirements using one of fiscal 2005, beginning July 1, 2005. Under SFAS No. 123(R), Infinity must determinetwo methods:
| | |
| • | A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date. |
|
| • | A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures. |
The Company adopted the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive options, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock at the beginning of the first quarter of adoptionprovisions of SFAS No. 123(R); on January 1, 2006 using the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. Infinity is evaluating the requirements of SFAS No. 123(R), and expects that themodified prospective method. The adoption of SFAS No. 123(R) will not have a materialhad no impact on consolidatedthe Company’s results of operations and earnings per share asbecause all employee stock options outstanding options areat December 31, 2005 were fully vested. As permitted by SFAS No. 123, through December 31, 2005 the Company accounted for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. Had the Company adopted SFAS No. 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123.
42
In March 2005, the FASB issued FASB Interpretation (“FIN”) 47,Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143. FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The Company adopted the provisions of FIN 47 effective December 31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.
In December 2004,February 2006, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29, 155,Accounting for Nonmonetary Transactions” (“Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140.SFAS 153”).No. 155 resolves issues addressed in SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchangesNo. 133 Implementation Issue No. D1,Application of similar productive assetsStatement 133 to Beneficial Interests in paragraph 21(b) of APB OpinionSecuritized Financial Assets. SFAS No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is155 will become effective for the Company’s fiscal periods beginningyear after JuneSeptember 15, 2005.2006. The Company is currently evaluating the effect that the adoption of SFAS 153 will have on consolidated results of operations and financial condition but does not expect it to have a material impact.
Staff Accounting Bulletin (“SAB”) 106 was released in September 2004. SAB 106 expresses the SEC staff’s views on the interactionimpact of SFAS No. 143155 will depend on the nature and extent of any new derivative instruments entered into after the full cost method and provides guidance on computing the full cost ceiling as well as depreciation, depletion and amortization. SAB 106 also requires additional disclosures regarding how the application of SFAS No. 143 has affected the ceiling test and depreciation, depletion and amortization. The Company adopted SAB 106 during the fourth quarter of 2004 and experienced no significant impact on its depletion or ceiling test calculation.effective date.
| |
| 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. GasExcluding sales under a fixed price contract which averaged $4.21 per Mcf, gas price realizations ranged from a low of $4.17$5.81 to a high of $6.98$12.04 per Mcf during the year ended December 31, 2004.2005. Oil price realizations ranged from a low of $33.35$43.12 per barrel to a high of $52.58$65.02 per barrel during thethat period.
Infinity periodically enters into fixed pricefixed-price physical contracts or hedging activitiesand 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. Realized gains or losses from Infinity’s cash flow risk management activitiesAs of December 31, 2005, the Company had one fixed price physical contract in place with the following terms:
| | | | | | | | | |
Delivery Dates | | MMBtu per Day | | Fixed Price |
| |
| April 1, 2005 - March 31, 2006 | | | 2,000 | | | $ | 4.15 | |
Sales under this fixed price contract are recognizedaccounted for as normal sales agreements under the exemption in production revenues. InSFAS No. 133. For the yearyears ended December 31, 2005 and 2004, the effect of Infinity-Wyoming hedgingInfinity’s sale of a portion of its gas production under a fixed price contract, compared to if it had sold the gas on the spot marketsales, was a decrease in revenue of approximately $1.4 million and $0.6 million.million, respectively.
As of December 31, 2005, Infinity had two costless collar arrangements in place to manage exposure to oil price volatility on a portion of its oil production. The following table sets forth the terms of the Company’s collar arrangements as of December 31, 2005:
| | | | | | | | | | | | | |
Terms of Arrangements | | Bbls per Day | | Floor Price | | Ceiling Price |
| |
| January 1, 2006 - June 30, 2006 | | | 50 | | | $ | 50.00 | | | $ | 64.40 | |
| October 1, 2005 - December 31, 2006 | | | 50 | | | $ | 52.50 | | | $ | 74.00 | |
Subsequent to December 31, 2005, the Company entered into the following costless collar arrangement:
| | | | | | | | | | | | | |
Terms of Arrangement | | Bbls per Day | | Floor Price | | Ceiling Price |
| |
| January 1, 2007 - June 30, 2007 | | | 50 | | | $ | 57.50 | | | $ | 77.50 | |
All of the Company’s collar arrangements have been designated as cash flow hedges.
The Securities Purchase Agreement dated as of January 13, 2005 by and among Infinity and the Buyers of the Notes includes a covenant that at each date that is the end of a quarterly or annual period covered by a quarterly report onForm 10-Q or annual report onForm 10-K (a “Determination Date”), at least 20% of the Company’s estimate of its oil and gas production for the12-month period commencing immediately after such
47
Determination Date shall be protected from price fluctuations using derivatives, fixed price agreementsand/or volumetric production payments. It is the opinion of management that the Company would have beenwas in compliance with this hedging requirement at December 31, 2004, had the Notes been issued and outstanding on that date.2005.
43
| |
| 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 at 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”) are communicated,is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. At the end offorms, and that such information is accumulated and communicated to management, including the Company’s fourth quarter of 2004,Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required by Rules 13a-15 and 15d-15 of the Exchange Act, an evaluation was carried out under the supervision anddisclosure. The Company’s management, with the participation of the Company’s management, including the Chief Executive Officer and PrincipalChief Financial and Accounting Officer, ofhas evaluated the effectiveness of the design and operation ofCompany’s disclosure controls and procedures (as defined in Rule 13a-15(e) underas of the Exchange Act). Based upon that evaluation,end of the fiscal year covered by this Annual Report onForm 10-K. The Company’s Chief Executive Officer and the PrincipalChief Financial and Accounting Officer have concluded that, as of the design and operationend of thesethe period covered by this Annual Report onForm 10-K, the Company’s disclosure controls and procedures were effective aseffective.
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 the reliability of that date. No changesfinancial 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 controlscontrol over financial reporting identified in connection with itsmay not prevent or detect misstatements. Management’s projections of any evaluation (as required by Rules 13a-15(d) and 15d-15(d) of the Exchange Act) occurredeffectiveness 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, 2005 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, 2005, the Company’s internal control over financial reporting was effective.
44
Report of 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, 2005, has issued an audit report on management’s assessment of the Company’s 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 fourthfiscal quarter of 2004ended December 31, 2005 that have materially affected, or wereare reasonably likely to materially affect, the Company’s internal control over financial reporting.
Although the evaluation did not detect any material weaknesses or significant deficiencies in the Company’s system of internal accounting controls over financial reporting, management has identified certain deficiencies in its reconciliation procedures, level of staffing, and inherent limitations in its electronic data processing software. The Company has added additional accounting staff during the first quarter of 2005 and intends to add additional accounting personnel during the second quarter of 2005 to address these deficiencies. The Company will also assess the viability of replacing or enhancing its electronic data processing software in 2005.
48
PART III
| |
ITEM 10:9B. | OTHER INFORMATION |
None.
PART III
| |
| ITEM 10: | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
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 20042006 annual meeting of shareholdersstockholders (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.
| |
| 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 AND RELATED TRANSACTIONS |
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” on Page 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 on Form 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.
45
49
EXHIBITS
| | | | |
Exhibit | | |
Number | | Description of Exhibits |
| | |
| 3.1 | | | Articles of Incorporation and Bylaws(1) |
| 3.2 | | | Articles and Amendment to Articles of Incorporation(1) |
| 3.3 | | | Articles of Amendment to Articles of Incorporation(2) |
| 4.1 | | | Form of 8% Convertible Subordinated Note(1) |
| 4.2 | | | Form of Trust Indenture for 8% Convertible Subordinated Notes with the Wilmington Trust Company(3) |
| 4.3 | | | Form of Placement Agent Warrant in connection with 8% Convertible Subordinated Notes(1) |
| 4.4 | | | Trust Indenture for 7% Convertible Subordinated Notes with Wilmington Trust Company(1) |
| 4.5 | | | Form of Placement Agent Warrants in connection with 7% Convertible Subordinated Notes(4) |
| 4.6 | | | Form of Warrant Agreement for 12% Bridge Note Financing(1) |
| 4.7 | | | Form of Common Stock Purchase Agreement for January 2004 private placement(5) |
| 4.8 | | | Form of Registration Rights Agreement in connection with January 2004 private placement(5) |
| 4.9 | | | Form of Common Stock Purchase Agreement for November 2004 private placement(6) |
| 4.10 | | | Form of Registration Rights Agreement for November 2004 private placement(6) |
| 4.11 | | | Securities Purchase Agreement for Senior Secured Notes with Promethean Asset Management LLC(7) |
| 4.12 | | | Form of Initial Note for Senior Secured Notes (7) |
| 4.13 | | | Form of Additional Note for Senior Secured Notes(7) |
| 4.14 | | | Registration Rights Agreement in connection with Senior Secured Notes(7) |
| 4.15 | | | Form of Warrant in connection with Senior Secured Notes(7) |
| 4.16 | | | Form of Security Agreement for Senior Secured Notes(7) |
| 4.17 | | | Form of Guaranty for Senior Secured Notes(7) |
| 4.18 | | | Form of Mortgage for Senior Secured Notes(7) |
| 10.1 | | | Stock Option Plan (1); 1999 Stock Option Plan (2); 2000 Stock Option Plan (1); 2001 Stock Option Plan (8); 2002 Stock Option Plan (9); 2003 Stock Option Plan (10); 2004 Stock Option Plan(11) |
| 10.2 | | | Loan and Security Agreement between LaSalle Bank N.A. and Consolidated Oil Well Services, Inc. and related guaranties (1); Third Amendment to Loan and Security Agreement with LaSalle Bank N.A. (12); Fourth Amendment to Loan and Security Agreement with LaSalle Bank N.A.(13) |
| 10.3 | | | Credit agreement dated as of September 4, 2003 between Infinity Oil and Gas of Wyoming, Inc. and U.S. Bank National Association (14); First Amendment of Credit Agreement with U.S. Bank(13) |
| 10.4 | | | Promissory Note to Stanton E. Ross, dated June 11, 2004(13) |
| 21 | | | Subsidiaries of the Registrant |
| 23.1 | | | Consent of Ehrhardt, Keefe, Steiner & Hottman, P.C. |
| 23.2 | | | Consent of Netherland Sewell and Associates, Inc. |
| 31.1 | | | Certification of Chief Executive Officer of Periodic Report Pursuant to Rule 13a_14(a) and Rule 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 13a_14(a) and Rule 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) |
50
(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) |
| | 10 | .2 | | Promissory Note to Stanton E. Ross, dated June 11, 2004(13) |
| | 10 | .3 | | First Additional Closing Agreement dated September 7, 2005(14) |
| | 21 | | | Subsidiaries of the Registrant |
| | 23 | .1 | | Consent of Ehrhardt, Keefe, Steiner & Hottman, P.C. |
| | 23 | .2 | | Consent of Netherland Sewell and 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 (No. 33-17416-D).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. |
46
|
(3) | Incorporated by reference to our Registration Statement on Form S-3 (File No. 333-69292). |
|
(4) | Incorporated by reference to our Registration Statement on Form S-3 (File No. 333-96671). |
|
(5) | Incorporated by reference to our Current Report on Form 8-K, filed with the SEC on January 21, 2004. |
|
(6) | Incorporated by reference to our Current Report on Form 8-K, filed with the SEC on November 16, 2004. |
|
(7) | Incorporated by reference to our Current Report on Form 8-K, filed with the SEC on January 14, 2005. |
|
| (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 Quarterly Report onForm 10-Q for the quarter ended March 31, 2004. |
|
(13) | Incorporated by reference to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004. |
| |
| (14) | | Incorporated by reference to our QuarterlyCurrent Report onForm 10-Q for the quarter ended8-K, filed on September 30, 2003.8, 2005. |
47
51
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. RossJAMES A. TUELL |
| |
| |
| Stanton E. Ross |
| President and Chief Executive Officer |
James A. Tuell
President and Chief Executive Officer
Dated: March 30, 20058, 2006
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 | | President and Chief Executive Officer
(Principal Executive Officer) and Director | | March 30, 2005 |
|
/s/James A. Tuell
James A. Tuell | | Executive Vice President
(Principal Financial and Accounting Officer) | | March 30, 2005 |
|
/s/Elliot M. Kaplan
Elliot M. Kaplan | | Director | | March 30, 2005 |
|
/s/Robert O. Lorenz
Robert O. Lorenz | | Director | | March 29, 2005 |
|
/s/Leroy C. Richie
Leroy C. Richie | | Director | | March 30, 2005 |
|
O. Lee Tawes | | Director | | March , 2005 |
52
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | |
| | | PageSignature | |
Capacity | | Date | | | |
Report of Independent Registered Public Accounting Firm | | | F-2 | |
Consolidated Financial Statements:/s/ JAMES A. TUELL
James A. Tuell | | President and Chief Executive Officer (Principal Executive Officer) and Director | | March 8, 2006 | | | | |
| | Consolidated Balance Sheets — December 31, 2004 and 2003 | | | F-3 | | | | |
/s/ TIMOTHY A. FICKER
Timothy A. Ficker | | Vice President, Chief Financial Officer (Principal Financial and Accounting Officer) | | March 8, 2006 | | | | |
| | Consolidated Statements of Operations — For the Years Ended December 31, 2004, 2003 and 2002 | | | F-4 | | | | |
/s/ STANTON E. ROSS
Stanton E. Ross | | Director | | March 8, 2006 | | | | |
| | | | | | | | | |
/s/ ELLIOT M. KAPLAN
Elliot M. Kaplan | | Director | | March 8, 2006 | | | | |
| | | | | | | | |
/s/ ROBERT O. LORENZ
Robert O. Lorenz | | Director | | March 8, 2006 | | | | |
| | | | | | | | |
/s/ LEROY C. RICHIE
Leroy C. Richie | | Director | | March 8, 2006 | | | | |
48
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | |
| | | F-2 | |
| Consolidated Financial Statements: | | | | |
| | | F-3 | |
| | | F-4 | |
| | | F-5 | |
| | | | F-7F-6 | |
| | | F-9F-8 | |
F-1
F-1
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Infinity Energy Resources, Inc. and Subsidiaries
Chanute, KansasDenver, Colorado
We have audited the accompanying consolidated balance sheets of Infinity Energy Resources, Inc. and Subsidiaries as of December 31, 2005 and 2004, and 2003 and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004, 2003 and 2002. These consolidated2005. 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, 2005, 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 financial statements, are the responsibilityfor maintaining effective internal control over financial reporting, and for its assessment of the Company’s management.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 auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration ofmisstatement and whether effective internal control over financial reporting as a basis for designingwas maintained in all material respects. Our audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includesstatements included examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includesstatements, assessing the accounting principles used and significant estimates made by management, as well asand evaluating the overall consolidated 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 opinion.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 conditionposition of Infinity Energy Resources, Inc. and Subsidiaries, as of December 31, 20042005 and 2003,2004, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2004, 2003 and 2002,2005 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, 2005, 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, 2005, 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, 2003, the Company changed its method of accounting for asset retirement obligations.
| |
| /s/ Ehrhardt Keefe Steiner & Hottman PC |
/s/ Ehrhardt Keefe Steiner & Hottman PC
March 13, 2005, except for Notes 7, 8 and 16
which are as of March 23, 20053, 2006
Denver, Colorado
F-2
F-2
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | |
| | | December 31, 2004 | | | December 31, 2003 | |
| | | | | | | |
| ASSETS |
| Current assets | | | | | | | | |
| | Cash and cash equivalents | | $ | 3,051,986 | | | $ | 727,134 | |
| | Accounts receivable, less allowance for doubtful accounts of $85,476 (2004) and $80,000 (2003) | | | 3,493,448 | | | | 1,766,642 | |
| | Current portion of note receivable | | | 1,580,742 | | | | 16,311 | |
| | Inventories | | | 286,365 | | | | 351,197 | |
| | Prepaid expenses and other | | | 654,107 | | | | 206,314 | |
| | Derivative asset | | | — | | | | 97,624 | |
| | | | | | | |
| | | | Total current assets | | | 9,066,648 | | | | 3,165,222 | |
| Property and equipment, at cost, less accumulated depreciation | | | 8,764,327 | | | | 10,043,828 | |
| Oil and gas properties, using full cost accounting net of accumulated depreciation, depletion, amortization and ceiling write-down | | | | | | | | |
| | | Subject to amortization | | | 28,791,880 | | | | 23,446,343 | |
| | | Not subject to amortization | | | 15,595,508 | | | | 12,715,834 | |
| Intangible assets, at cost, less accumulated amortization | | | 1,497,076 | | | | 3,952,989 | |
| Note receivable, less current portion | | | — | | | | 1,580,742 | |
| Other assets, net | | | 332,824 | | | | 361,320 | |
| | | | | | | |
| Total assets | | $ | 64,048,263 | | | $ | 55,266,278 | |
| | | | | | | |
| |
| LIABILITIES AND STOCKHOLDERS’ EQUITY |
| Current Liabilities | | | | | | | | |
| | Note payable and current portion of long-term debt | | $ | 283,978 | | | $ | 1,762,777 | |
| | Accounts payable | | | 4,001,364 | | | | 2,645,277 | |
| | Accrued liabilities | | | 4,496,412 | | | | 966,769 | |
| | | | | | | |
| | | | Total current liabilities | | | 8,781,754 | | | | 5,374,823 | |
| Long-term liabilities | | | | | | | | |
| | Production taxes payable | | | 469,054 | | | | 229,889 | |
| | Asset retirement obligations | | | 635,023 | | | | 520,638 | |
| | Long-term debt, less current portion | | | 11,330,438 | | | | 9,252,872 | |
| | 8% subordinated convertible notes payable | | | 2,493,000 | | | | 2,793,000 | |
| | 7% subordinated convertible notes payable | | | 11,516,698 | | | | 11,184,000 | |
| | Note payable — related party | | | — | | | | 3,000,000 | |
| | | | | | | |
| | | | Total liabilities | | | 35,225,967 | | | | 32,355,222 | |
| | | | | | | |
| Commitments and contingencies | | | | | | | | |
| Stockholders’ equity | | | | | | | | |
| | Common stock, par value $.0001, authorized 300,000,000 shares, issued and outstanding 10,628,196 (2004) and 8,204,032 (2003) shares | | | 1,063 | | | | 820 | |
| | Additional paid-in-capital | | | 43,362,925 | | | | 32,720,904 | |
| | Accumulated other comprehensive income | | | — | | | | 97,624 | |
| | Accumulated deficit | | | (14,541,692 | ) | | | (9,908,292 | ) |
| | | | | | | |
| | | | Total stockholders’ equity | | | 28,822,296 | | | | 22,911,056 | |
| | | | | | | |
| Total liabilities and stockholders’ equity | | $ | 64,048,263 | | | $ | 55,266,278 | |
| | | | | | | |
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (In thousands, except share and per share data) | |
| |
ASSETS |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 7,942 | | | $ | 3,052 | |
| Accounts receivable, less allowance for doubtful accounts of $70 (2005) and $85 (2004) | | | 4,748 | | | | 3,494 | |
| Note receivable | | | — | | | | 1,581 | |
| Inventories | | | 453 | | | | 286 | |
| Prepaid expenses and other | | | 422 | | | | 654 | |
| | | | | | | | | |
| Total current assets | | | 13,565 | | | | 9,067 | |
| Property and equipment, at cost, net of accumulated depreciation | | | 11,489 | | | | 8,764 | |
| Oil and gas properties, using full cost accounting, net of accumulated depreciation, depletion, amortization and ceiling write-down: | | | | | | | | |
| Proved | | | 43,699 | | | | 28,792 | |
| Unproved | | | 22,849 | | | | 15,595 | |
| Intangible assets, at cost, less accumulated amortization | | | 2,514 | | | | 1,497 | |
| Other assets, net | | | 168 | | | | 333 | |
| | | | | | | | | |
| Total assets | | $ | 94,284 | | | $ | 64,048 | |
| | | | | | | | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY |
| Current liabilities: | | | | | | | | |
| Note payable and current portion of long-term debt | | $ | 288 | | | $ | 284 | |
| Accounts payable | | | 5,035 | | | | 4,001 | |
| Accrued liabilities | | | 6,314 | | | | 4,497 | |
| Current portion of asset retirement obligations | | | 284 | | | | — | |
| | | | | | | | | |
| Total current liabilities | | | 11,921 | | | | 8,782 | |
| Long-term liabilities: | | | | | | | | |
| Production taxes payable | | | 401 | | | | 469 | |
| Asset retirement obligations, less current portion | | | 1,129 | | | | 635 | |
| Accrued interest | | | 905 | | | | — | |
| Derivative liabilities | | | 9,837 | | | | — | |
| Long-term debt, less current portion | | | 39,874 | | | | 11,330 | |
| Subordinated convertible notes payable | | | — | | | | 14,010 | |
| | | | | | | | | |
| Total liabilities | | | 64,067 | | | | 35,226 | |
| | | | | | | | | |
| Commitments and contingencies (Note 10) | | | | | | | | |
| Stockholders’ equity: | | | | | | | | |
| Preferred stock, par value $.0001, authorized 10,000,000 shares, issued and outstanding -0- (2005) and -0- (2004) shares | | | — | | | | — | |
| Common stock, par value $.0001, authorized 75,000,000 shares, issued and outstanding 13,501,988 (2005) and 10,628,196 (2004) shares | | | 1 | | | | 1 | |
Additionalpaid-in-capital | | | 58,335 | | | | 43,363 | |
| Accumulated deficit | | | (28,119 | ) | | | (14,542 | ) |
| | | | | | | | | |
| Total stockholders’ equity | | | 30,217 | | | | 28,822 | |
| | | | | | | | | |
| Total liabilities and stockholders’ equity | | $ | 94,284 | | | $ | 64,048 | |
| | | | | | | | | |
See Notes to Consolidated Financial StatementsStatements.
F-3
F-3
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Revenue | | | | | | | | | | | | |
| | Oilfield service operations | | $ | 14,720,979 | | | $ | 11,634,457 | | | $ | 8,570,631 | |
| | Exploration and production | | | 6,267,453 | | | | 6,589,281 | | | | 2,367,713 | |
| | | | | | | | | | |
| | | Total revenue | | | 20,988,432 | | | | 18,223,738 | | | | 10,938,344 | |
| Cost of revenue | | | | | | | | | | | | |
| | Oilfield service operations | | | 7,890,375 | | | | 6,222,919 | | | | 4,620,663 | |
| | Oil and gas production expenses | | | 1,913,735 | | | | 2,161,666 | | | | 1,582,816 | |
| | Oil and gas production taxes | | | 722,157 | | | | 758,827 | | | | 237,876 | |
| | | | | | | | | | |
| | | Total cost of revenue | | | 10,526,267 | | | | 9,143,412 | | | | 6,441,355 | |
| | | | | | | | | | |
| Gross profit | | | 10,462,165 | | | | 9,080,326 | | | | 4,496,989 | |
| General and administrative expenses | | | 5,462,491 | | | | 5,311,080 | | | | 4,647,062 | |
| Depreciation, depletion, amortization and accretion | | | 5,197,981 | | | | 3,074,247 | | | | 1,782,586 | |
| Ceiling write-down of oil and gas properties | | | 4,100,000 | | | | 2,975,000 | | | | — | |
| | | | | | | | | | |
| | | | 14,760,472 | | | | 11,360,327 | | | | 6,429,648 | |
| | | | | | | | | | |
| Operating loss | | | (4,298,307 | ) | | | (2,280,001 | ) | | | (1,932,659 | ) |
| Other income (expense) | | | | | | | | | | | | |
| | Interest and other income | | | 169,937 | | | | 129,599 | | | | 102,460 | |
| | Amortization of loan costs | | | (2,097,329 | ) | | | (6,200,633 | ) | | | (234,680 | ) |
| | Interest expense and finance charges | | | (1,231,515 | ) | | | (1,593,765 | ) | | | (602,350 | ) |
| | Gain (loss) on sales of other assets | | | 2,823,814 | | | | 19,920 | | | | (33,665 | ) |
| | | | | | | | | | |
| | | Total other expense | | | (335,093 | ) | | | (7,644,879 | ) | | | (768,235 | ) |
| | | | | | | | | | |
| Net loss before income taxes | | | (4,633,400 | ) | | | (9,924,880 | ) | | | (2,700,894 | ) |
| Income tax benefit | | | — | | | | — | | | | 1,144,028 | |
| | | | | | | | | | |
| Net loss | | $ | (4,633,400 | ) | | $ | (9,924,880 | ) | | $ | (1,556,866 | ) |
| | | | | | | | | | |
| Basic and diluted net loss per share | | $ | (0.49 | ) | | $ | (1.23 | ) | | $ | (0.22 | ) |
| | | | | | | | | | |
| Weighted average shares outstanding (basic and diluted) | | | 9,495,346 | | | | 8,047,688 | | | | 7,202,844 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands, except per share data) | |
| |
| Revenue: | | | | | | | | | | | | |
| Oilfield service operations | | $ | 21,583 | | | $ | 14,721 | | | $ | 11,634 | |
| Exploration and production | | | 9,192 | | | | 6,267 | | | | 6,589 | |
| | | | | | | | | | | | | |
| Total revenue | | | 30,775 | | | | 20,988 | | | | 18,223 | |
| Cost of revenue: | | | | | | | | | | | | |
| Oilfield service operations | | | 10,769 | | | | 7,890 | | | | 6,222 | |
| Oil and gas production expenses | | | 3,548 | | | | 1,914 | | | | 2,162 | |
| Oil and gas production taxes | | | 877 | | | | 722 | | | | 759 | |
| | | | | | | | | | | | | |
| Total cost of revenue | | | 15,194 | | | | 10,526 | | | | 9,143 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Gross profit | | | 15,581 | | | | 10,462 | | | | 9,080 | |
| | | | | | | | | | | | | |
| General and administrative expenses | | | 5,836 | | | | 5,462 | | | | 5,311 | |
| Depreciation, depletion, amortization and accretion | | | 7,451 | | | | 5,198 | | | | 3,074 | |
| Ceiling write-down of oil and gas properties | | | 13,450 | | | | 4,100 | | | | 2,975 | |
| | | | | | | | | | | | | |
| | | | 26,737 | | | | 14,760 | | | | 11,360 | |
| | | | | | | | | | | | | |
| Operating loss | | | (11,156 | ) | | | (4,298 | ) | | | (2,280 | ) |
| Other income (expense): | | | | | | | | | | | | |
| Financing costs: | | | | | | | | | | | | |
| Interest expense | | | (2,486 | ) | | | (1,232 | ) | | | (1,594 | ) |
| Amortization of loan discount and costs | | | (1,066 | ) | | | (1,741 | ) | | | (6,146 | ) |
| Early extinguishment of debt | | | (1,276 | ) | | | (356 | ) | | | (55 | ) |
| Change in derivative fair value | | | 2,908 | | | | — | | | | — | |
| Gain (loss) on sales of other assets | | | (96 | ) | | | 2,824 | | | | 20 | |
| Other | | | (405 | ) | | | 170 | | | | 130 | |
| | | | | | | | | | | | | |
| Total other expense | | | (2,421 | ) | | | (335 | ) | | | (7,645 | ) |
| | | | | | | | | | | | | |
| Net loss before income taxes | | | (13,577 | ) | | | (4,633 | ) | | | (9,925 | ) |
| Income taxes | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Net loss | | $ | (13,577 | ) | | $ | (4,633 | ) | | $ | (9,925 | ) |
| | | | | | | | | | | | | |
| Basic and diluted net loss per share | | $ | (1.05 | ) | | $ | (0.49 | ) | | $ | (1.23 | ) |
| | | | | | | | | | | | | |
| Weighted average shares outstanding (basic and diluted) | | | 12,936 | | | | 9,495 | | | | 8,048 | |
| | | | | | | | | | | | | |
See Notes to Consolidated Financial StatementsStatements.
F-4
F-4
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the years ended December 31, 2005, 2004 2003 and 20022003
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | (Accumulated | | | | | Accumulated | | | |
| | | Common Stock | | | Additional | | | Deficit) | | | Total | | | Other | | | |
| | | | | | Paid-In | | | Retained | | | Comprehensive | | | Comprehensive | | | Stockholders’ | |
| | | Shares | | | Amount | | | Capital | | | Earnings | | | Loss | | | Income (Loss) | | | Equity | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2001 | | | 6,515,224 | | | $ | 652 | | | $ | 13,632,999 | | | $ | 1,573,454 | | | | | | | | — | | | $ | 15,207,105 | |
| Issuance of common stock for cash upon the exercise of options and warrants | | | 588,264 | | | | 58 | | | | 1,947,147 | | | | — | | | | | | | | — | | | | 1,947,205 | |
| Conversion of 8% subordinated convertible notes and accrued interest into common stock | | | 454,974 | | | | 46 | | | | 2,274,813 | | | | — | | | | | | | | — | | | | 2,274,859 | |
| Warrants granted in connection with $2,000,000 bridge loan | | | — | | | | — | | | | 1,347,728 | | | | — | | | | | | | | — | | | | 1,347,728 | |
| Warrants granted in connection with 7% subordinated convertible notes | | | — | | | | — | | | | 1,386,044 | | | | — | | | | | | | | — | | | | 1,386,044 | |
| Warrants granted in connection with $3,000,000 bridge loan | | | — | | | | — | | | | 2,281,718 | | | | — | | | | | | | | — | | | | 2,281,718 | |
| Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net loss | | | — | | | | — | | | | — | | | | (1,556,866 | ) | | $ | (1,556,866 | ) | | | — | | | | (1,556,866 | ) |
| | Change in fair value of fixed price delivery contract, net of tax benefit of $60,712 | | | — | | | | — | | | | — | | | | — | | | | (96,981 | ) | | $ | (96,981 | ) | | | (96,981 | ) |
| | Reclassifications, net of income tax expense of $12,320 | | | — | | | | — | | | | — | | | | — | | | | 19,680 | | | | 19,680 | | | | 19,680 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | $ | (1,634,167 | ) | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2002 | | | 7,558,462 | | | | 756 | | | | 22,870,449 | | | | 16,588 | | | | | | | | (77,301 | ) | | | 22,810,492 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | (Accumulated
| | | | | | Accumulated
| | | | |
| | | | | | | | | Additional
| | | Deficit)
| | | Total
| | | Other
| | | | |
| | | Common Stock | | | Paid-In
| | | Retained
| | | Comprehensive
| | | Comprehensive
| | | Stockholders’
| |
| | | Shares | | | Amount | | | Capital | | | Earnings | | | Loss | | | Income (Loss) | | | Equity | |
| | | (In thousands, except share data) | |
| |
| Balance, December 31, 2002 | | | 7,558,462 | | | $ | 1 | | | $ | 22,871 | | | $ | 16 | | | | | | | $ | (77 | ) | | $ | 22,811 | |
| Issuance of common stock upon the exercise of options and warrants | | | 146,169 | | | | — | | | | 824 | | | | — | | | | | | | | — | | | | 824 | |
| Conversion of subordinated convertible notes and accrued interest into common stock | | | 499,401 | | | | — | | | | 3,236 | | | | — | | | | | | | | — | | | | 3,236 | |
| Options and warrants granted in connection with amendments and agreements related to bridge loans | | | — | | | | — | | | | 5,790 | | | | — | | | | | | | | — | | | | 5,790 | |
| Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | | | — | | | | — | | | | — | | | | (9,925 | ) | | $ | (9,925 | ) | | | — | | | | (9,925 | ) |
| Change in fair value of fixed price delivery contract, net of tax benefit | | | — | | | | — | | | | — | | | | — | | | | 257 | | | | 257 | | | | 257 | |
| Reclassifications, net of income tax expense | | | — | | | | — | | | | — | | | | — | | | | (82 | ) | | | (82 | ) | | | (82 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Comprehensive loss | | | | | | | | | | | | | | | | | | $ | (9,750 | ) | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2003 | | | 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 | ) | | | (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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
See Notes to Consolidated Financial StatementsStatements.
F-5
F-5
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITYCASH FLOWS
For the year ended December 31, 2004, 2003 and 2002
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | (Accumulated | | | | | Accumulated | | | |
| | | Common Stock | | | Additional | | | Deficit) | | | Total | | | Other | | | |
| | | | | | Paid-In | | | Retained | | | Comprehensive | | | Comprehensive | | | Stockholders’ | |
| | | Shares | | | Amount | | | Capital | | | Earnings | | | Loss | | | Income (Loss) | | | Equity | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2002 | | | 7,558,462 | | | $ | 756 | | | $ | 22,870,449 | | | $ | 16,588 | | | | | | | $ | (77,301 | ) | | $ | 22,810,492 | |
| Issuance of common stock upon the exercise of options and warrants | | | 146,169 | | | | 15 | | | | 824,219 | | | | — | | | | | | | | — | | | | 824,234 | |
| Conversion of 8% subordinated convertible notes and accrued interest into common stock | | | 295,689 | | | | 29 | | | | 1,478,521 | | | | — | | | | | | | | — | | | | 1,478,550 | |
| Conversion of 7% subordinated convertible notes and accrued interest into common stock | | | 203,712 | | | | 20 | | | | 1,756,996 | | | | — | | | | | | | | — | | | | 1,757,016 | |
| Options granted in connection with $1,050,000 of bridge loans | | | — | | | | — | | | | 1,050,000 | | | | — | | | | | | | | — | | | | 1,050,000 | |
| Options granted in connection with amendments and agreements related to a $3,000,000 bridge loan | | | — | | | | — | | | | 2,493,329 | | | | — | | | | | | | | — | | | | 2,493,329 | |
| Warrants granted in connection with $4,850,000 of bridge loans | | | — | | | | — | | | | 2,247,390 | | | | — | | | | | | | | — | | | | 2,247,390 | |
| Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net loss | | | — | | | | — | | | | — | | | | (9,924,880 | ) | | $ | (9,924,880 | ) | | | — | | | | (9,924,880 | ) |
| | Change in fair value of fixed price delivery contract, net of tax benefit of $151,573 | | | — | | | | — | | | | — | | | | — | | | | 256,500 | | | | 256,500 | | | | 256,500 | |
| | Reclassifications, net of income tax expense of $51,068 | | | — | | | | — | | | | — | | | | — | | | | (81,575 | ) | | | (81,575 | ) | | | (81,575 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | Comprehensive loss | | | | | | | | | | | | | | | | | | $ | (9,749,955 | ) | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2003 | | | 8,204,032 | | | | 820 | | | | 32,720,904 | | | | (9,908,292 | ) | | | | | | | 97,624 | | | | 22,911,056 | |
| Issuance of common stock in private equity placement financings, net of costs of $319,644 | | | 2,027,000 | | | | 203 | | | | 8,917,853 | | | | — | | | | | | | | — | | | | 8,918,056 | |
| Issuance of common stock to partially repay related party debt | | | 125,000 | | | | 13 | | | | 499,987 | | | | — | | | | | | | | — | | | | 500,000 | |
| Issuance of common stock upon the exercise of options and warrants | | | 146,300 | | | | 15 | | | | 428,432 | | | | — | | | | | | | | — | | | | 428,447 | |
| Conversion of 8% subordinated convertible notes and accrued interest into common stock | | | 63,179 | | | | 6 | | | | 308,276 | | | | — | | | | | | | | — | | | | 308,282 | |
| Conversion of 7% subordinated convertible notes and accrued interest into common stock | | | 62,685 | | | | 6 | | | | 487,473 | | | | — | | | | | | | | — | | | | 487,479 | |
| Comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net loss | | | — | | | | — | | | | — | | | | (4,633,400 | ) | | | (4,633,400 | ) | | | — | | | | (4,633,400 | ) |
| | Reclassifications, net of income tax expense of $(57,559) | | | — | | | | — | | | | — | | | | — | | | | (97,624 | ) | | | (97,624 | ) | | | (97,624 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| | | Comprehensive loss | | | | | | | | | | | | | | | | | | $ | (4,731,024 | ) | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2004 | | | 10,628,196 | | | $ | 1,063 | | | $ | 43,362,925 | | | $ | (14,541,692 | ) | | | | | | $ | — | | | $ | 28,822,296 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Cash flows from operating activities: | | | | | | | | | | | | |
| Net loss | | $ | (13,577 | ) | | $ | (4,633 | ) | | $ | (9,925 | ) |
| | | | | | | | | | | | | |
| Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | |
| Depreciation, depletion, amortization, accretion and ceiling write-down | | | 20,901 | | | | 9,298 | | | | 6,049 | |
| Amortization of loan discount and costs | | | 1,066 | | | | 1,741 | | | | 6,146 | |
| Non-cash early extinguishment of loan cost | | | 1,052 | | | | 356 | | | | 55 | |
| Change in fair value of derivative liabilities | | | (2,908 | ) | | | — | | | | — | |
| Impairment of note receivable and other | | | 530 | | | | — | | | | — | |
| (Gain) loss on sales of other assets | | | 96 | | | | (2,824 | ) | | | (20 | ) |
| Unrealized loss on commodity derivative instruments | | | 28 | | | | — | | | | — | |
| Change in operating assets and liabilities | | | | | | | | | | | | |
| Increase in accounts receivable | | | (1,273 | ) | | | (1,687 | ) | | | (252 | ) |
| (Increase) decrease in inventories | | | (167 | ) | | | 65 | | | | (11 | ) |
| (Increase) decrease in prepaid expenses and other | | | 232 | | | | (89 | ) | | | (12 | ) |
| Increase in accounts payable | | | 1,034 | | | | 1,526 | | | | 33 | |
| Increase in accrued liabilities | | | 2,636 | | | | 1,710 | | | | 782 | |
| | | | | | | | | | | | | |
| Net cash provided by operating activities | | | 9,650 | | | | 5,463 | | | | 2,845 | |
| | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | |
| Capital expenditures — exploration and production | | | (39,271 | ) | | | (11,714 | ) | | | (6,274 | ) |
| Capital expenditures — oilfield services | | | (4,190 | ) | | | (1,149 | ) | | | (460 | ) |
| Acquisitions — exploration and production | | | (330 | ) | | | (516 | ) | | | — | |
| Acquisitions — oilfield services, net of cash acquired | | | — | | | | (1,189 | ) | | | — | |
| Proceeds from sale of fixed assets — exploration and production | | | 133 | | | | 156 | | | | — | |
| Proceeds from sale of fixed assets — oilfield services | | | 31 | | | | 4,654 | | | | 105 | |
| Increase in other assets | | | (31 | ) | | | (200 | ) | | | (288 | ) |
| Proceeds from note receivable | | | 1,204 | | | | 16 | | | | 15 | |
| | | | | | | | | | | | | |
| Net cash used in investing activities | | | (42,454 | ) | | | (9,942 | ) | | | (6,902 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Proceeds from notes payable | | | 434 | | | | 295 | | | | — | |
| Proceeds from borrowings on long-term debt | | | 45,000 | | | | 5,845 | | | | 11,453 | |
| Proceeds from issuance of common stock | | | 4,707 | | | | 9,666 | | | | 824 | |
| Debt and equity issuance costs | | | (2,751 | ) | | | (320 | ) | | | — | |
| Repayment of notes payable | | | (406 | ) | | | (664 | ) | | | — | |
| Repayment of long-term debt | | | (9,290 | ) | | | (8,018 | ) | | | (8,360 | ) |
| | | | | | | | | | | | | |
| Net cash provided by financing activities | | | 37,694 | | | | 6,804 | | | | 3,917 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 4,890 | | | | 2,325 | | | | (140 | ) |
| Cash and cash equivalents, beginning of period | | | 3,052 | | | | 727 | | | | 867 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 7,942 | | | $ | 3,052 | | | $ | 727 | |
| | | | | | | | | | | | | |
See Notes to Consolidated Financial StatementsStatements.
F-6
F-6
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Cash flows from operating activities | | | | | | | | | | | | |
| | Net loss | | $ | (4,633,400 | ) | | $ | (9,924,880 | ) | | $ | (1,556,866 | ) |
| | | | | | | | | | |
| | Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | |
| | | Depreciation, depletion, amortization, accretion, impairment and ceiling write-down | | | 9,297,981 | | | | 6,049,247 | | | | 1,782,586 | |
| | | Amortization of loan costs included in interest expense | | | 2,097,329 | | | | 6,200,633 | | | | 234,680 | |
| | | Deferred income taxes | | | — | | | | — | | | | (1,144,028 | ) |
| | | (Gain) loss on sales of other assets | | | (2,823,814 | ) | | | (19,920 | ) | | | 33,665 | |
| | Change in assets and liabilities | | | | | | | | | | | | |
| | | (Increase) decrease in accounts receivable | | | (1,686,806 | ) | | | (252,483 | ) | | | 85,724 | |
| | | (Increase) decrease in inventories | | | 64,832 | | | | (10,980 | ) | | | 9,999 | |
| | | (Increase) decrease in prepaid expenses and other | | | (89,160 | ) | | | (12,234 | ) | | | (89,985 | ) |
| | | Increase in accounts payable | | | 1,525,618 | | | | 32,758 | | | | 284,657 | |
| | | Increase in accrued liabilities | | | 1,709,944 | | | | 782,391 | | | | 495,383 | |
| | | | | | | | | | |
| | | | Net cash provided by operating activities | | | 5,462,524 | | | | 2,844,532 | | | | 135,815 | |
| | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | |
| | Capital expenditures — exploration and production | | | (11,714,121 | ) | | | (6,273,692 | ) | | | (15,560,549 | ) |
| | Capital expenditures — oilfield services | | | (1,149,093 | ) | | | (459,820 | ) | | | (1,561,357 | ) |
| | Proceeds from sale of fixed assets — exploration and production | | | 155,779 | | | | — | | | | — | |
| | Proceeds from sale of fixed assets — oilfield services | | | 4,653,771 | | | | 104,911 | | | | 235,000 | |
| | Proceeds from sale of investments and marketable securities | | | — | | | | — | | | | 750,000 | |
| | Acquisitions — exploration and production, net of cash acquired | | | (516,239 | ) | | | — | | | | — | |
| | Acquisitions — oilfield services, net of cash acquired | | | (1,188,469 | ) | | | — | | | | — | |
| | Payments on note receivable | | | 16,311 | | | | 15,103 | | | | 7,844 | |
| | Increase in other assets | | | (199,813 | ) | | | (288,093 | ) | | | (88,547 | ) |
| | | | | | | | | | |
| | | | Net cash used in investing activities | | | (9,941,874 | ) | | | (6,901,591 | ) | | | (16,217,609 | ) |
| | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | |
| | Proceeds from notes payable | | | 295,000 | | | | — | | | | — | |
| | Proceeds from borrowings on long-term debt | | | 5,844,558 | | | | 11,452,861 | | | | 21,749,993 | |
| | Proceeds from issuance of common stock | | | 9,666,147 | | | | 824,234 | | | | 1,947,205 | |
| | Equity issuance costs | | | (319,644 | ) | | | — | | | | — | |
| | Repayment of notes payable | | | (663,540 | ) | | | — | | | | — | |
| | Repayment of long-term debt | | | (8,018,319 | ) | | | (8,359,919 | ) | | | (7,414,285 | ) |
| | | | | | | | | | |
| | | | Net cash provided by financing activities | | | 6,804,202 | | | | 3,917,176 | | | | 16,282,913 | |
| | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 2,324,852 | | | | (139,883 | ) | | | 201,119 | |
| Cash and cash equivalents, beginning of period | | | 727,134 | | | | 867,017 | | | | 665,898 | |
| | | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 3,051,986 | | | $ | 727,134 | | | $ | 867,017 | |
| | | | | | | | | | |
See Notes to Consolidated Financial Statements
F-7
INFINITY, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Supplemental cash flow disclosures: | | | | | | | | | | | | |
| Cash paid for interest, net of amounts capitalized | | $ | 436,380 | | | $ | 1,589,606 | | | $ | 383,449 | |
| Non-cash transactions: | | | | | | | | | | | | |
| Non-cash costs capitalized in the full cost pool for oil and gas properties | | | 1,070,065 | | | | 2,714,974 | | | | 2,056,283 | |
| Property and equipment acquired through capital lease or assumption of debt | | | 195,000 | | | | 967,975 | | | | — | |
| Oil and gas properties acquired through seller financed debt | | | — | | | | 263,381 | | | | 607,236 | |
| Stock based compensation for options and warrants granted in connection with debt, recorded as loan costs | | | — | | | | 5,790,719 | | | | 5,015,490 | |
| Conversion of 8% subordinated convertible notes and accrued interest to common stock | | | 308,282 | | | | 1,478,550 | | | | 2,274,859 | |
| Conversion of 7% subordinated convertible notes and accrued interest to common stack | | | 487,479 | | | | 1,757,016 | | | | — | |
| Issuance of common stock to partially repay related party debt | | | 500,000 | | | | — | | | | — | |
| Issuance of additional notes in lieu of cash interest payment on 7% subordinated convertible notes | | | 795,000 | | | | 379,000 | | | | — | |
| Sale of oil and gas property for note receivable | | | — | | | | — | | | | 1,620,000 | |
| Warrants valuation recorded as offering cost | | | 120,000 | | | | — | | | | — | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Supplemental cash flow disclosures: | | | | | | | | | | | | |
| Cash paid for interest, net of amounts capitalized | | $ | 1,175 | | | $ | 436 | | | $ | 1,590 | |
| Non-cash transactions: | | | | | | | | | | | | |
| Non-cash costs capitalized in the full cost pool for oil and gas properties | | | 764 | | | | 1,070 | | | | 2,715 | |
| Property and equipment acquired through capital lease or assumption of debt | | | 189 | | | | 195 | | | | 968 | |
| Oil and gas properties acquired through seller financed debt | | | — | | | | — | | | | 263 | |
| Options and warrants granted in connection with debt, recorded as loan costs or debt discount | | | 8,828 | | | | 120 | | | | 5,791 | |
| Conversion of subordinated convertible notes and accrued interest to common stock | | | 14,181 | | | | 796 | | | | 3,236 | |
| 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 | | | | 379 | |
See Notes to Consolidated Financial StatementsStatements.
F-7
F-8
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
| |
Note 1 — | Organization and Summary of Significant Accounting Policies |
Note 1 — Organization and Summary of Significant Accounting Policies
The Company
Nature of Operations
Effective September 9, 2005, Infinity, Inc. merged with and into its wholly-owned subsidiary Infinity Energy Resources, Inc., a Delaware corporation, for the purpose of changing its domicile from Colorado to Delaware. As a result of the merger, the legal domicile of Infinity, Inc. was changed to Delaware and its name was changed to Infinity Energy Resources, Inc. At the effective time of the merger, shares of Infinity, Inc. were converted into an equal number of shares of common stock of Infinity Energy Resources, Inc.
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 alsothe acquisition and exploration of oil and gas properties in Nicaragua. In addition, the Company provides oilfield services in theMid-Continent region and in Northeastnortheast Wyoming.
Basis of Presentation
The consolidated financial statements include the accounts of Infinity Energy Resources, Inc. and its wholly-owned subsidiaries, which include Consolidated Oil Well Services, Inc., Infinity Oil and& Gas of Wyoming, Inc., Infinity Oil and Gas of Texas, Inc., Infinity Oil and& Gas of Kansas, Inc., and CIS — Oklahoma, Inc., Infinity Research and Development, Inc., L.D.C. Food Systems, Inc., Consolidated Pipeline Company, Inc., CIS Oil and Gas, Inc., Infinity Nicaragua, Ltd., and Infinity Nicaragua Offshore, Ltd. Infinity Nicaragua, Ltd., and Infinity Nicaragua Offshore, Ltd. own a 98.2% interest in Rio Grande Resources, SA, which is also consolidated. All significant intercompany balances and transactions have been eliminated in consolidation.
Reclassifications
Certain prior period amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to the current year presentation.
| |
| Accounts ReceivableManagement Estimates |
Revenue producing activities are conducted primarily in Kansas, Oklahoma, and Wyoming. The Company grants credit to all qualified customers which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. We continuously monitor collections and payments from our customers and maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that we have identified.
The Company accounts for derivative instruments or hedging activities under the provisions of Statement of Financial Accounting Standards No 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). 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.
The Company periodically enters into fixed price delivery contracts to manage price risk with regard to a portion of its natural gas production. Fixed price delivery contracts that do not meet certain requirements are accounted for using cash flow hedge accounting. Under this method, realized gains and losses on qualifying hedges are recognized in gas revenues when the associated revenue stream occurs and the resulting cash flows are reported as cash flows from operations. To qualify as a hedge, these contracts must be designated as a cash flow hedge and changes in their value must correlate with changes in the price of anticipated future production such that the Company’s exposure to the effects of commodity price is reduced. If the contract is not a hedge, changes in the fair value are recorded in the Company’s statement of operations currently. If a derivative financial instrument, such as the contracts discussed above, is settled before the date of the anticipated
F-9
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
transaction, the Company carries forward the accumulated change in value of the contract and includes it in the measurement of the related transaction.
During the years ended December 31, 2004, 2003 and 2002, the Company had fixed price delivery contracts that were designated as cash flow hedges as follows:
| | | | | | | | | |
| | | MMBtu | | | Amount | |
| Effective Dates | | Per Day | | | Per MMBtu | |
| | | | | | | |
| April 1, 2002 — October 31, 2002 | | | 1,000 | | | $ | 1.80 | |
| October 1, 2002 — September 30, 2003 | | | 1,000 | | | | 2.97 | |
| November 1, 2002 — March 31, 2003 | | | 1,000 | | | | 3.00 | |
| April 1, 2003 — March 31, 2004 | | | 3,500 | | | | 4.71 | |
During 2004, 2003 and 2002, the Company reclassified out of other comprehensive income, income of approximately $155,000, income of approximately $133,000 and losses of approximately $32,000, respectively, on the contracts, which have been included in natural gas revenues in the accompanying consolidated statement of operations and in cash provided by operating activities in the accompanying consolidated statement of cash flows. The fair value of the fixed price delivery contracts was calculated using the twelve month forecasted sales price for the Henry Hub gas delivery point less a historical differential for the actual delivery point and the quantities and prices fixed in the contracts.
During 2004, the Company entered into fixed price delivery contracts for 2,000 MMBtu per day from April 1, 2004 until March 31, 2006. The price for the period April 1, 2004 until March 31, 2005 is $4.40 per MMBtu and the price for the period April 1, 2005 until March 31, 2006 is $4.15 per MMBtu. Sales under these fixed price contracts are accounted for as normal sales agreements under the exemption in SFAS No. 133.
The Company recognizes sales of oil when the product is delivered and recognizes enhancement service revenue when the services are performed. The Company uses the sales method for recording natural gas sales. This method allows for recognition of revenue which may be more or less than the Company’s share of pro-rata production from certain wells. During 2004, 2003 and 2002, there were no material natural gas imbalances.
The Company expenses, on a current basis, recurring costs associated with managing hazardous substances and pollution in ongoing operations. The Company also accrues for costs associated with the remediation of environmental pollution when it becomes probable that a liability has been incurred and its proportionate share of the amount can be reasonably estimated.
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 realizationrealizability 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.
Accounts Receivable
The Company’s revenue producing activities are conducted primarily in Colorado, Kansas, Oklahoma, Texas and Wyoming. The Company grants credit to qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its
F-8
F-10
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
customers and maintains an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified.
Inventories
Inventories, consisting primarily of cement mix, sand, fuel and chemicals, are stated at the lower of cost or market. Cost has been determined on thefirst-in, first-out method.
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.
The Company’s Senior Secured Notes (see Note 6) include certain terms, conditions and features that are separately accounted for as embedded derivatives at estimated fair value. In addition, the related warrants issued with the Senior Secured Notes and non-employee options and warrants are also separately accounted for as freestanding derivatives at estimated fair value. 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, interest rates and the probability of conversion, redemption or exercise, 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. See Note 7.
Property and Equipment
Depreciation and amortization are computed using the straight-line method over the following estimated useful lives:
| | | | | |
Assets | | Useful Lives | |
| | | | |
| Buildings | | | 30 years | |
| Site improvements | | | 15 years | |
| Machinery, equipment and vehicles | | | 5 – 203-20 years | |
| Office furniture and equipment | | | 3 – 103-10 years | |
Long-Lived Assets
Long-lived assets to be held and used in the Company’s business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, the Company records an impairment. No impairments were recorded during the years ended December 31, 2005, 2004 or 2003.
F-9
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Oil and Gas Properties
The Company follows the full cost method of accounting for oilexploration and gas properties.development activities. Accordingly, all costs associated with propertyincurred in the acquisition, exploration, and development activities are capitalized. Explorationof properties (including costs of surrendered and development costs includeabandoned leaseholds, delay lease rentals and dry hole costs, geologicalholes) and geophysical costs, direct overhead related to exploration and development activities,the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paidare capitalized. Overhead related to employees involved in the acquisition, exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities areis also capitalized. The Company capitalized $652,038, $49,221,$884,000, $652,000 and $1,444,238$49,000 of internal costs during the years ended December 31, 2005, 2004 2003 and 2002,2003, 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 Company performs an impairment analysis whenever events or changes in circumstances indicate an asset’s carrying amountceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not be recoverable. Cash flows used in this impairment analysis are determined based upon estimatesexceed 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, andincluding the costs to extract those reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates, depressed oil and gas prices, or the reclassificationeffects of unevaluated costs to costs subject to amortization without a corresponding increase in proved reserves could cause the Company to reduce the carrying amounts of our properties. Under full cost accounting rules, capitalized costs,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 full cost pool,costs being amortized, if any; less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value discounted at ten percent of estimated future net revenue less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related(4) income tax effects. If capitalized costs exceedeffects related to differences in the limit, the excess must be charged to expense. This is referred to as the “full cost ceiling limitation.” The expense may not be reversed in future periods. At the endbook and tax basis of each quarter, a full cost ceiling limitation calculation is made.oil and gas properties.
At December 31, 2004,2005, the carrying amount of oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $8,900,000$13,450,000 based upon aan average natural gas price of approximately $6.07$8.21 per Mcf and an average oil price of approximately $40.25$60.74 per barrel in effect at that date. However, due to significant subsequent price increases to approximately $6.53 per Mcf of gasIn 2004 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. In 2003, the Company also recorded a ceiling writedownwritedowns of $2,975,000.
F-11
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)$4,100,000 and $2,975,000, 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 their relative energy content, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, 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 being 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. AbandonmentAbandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. See Note 17 for additional discussion of unevaluated properties.
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.
F-10
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Asset Retirement Obligations
The SecuritiesCompany 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 Exchange Commission’s full cost accounting rules prohibit recognition of income in current operations for services performed by the Companyequipment, and site restoration on oil and natural gas properties in which the Company has an interest, but rather require amounts to be treatedproperties. Capitalized costs are depleted as a reimbursementcomponent of costs with any excess of fees over costs credited to 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, 2005, 2004 and recognized through lower cost amortization only as production occurs.2003:
| | | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Asset retirement obligations at January 1 | | $ | 635 | | | $ | 521 | | | $ | 448 | |
| Accretion expense | | | 70 | | | | 21 | | | | 17 | |
| Liabilities incurred | | | 51 | | | | 93 | | | | 56 | |
| Liabilities assumed | | | 17 | | | | — | | | | — | |
| Liabilities settled | | | (199 | ) | | | — | | | | — | |
| Revision in estimates | | | 839 | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Asset retirement obligations at December 31 | | | 1,413 | | | | 635 | | | | 521 | |
| Less: current portion of asset retirement obligations | | | (284 | ) | | | — | | | | — | |
| | | | | | | | | | | | | |
| Asset retirement obligations at December 31, less current portion | | $ | 1,129 | | | $ | 635 | | | $ | 521 | |
| | | | | | | | | | | | | |
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. Total interest costs incurred in 2004, 2003 and 2002 were $1,866,104, $1,976,001, and $1,612,469, respectively. Interest costs capitalized in 2005, 2004 and 2003 were $634,589, $382,236,$1,451,000, $635,000 and $1,010,119 for 2004, 2003 and 2002,$382,000, respectively.
Intangible Assets
Long-lived
Intangible assets to be heldconsist principally of loan costs and used ingoodwill. Loan costs are amortized over the Company’s business are reviewed for impairment whenever events or changes in circumstances indicate thatterms of the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the discounted expected future cash flows, the Company records an impairment. No impairment was recorded during 2004, 2003 or 2002.
The Company accounts for transportation costs under Emerging Issues Task Force (“EITF”) 00-10, “Accounting for Shipping and Handling Fees and Costs,” whereby amounts paid for transportation costs are classified as an operating expense and not netted against natural gas revenues.
The Company adopted SFAS No. 142 “Goodwill and Other Intangible Assets,” effective January 1, 2001. As a result, the Company does not amortize goodwill, but instead, reviews goodwill for impairment on at least an annual basis.
Other intangibles are recorded at cost and are amortized on the straight-line basis over the contractual or estimated useful life of the asset, which ranges from one to five yearsdebt instruments using the effective interest method.
F-12
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Goodwill is not amortized, but is reviewed for impairment at least annually. As of December 31, 2005, goodwill was not impaired.
Amortization
The Company capitalizes amortization of loan costs associated with debt obtainedto oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current amortization are capitalized to oil and gas properties.depletion. Amortization of loan costs areis capitalized only for the period that activities are in progress to bring these projects to their intended use. Total loan cost amortization costs capitalized for 2005, 2004 and 2003 was $261,000, $555,000 and 2002$2,715,000, respectively.
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, 2005 and 2004 were $555,375, $2,714,974,immaterial. The Company recognizes sales of oil when title to the product is transferred. The Company recognizes revenue from oilfield services when the services are provided and $2,023,373, respectively (see Note 4collection is reasonably assured.
F-11
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Transportation Costs
The Company accounts for total loantransportation costs under Emerging Issues Task ForceIssue 00-10,Accounting for Shipping and Handling Fees and Costs, whereby amounts paid for transportation are classified as intangibles).operating expenses.
Per Share Information
Basic earnings (loss) per common share areis computed asby dividing net income (loss) dividedearnings from continuing operations by the weighted average number of shares of common sharesstock outstanding during the period.each period, excluding treasury shares. Diluted earnings (loss) per common share areis computed as net income (loss) divided by adjusting the weighted average number of shares of common sharesstock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options, warrants and potential common shares, using the treasury stock method, outstanding during the period.
| |
| Cash and Cash Equivalents |
For purposes of reporting cash flows, cash generally consists 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.convertible debt.
The Company considers all highly liquid investments with an original maturity of three months or less to be a cash equivalent.
Stock Options
The Company applies Accounting Principles Board (“APB”) Opinion No. 25, “AccountingAccounting for Stock Issued to Employees”, and related interpretations in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for options granted to employees under the stock option plans because the fair value of the stock equaled or was less than the option exercise price at the date of grant. Had compensation costs for employee stock options under the Company’s plan been determined based upon the fair value at the grant date for awards under the plan consistent with the methodology prescribed under SFAS No. 123, “AccountingAccounting for Stock-Based Compensation”Compensation, the Company’s net loss and loss per share would have been as follows (see Note 10)8):
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Net loss as reported | | $ | (4,633,400 | ) | | $ | (9,924,880 | ) | | $ | (1,556,866 | ) |
| Deduct: Total stock-based employee compensation expense, determined under fair value based method for all awards, net of tax | | | (1,702,904 | ) | | | (26,244 | ) | | | (2,448,341 | ) |
| | | | | | | | | | |
| Pro forma net loss | | $ | (6,336,304 | ) | | $ | (9,951,124 | ) | | $ | (4,005,207 | ) |
| | | | | | | | | | |
| Basic and diluted loss per share as reported | | $ | (0.49 | ) | | $ | (1.23 | ) | | $ | (0.22 | ) |
| Basic and diluted loss per share-pro forma | | $ | (0.67 | ) | | $ | (1.23 | ) | | $ | (0.56 | ) |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31 | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands,
| |
| | | except per share amounts) | |
| |
| Net loss as reported | | $ | (13,577 | ) | | $ | (4,633 | ) | | $ | (9,925 | ) |
| Deduct: Total stock-based employee compensation expense, determined under fair value based method for all awards, net of tax | | | (3,177 | ) | | | (1,703 | ) | | | (26 | ) |
| | | | | | | | | | | | | |
| Pro forma net loss | | $ | (16,754 | ) | | $ | (6,336 | ) | | $ | (9,951 | ) |
| | | | | | | | | | | | | |
| Basic and diluted loss per share as — reported | | $ | (1.05 | ) | | $ | (0.49 | ) | | $ | (1.23 | ) |
| Basic and diluted loss per share — pro forma | | $ | (1.30 | ) | | $ | (0.67 | ) | | $ | (1.23 | ) |
For options granted during the years ended December 31, 2005, 2004 2003 and 2002,2003, the estimated fair value of the options granted utilizing the Black-Scholes pricing model under the Company’s plan was based on a weighted average risk-free interest raterates of 4.15%, 1.5% and 1.5%, respectively, expected option life of 10 years for 2005 and 2004 and 5 years for 2003, and 2002, expected volatility of approximately 67%, 147%, and 131%, and 117%,respectively, and no expected dividends.
Income Taxes
The Company has adopteduses the disclosure requirementsasset and liability method of SFAS No. 148, “Accountingaccounting for Stock-Based Compensation Transition Disclosure” inincome 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, 2005 and 2004, the Company had recorded a full valuation allowance for its consolidated financial statements. This statement amendsnet deferred tax asset.
F-13
F-12
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
SFAS No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for an entity that voluntarily changes to the fair value method of accounting for stock-based compensation. In addition, SFAS No. 148 amends the disclosure provision of SFAS No. 123 to require more prominent disclosure about the effects of an entity’s accounting policy decisions with respect to stock-based employee compensation on reported net income.
Comprehensive Income (Loss)
In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R, “Share-Based Payment”, which amends SFAS No. 123 and requires companies to recognize in the statement of operations the grant date fair value of stock options and other equity-based compensation to employees for fiscal periods after June 15, 2005.
| |
| Comprehensive Income (Loss) |
The Company has elected to report comprehensive income (loss) in the consolidated statement 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.
Income taxes are provided for the tax effects of the transactions reported in the consolidated financial statements and consist of taxes currently due plus deferred taxes related primarily to temporary differences between the tax and financial basis of property and equipment and other assets, oil and gas properties, and net operating loss carry-forwards using enacted tax rates in effect for the year in which the differences are expected to reverse.
The deferred tax assets and liabilities represent the future tax return consequences of those temporary differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that are not expected to be realized based on available evidence that it is more likely than not to be realized in the form of a deferred tax valuations allowance.
| |
| Asset Retirement Obligations |
Effective January 1, 2003, the Company adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires the Company to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted each period towards its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company reports a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. Upon adoption of SFAS No. 143, the Company recorded a discounted liability of approximately $447,000 for future retirement obligations and increased net oil and gas properties by the same amount. The adoption of SFAS No. 143 had no material effect on earnings in all periods presented. The majority of the asset retirement obligation to be recognized relates to the projected costs to plug and abandon oil and gas wells. Liabilities are also recorded for compressor and field facilities.
F-14
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Recently Issued Accounting Pronouncements
The following table reflects the components of the change in the carrying amount of the asset retirement obligation.
| | | | | | | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Asset retirement obligation at January 1 | | $ | 520,638 | | | $ | 447,357 | |
| Liabilities incurred in the current period | | | 93,349 | | | | 56,008 | |
| Accretion expense | | | 21,036 | | | | 17,273 | |
| | | | | | | |
| Asset retirement obligation at December 31 | | $ | 635,023 | | | $ | 520,638 | |
| | | | | | | |
| |
| Recently Issued Accounting Pronouncements |
In December 2004, the FASB issued SFAS No. 123(R), “Share-BasedShare-Based Payment”, which is a revision of SFAS No. 123, “AccountingAccounting for Stock-Based Compensation”.Compensation. SFAS No. 123(R) is effective for public companies for interim or annual periods beginning after June 15, 2005, supersedes APB Opinion No. 25, “AccountingAccounting for Stock Issued to Employee’s,”Employees, and amends SFAS No. 95, “StatementStatement of Cash Flows.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values, beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged.values. The pro forma disclosures, previously permitted under SFAS No. 123 will no longer will be an alternative to financial statement recognition. SFAS No. 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce the Company’s future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future.
The Company is required to adopt
SFAS No. 123(R) inmust be adopted no later than January 1, 2006 and permits public companies to adopt its third quarterrequirements using one of fiscal 2005, beginning July 1, 2005. Under SFAS No. 123(R), Infinity must determinetwo methods:
| | |
| • | A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date. |
|
| • | A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures. |
The Company adopted the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive options, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock at the beginning of the first quarter of adoptionprovisions of SFAS No. 123(R); on January 1, 2006 using the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. Infinity is evaluating the requirements of SFAS No. 123(R), and expects that themodified prospective method. The adoption of SFAS No. 123(R) will not have a materialhad no impact on consolidatedthe Company’s results of operations and earnings per share asbecause all employee stock options outstanding options areat December 31, 2005 were fully vested. As permitted by SFAS No. 123, through December 31, 2005 the Company accounted for share-based payments to employees using the intrinsic value method prescribed by APB Opinion No. 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. Had the Company adopted SFAS No. 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123 as described in the pro forma disclosures above underStock Options.
In March 2005, the FASB issued FASB Interpretation (“FIN”) 47,Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143. FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The Company adopted the provisions of FIN 47 effective December 2004,31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.
In February 2006, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29, 155,Accounting for Nonmonetary Transactions”.Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140. SFAS No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets155 resolves issues addressed in paragraph 21(b) of APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. SFAS No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows133 Implementation Issue No. D1,Application of the entity are expectedStatement 133 to change significantly as a result of the exchange.Beneficial Interests in Securitized Financial Assets. SFAS No. 153 is155 will become effective for the Company’s fiscal periods beginningyear after JuneSeptember 15, 2005.2006. The Company is currently evaluating the effect that the adoptionimpact of SFAS No. 153 will have on consolidated results of operations and financial condition but does not expect it to have a material impact.
Staff Accounting Bulletin (“SAB”) 106 was released in September 2004. SAB 106 expresses the SEC staff’s views on the interaction of SFAS No. 143 and the full cost method and provides guidance on computing the full cost ceiling as well as depreciation, depletion and amortization. SAB 106 also requires additional
F-15
F-13
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
disclosures regarding how the application of SFAS No. 143 has affected155 will depend on the ceiling testnature and depreciation, depletion and amortization. The Company adopted SAB 106 duringextent of any new derivative instruments entered into after the fourth quarter of 2004 and experienced no significant impact on its depletion or ceiling test calculation.effective date.
| |
Note 2 — | Accounts Receivable |
Note 2 — Accounts Receivable
Accounts receivable consists of the following:
| | | | | | | | | | |
| | | December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Accounts receivable oil field services | | $ | 2,739,816 | | | $ | 1,171,886 | |
| Revenue receivable oil and gas production | | | 722,372 | | | | 652,401 | |
| Other receivables | | | 116,736 | | | | 22,355 | |
| | | | | | | |
| | Total receivables | | | 3,578,924 | | | | 1,846,642 | |
| | Less allowance for doubtful accounts | | | (85,476 | ) | | | (80,000 | ) |
| | | | | | | |
| | Net receivables | | $ | 3,493,448 | | | $ | 1,766,642 | |
| | | | | | | |
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (In thousands) | |
| |
| Accounts receivable oil field services | | $ | 2,771 | | | $ | 2,740 | |
| Revenue receivable oil and gas production | | | 2,004 | | | | 722 | |
| Other receivables | | | 43 | | | | 117 | |
| | | | | | | | | |
| Total receivables | | | 4,818 | | | | 3,579 | |
| Less allowance for doubtful accounts | | | (70 | ) | | | (85 | ) |
| | | | | | | | | |
| Net receivables | | $ | 4,748 | | | $ | 3,494 | |
| | | | | | | | | |
| |
Note 3 — | Property and Equipment |
Note 3 — Property and Equipment
Property and equipment consists of the following:
| | | | | | | | | | |
| | | December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Buildings, site costs and improvements | | $ | 776,517 | | | $ | 2,208,587 | |
| Machinery, equipment, vehicles and aircraft | | | 13,779,444 | | | | 15,758,828 | |
| Office furniture and equipment | | | 257,253 | | | | 276,135 | |
| | | | | | | |
| | Total cost | | | 14,813,214 | | | | 18,243,550 | |
| | Less accumulated depreciation | | | (6,048,887 | ) | | | (8,199,722 | ) |
| | | | | | | |
| | Net property and equipment | | $ | 8,764,327 | | | $ | 10,043,828 | |
| | | | | | | |
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (In thousands) | |
| |
| Buildings, site costs and improvements | | $ | 1,601 | | | $ | 777 | |
| Machinery, equipment, vehicles and aircraft | | | 16,610 | | | | 13,569 | |
| Office furniture and equipment | | | 548 | | | | 467 | |
| | | | | | | | | |
| Total cost | | | 18,759 | | | | 14,813 | |
| Less accumulated depreciation | | | (7,270 | ) | | | (6,049 | ) |
| | | | | | | | | |
| Net property and equipment | | $ | 11,489 | | | $ | 8,764 | |
| | | | | | | | | |
Intangibles
Depreciation expense related to property and equipment for the years ended December 31, 2005, 2004 and 2003 was $1,468,000, $1,617,000 and $1,580,000, respectively.
Note 4 — Intangible Assets
Intangible assets consist of the following:
| | | | | | | | | |
| | | December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Loan costs | | $ | 4,032,489 | | | $ | 8,812,297 | |
| Non-compete | | | 300,000 | | | | 300,000 | |
| Goodwill | | | 225,000 | | | | 225,000 | |
| Other | | | 55,870 | | | | 55,870 | |
| | | | | | | |
| | | | 4,613,359 | | | | 9,393,167 | |
| Less accumulated amortization | | | (3,116,283 | ) | | | (5,440,178 | ) |
| | | | | | | |
| Net intangibles | | $ | 1,497,076 | | | $ | 3,952,989 | |
| | | | | | | |
During 2004, 2003 and 2002, the Company recorded amortization expense related to intangibles, excluding amounts capitalized, of $2,100,351, $6,210,738, and $241,272, respectively. Of the total amortization expense
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (In thousands) | |
| |
| Loan costs | | $ | 2,889 | | | $ | 4,032 | |
| Goodwill | | | 225 | | | | 225 | |
| Other | | | 20 | | | | 56 | |
| | | | | | | | | |
| | | | 3,134 | | | | 4,313 | |
| Less accumulated amortization | | | (620 | ) | | | (2,816 | ) |
| | | | | | | | | |
| Net intangible assets | | $ | 2,514 | | | $ | 1,497 | |
| | | | | | | | | |
F-16
F-14
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
related to intangibles,
During the years ended December 31, 2005, 2004 and 2003, the Company recorded amortization related to intangible assets of loan costs of $2,097,329, $6,200,633,$1,735,000, $2,100,000 and $234,680,$6,211,000, respectively.
Loan costs
Note 5 — Accrued Liabilities
Accrued liabilities consist of the following at December 31, 2004:following:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated | | | |
| | | Non-cash | | | Cash | | | Total | | | Amortization | | | Net | |
| Description of Notes or Agreement | | Loan Costs | | | Loan Costs | | | Loan Costs | | | 12/31/2004 | | | Book Value | |
| | | | | | | | | | | | | | | | |
| 8% subordinated convertible notes | | $ | 1,375,464 | | | $ | 51,159 | | | $ | 1,426,623 | | | $ | (1,270,968 | ) | | $ | 155,655 | |
| 7% subordinated convertible notes | | | 2,178,944 | | | | 72,605 | | | | 2,251,549 | | | | (1,384,924 | ) | | | 866,625 | |
| $25,000,000 development credit facility | | | — | | | | 166,506 | | | | 166,506 | | | | (63,944 | ) | | | 102,562 | |
| Various other financing arrangements | | | — | | | | 187,811 | | | | 187,811 | | | | (8,333 | ) | | | 179,478 | |
| | | | | | | | | | | | | | | | |
| Total | | $ | 3,554,408 | | | $ | 478,081 | | | $ | 4,032,489 | | | $ | (2,728,169 | ) | | $ | 1,304,320 | |
| | | | | | | | | | | | | | | | |
Substantially all of the net book value of loan costs at December 31, 2004 will expensed in 2005 as a result of debt repayments or conversion.
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (In thousands) | |
| |
| Production taxes payable — current portion | | $ | 516 | | | $ | 236 | |
| Oil and gas revenue payable to oil and gas property owners | | | 680 | | | | 131 | |
| Accrued interest | | | 247 | | | | 223 | |
| Accrued drilling costs | | | 2,918 | | | | 2,650 | |
| Other accrued liabilities | | | 1,953 | | | | 1,257 | |
| | | | | | | | | |
| | | $ | 6,314 | | | $ | 4,497 | |
| | | | | | | | | |
Note 5 — Notes Receivable
The Company received a three year note for $1,620,000 when it sold its Kansas producing properties in May 2002. The note had an outstanding balance as of December 31, 2004 and 2003 of approximately $1,581,000 and $1,597,000, respectively. Interest accrues on the note at 8% per annum with quarterly payments, based on a 30 year amortization, of $35,000, including interest, due on the first day of November, February, May and August with a balloon payment due May 1, 2005. The note is collateralized by the oil producing properties that were sold.
Note 6 — Accrued LiabilitiesDebt
Accrued liabilities consist of:
| | | | | | | | | |
| | | December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Production taxes payable — current portion | | $ | 235,919 | | | $ | 282,752 | |
| Oil and gas revenue payable to oil and gas property owners | | | 130,308 | | | | 158,318 | |
| Accrued interest | | | 223,195 | | | | 223,060 | |
| Other accrued liabilities, principally accrued drilling costs | | | 3,906,990 | | | | 302,639 | |
| | | | | | | |
| | | $ | 4,496,412 | | | $ | 966,769 | |
| | | | | | | |
Debt consists of the following:
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (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), with interest at 7.0% due quarterly. Annual principal payments equal to 5% of the current outstanding principal due each February until paid in full. The note was settled in February 2006 in connection with the sale of the related aircraft. See Note 16 | | | 2,203 | | | | 2,326 | |
| 8% Subordinated Convertible Notes | | | — | | | | 2,493 | |
| 7% Subordinated Convertible Notes | | | — | | | | 11,517 | |
| $25 million Development Credit Facility | | | — | | | | 5,000 | |
| Various revolving credit and term loans | | | — | | | | 3,582 | |
| Other | | | 376 | | | | 706 | |
| | | | | | | | | |
| | | | 40,162 | | | | 25,624 | |
| Less current portion | | | (288 | ) | | | (284 | ) |
| | | | | | | | | |
| Long-term debt | | $ | 39,874 | | | $ | 25,340 | |
| | | | | | | | | |
F-17
F-15
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note 7 — Long-Term Debt and Convertible Notes Payable
Long term debt consists of the following:
| | | | | | | | | |
| | | December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| 8% subordinated convertible notes payable, due June 13, 2006 | | $ | 2,493,000 | | | $ | 2,793,000 | |
| 7% subordinated convertible notes payable, due April 22, 2007 | | | 11,516,698 | | | | 11,184,000 | |
| $25,000,000 development credit facility with U.S. Bank, repaid in full and terminated on January 13, 2005 | | | 5,000,000 | | | | 5,500,000 | |
| Bridge loan with related party; interest at 7%, repaid in full during 2004 | | | — | | | | 3,000,000 | |
| Note payable to seller (for a 50% interest in an airplane), with interest at 7.25% due on a quarterly basis. The Company is required to make annual principal payments equal to 5% of the current outstanding principal until paid in full. The seller can call the note if the bank calls its note for the original purchase of the airplane. The note is collateralized by the Company’s 50% interest in the airplane with a net book value of $2,167,717 | | | 2,326,201 | | | | 2,326,201 | |
| Various revolving credit and term loans with LaSalle Bank with interest at prime plus 1.25%, repaid in full and terminated on January 13, 2005 | | | 3,582,533 | | | | 1,391,505 | |
| Various other collateralized notes repaid in full and terminated no later than January 31, 2005 | | | 546,058 | | | | 1,797,943 | |
| | | | | | | |
| | | $ | 25,464,490 | | | $ | 27,992,649 | |
| | | | | | | |
Maturities of long-term debt are as follows:
| | | | | |
| | | Long-Term Debt | |
| Year Ending December 31, | | and Convertible Notes | |
| | | | |
| 2005 | | $ | 124,354 | |
| 2006 | | | 2,603,495 | |
| 2007 | | | 11,621,668 | |
| 2008 | | | 99,721 | |
| 2009 | | | 9,222,924 | |
| Thereafter | | | 1,792,328 | |
| | | | |
| | | $ | 25,464,490 | |
| | | | |
Certain subordinated notes have converted in 2005, as discussed below. However, the table above reflects the maturity of the convertible notes and the note payable to seller in accordance with their stated terms. All other borrowings under secured credit facilities and revolving and term loans were paid in full in January 2005 with proceeds from the
| | | | | |
Year Ending December 31, | | (In thousands)
| |
| |
| 2006 | | $ | 288 | |
| 2007 | | | 88 | |
| 2008 | | | — | |
| 2009 | | | 37,583 | |
| 2010 | | | — | |
| Thereafter | | | 2,203 | |
| | | | | |
| | | $ | 40,162 | |
| | | | | |
Senior Secured Notes Facility discussed in Note 16 and the maturities for that debt have been presented in the financial statements in accordance with the terms of the Notes due January 13, 2009.
| |
| Convertible Subordinated Notes |
| |
| 8% Convertible Subordinated Notes |
Effective June 13, 2001, the Company sold $6,475,000 in 8% Subordinated Convertible Notes in a private placement in which C.E. Unterberg, Towbin acted as the placement agent. A director of the Company was an officer with C.E. Unterberg, Towbin. Interest on the notes accrued at a rate of 8% per annum and was payable
F-18
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
in arrears on each December 15 and June 15. The notes were originally convertible to one share of common stock at $5 per share and matured on June 13, 2006.
The Company incurred costs of $501,906 associated with the placement, which has been capitalized as loan costs and is being amortized using the effective interest method. The Company also issued warrants to purchase 220,000 shares of common stock at $5.99. The Company capitalized additional loan costs of $924,717 related to the fair value of the warrants as determined using the Black-Scholes pricing model assuming a five year life, weighted average risk-free interest rate of 8%, expected volatility of 80.66% and no expected dividend yield.
As the conversion feature of the convertible notes was below the market value of the stock on the date of issue, the Company recorded a discount of $1,165,500 related to the intrinsic value of the beneficial conversion feature. The notes were immediately convertible and therefore, the discount was immediately amortized. The Company capitalized the amortization of the beneficial conversion feature into oil and gas properties not subject to amortization as the debt was issued in order to continue exploration and development of projects that were not currently subject to amortization, and was not used for general operating purposes.
During 2004, 2003 and 2002, the holders of $300,000, $1,450,000 and $2,232,000 of 8% subordinated convertible notes converted the debt and accrued interest into 63,179, 295,689 and 454,974 shares of the Company’s common stock, respectively.
On January 13, 2005, the Company called for redemption all of the remaining 8% subordinated convertible notes outstanding on February 28, 2005. During January and February 2005, the holders of all $2,493,000 of 8% subordinated convertible notes converted the debt and accrued interest into 517,296 shares of the Company’s common stock.
| |
| 7% Convertible Subordinated Notes |
Effective April 22, 2002, the Company sold $12,540,000 in 7% Subordinated Convertible Notes in a private placement in which C.E. Unterberg, Towbin acted as the placement agent. A director of the Company was an officer with C.E. Unterberg, Towbin. In addition, to the extent a holder of the Company’s 8% Subordinated Convertible Notes converted any of their notes and the accrued interest to stock, and purchased 7% Subordinated Convertible Notes, these parties would be related parties. Interest on the 7% subordinated notes accrues at a rate of 7% per annum and is payable in arrears on each April 15 and October 15. The Company can elect to pay the accrued interest in cash or in the form of additional notes issued in increments of $1,000 with residual interest due in cash. In 2004 and 2003, the Company issued $795,000 and $379,000 in new notes as payment for interest due. The notes were originally convertible to one share of common stock at $8.625 per share and mature on April 22, 2007. The loan indenture for the 7% notes contains anti-dilution provisions that require the Company to adjust the conversion price of the notes if stock is sold at a price less than the conversion price. At December 31, 2004, the conversion price was $7.766 per share. In connection with the adjustment of the conversion price, the Company recorded a charge of approximately $354,000 related to the additional shares issuable at the new conversion price.
The notes are subordinated to substantially all the Company’s other existing or future notes payable, capital leases, debentures, bonds or other such securities.
The Company incurred costs of $865,505 associated with the issuance of the 7% convertible notes, which have been capitalized as loan costs and are being amortized using the effective interest method. The Company also issued warrants to purchase 200,000 shares of common stock at $9.058. The Company capitalized additional loan costs of $1,386,044 related to the fair value of the warrants as determined using the Black-Scholes pricing model assuming a five year life, weighed average risk-free interest rate of 7%, expected volatility of 98.30% and no expected dividend yield.
F-19
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During 2004 and 2003, the holders of $462,302 and $1,735,000 of the 7% subordinated convertible notes converted the debt and accrued interest into 62,685 and 203,712 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. During 2005, through March 23, the holders of $5,950,538 of 7% subordinated convertible notes at December 31, 2004 have converted the debt and accrued interest into 783,779 shares of the Company’s common stock.
| |
| $25,000,000 Development Credit Facility |
In September 2003, the Company established a Secured Revolving Borrowing Base Credit Facility (“Facility”) with a bank. Interest on the amounts outstanding accrued at prime rate plus 1.0%. The Company incurred $110,000 in loan costs and approximately $57,000 in legal costs to establish the facility. These costs were capitalized as loan costs and amortized using the effective interest method. The facility was repaid in full with proceeds from the Senior Secured Notes Facility discussed in Note 16 to the Consolidated Financial Statements and terminated on January 13, 2005.
| |
| Bridge Loan and Related Agreements — Related Party |
On November 25, 2002, the Company obtained a $3,000,000 one year bridge loan from a related party with an annual interest rate at Wall Street prime plus 1.0%. In March 2003, the note was extended to January 2004. In May 2003, the note was amended to extend the maturity to January 30, 2005. In June 2003, the loan agreement was amended to waive a portion of the accelerated payment requirements and to increase the interest rate to 7%. The Company also entered into a consulting agreement with the related party in June 2003 under which the related party would facilitate a $3,850,000 bridge loan that was obtained and repaid in 2003 and other future financings, if any.
The table below sets forth information about options that were granted in conjunction with these transactions. All of the options issued were valued using the Black-Scholes pricing model assuming a five year life, weighted average risk free interest rate of 1.5%, expected volatility rates between 125% and 132% and no expected dividend yield. The option value was capitalized as loan costs and was amortized using the effective interest method. The amortization is treated as interest in the Company’s consolidated statement of operations with a portion capitalized to the non-producing properties developed with the proceeds of the loan.
The following is a summary of the options granted in connection with the loan and related agreements:
| | | | | | | | | | | | | |
| | | Options | | | Option | | | Loan | |
| Date of Grant | | Granted | | | Price | | | Costs | |
| | | | | | | | | | |
| November 25, 2002 | | | 320,000 | | | $ | 8.75 | | | $ | 2,281,718 | |
| May 23, 2003 | | | 150,000 | | | | 8.75 | | | | 730,130 | |
| June 18, 2003 | | | 125,000 | | | | 8.75 | | | | 642,841 | |
| June 26, 2003 | | | 225,000 | | | | 8.75 | | | | 1,120,358 | |
| | | | | | | | | | |
| | | | 820,000 | | | | | | | $ | 4,775,047 | |
| | | | | | | | | | |
During 2004, the Company repaid the loan balance outstanding with $2,500,000 in cash and the issuance of 125,000 shares of common stock valued at $4.00 per share.
| |
| Revolving Credit and Term Loans |
Effective July 9, 2004, Consolidated borrowed $5,400,000 under an amended credit facility with LaSalle Bank. The amended facility required monthly payments of $113,493 plus interest through November 2007,
F-20
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
with a final payment of the remaining balance of the note due December 31, 2007. Amounts outstanding accrued interest at the prime rate plus 1.25% per annum. The credit facility was repaid in full with proceeds from the Senior Secured Notes Facility discussed in Note 16 to the Consolidated Financial Statements and terminated on January 13, 2005.
In 2003, the Company issued 201,000 five year options and 462,500 five year warrants to purchase common stock at $8.75 per share and granted a 4% over-riding royalty in certain producing properties when it obtained three bridge loans totaling $5,900,000 with interest rates ranging from 2% per month to 12% per year. The Company capitalized loan costs of $3,297,390 for the options and warrants and $1,250,000 based on the estimated fair value for the 4% over-riding royalty conveyed. The Company used the Black-Scholes pricing model assuming a five year life, weighted average risk-free interest rates of 1.5% to 4%, expected volatility between 126.11% and 131.96% and no expected dividend yield to calculate the fair value of the options and warrants at the date of grant. The Company repaid all of the loans during 2003 and all of the loan costs were fully amortized during the year.
Note 8 — Stockholders’ Equity
In May 2002, the Company effected a 2:1 stock split effective May 13, 2002. All shares and per share amounts have been restated to give effect to the stock split.
| |
| Private Institutional Placements of Equity |
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 $319,644.
| |
| Warrants and Options to Non-Employees |
The Company, in conjunction with a public stock offering in September 1988, issued Class A and Class B warrants to purchase 425,918 shares of common stock. The 223,496 Class A warrants have expired. During 2002, 163,264 shares of common stock were issued upon the exercise of Class B warrants for proceeds of $977,911. The remaining 39,158 Class B warrants expired in June 2002.
During 2001, in connection with the sale of $6,475,000 8% subordinated convertible notes; the Company granted 220,000 warrants to purchase the Company’s common stock at $5.99 per share. During February 2005, all of these warrants were exercised.
During 2002, in connection with the sale of $12,540,000, 7% subordinated convertible notes; the Company granted 200,000 warrants to purchase the Company’s common stock at $9.058 per share. The warrants expire in April 2007 (see Note 7).
In connection with obtaining $5,000,000 of bridge loans in March and November 2002, the Company granted five year options to purchase the Company’s common stock; 250,000 at $7.34 and 320,000 at $8.75 per share (see Note 7). Subsequent to December 31, 2004 and through March 23, 2005, 77,850 of the $7.34 options and 191,000 of $8.75 options were exercised.
During 2003, in connection with the issuance of $1,000,000 of bridge notes, which were paid in full in 2003, the Company granted 212,500 warrants to purchase the Company’s common stock at $8.75 per share. The warrants expire in April 2008 (see Note 7). During February 2005, warrants on 8,000 shares were exercised under cashless exercise provisions resulting in the issuance of 2,257 shares of common stock.
F-21
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During 2003, in connection with the issuance of $3,850,000 in bridge notes which were paid in full in 2003, the Company granted 250,000 warrants to purchase the Company’s common stock at $8.75 per share. The warrant agreement contains anti-dilution provisions that require the Company to adjust the exercise price and change the number of warrants outstanding if the Company sells stock at less than the exercise price. During January and November 2004, the warrants were increased by 27,746, to 277,746 warrants with an exercise price of $7.88 per share and the associated value of approximately $120,000 was recorded as offering costs. The warrants expire July 2, 2008 (see Note 7).
In connection with obtaining $1,050,000 of bridge loans in January and April of 2003 (which were paid in full during 2003), the amendments of an existing $3,000,000 loan agreement, and a consulting contract to assist with the facilitation of a $3,850,000 loan agreement, the Company granted options to purchase the Company’s common shares at $8.75 per share (see Note 7).
A summary of warrant and option activity with non-employees is as follows:
| | | | | | | | | | | |
| | | | | Warrant/Option | | Weighted Average | |
| | | Number of Shares | | | Price Per Share | | Price Per Share | |
| | | | | | | | | |
| Outstanding, December 31, 2001 | | | 462,422 | | | $3.22 - $6.00 | | $ | 5.75 | |
| Granted | | | 770,000 | | | 7.34 - 9.06 | | | 8.37 | |
| Canceled or forfeited | | | (39,158 | ) | | 6.00 | | | 6.00 | |
| Exercised | | | (163,264 | ) | | 6.00 | | | 6.00 | |
| | | | | | | | | |
| Outstanding, December 31, 2002 | | | 1,030,000 | | | 3.22 - 9.06 | | | 7.66 | |
| Granted | | | 1,163,500 | | | 8.75 | | | 8.75 | |
| Exercised | | | (83,350 | ) | | 7.34 | | | 7.34 | |
| | | | | | | | | |
| Outstanding, December 31, 2003 | | | 2,110,150 | | | 3.22 - 9.06 | | | 8.27 | |
| Granted | | | 47,746 | | | 7.88 - 8.75 | | | 8.24 | |
| | | | | | | | | |
| Outstanding, December 31, 2004 | | | 2,157,896 | | | $3.22 - $9.06 | | $ | 8.17 | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | Number | | | Weighted Average | | | | | Number | | | |
| Range of | | Outstanding at | | | Remaining | | | Weighted Average | | | Exercisable at | | | Weighted Average | |
| Exercise Prices | | December 31, 2004 | | | Contractual Life | | | Exercise Price | | | December 31, 2004 | | | Exercise Price | |
| | | | | | | | | | | | | | | | |
| $3.22 | | | 40,000 | | | | 1 years | | | $ | 3.22 | | | | 40,000 | | | $ | 3.22 | |
| $5.99 | | | 220,000 | | | | 2 years | | | $ | 5.99 | | | | 220,000 | | | $ | 5.99 | |
| $7.34 - 9.06 | | | 686,650 | | | | 3 years | | | $ | 8.50 | | | | 686,650 | | | $ | 8.50 | |
| $7.88 - 8.75 | | | 1,191,246 | | | | 4 years | | | $ | 8.55 | | | | 1,191,246 | | | $ | 8.55 | |
| $8.75 | | | 20,000 | | | | 5 years | | | $ | 8.75 | | | | 20,000 | | | $ | 8.75 | |
| | | | | | | | | | | | | | | | |
| | | | 2,157,896 | | | | | | | | | | | | 2,157,896 | | | | | |
| | | | | | | | | | | | | | | | |
The following is the weighted average fair value of warrants and options granted to non-employees:
| | | | | |
| | | Weighted Average | |
| Period Ending December 31, | | Fair Value | |
| | | | |
| 2002 | | $ | 6.51 | |
| 2003 | | $ | 4.98 | |
| 2004 | | $ | 4.80 | |
| |
| Options Under Employee Option Plans |
The Company has adopted stock option plans containing both incentive and non-statutory stock options. All options allow for the purchase of common stock at prices not less than the fair market value of such stock
F-22
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
at the date of grant. If the optionee owns more than 10% of the total combined voting power of all classes of the Company’s stock, the exercise price can not be less than 110% of the fair market value of such stock at the date of grant.
Options granted under the plans become exercisable immediately or as directed by the Board of Directors and generally expire five or ten years after the date of grant, unless the employee owns more than 10% of the total combined voting power of all classes of the Company’s stock, in which case they must be exercised within five years of the date of grant. Pursuant to the plans, an aggregate of 2,338,047 options were available for grant. The Company granted 403,750, 10,000, and 345,000 options to employees under the Plans during 2004, 2003 and 2002, respectively. At December 31, 2004, there were 195,881 shares remaining available under the plans. During February 2005, the Company granted ten-year options on 165,000 shares at an exercise price of $8.50 per share.
A summary of stock option activity is as follows:
| | | | | | | | | | | |
| | | | | Option Price | | Weighted Average | |
| | | Number of Shares | | | Per Share | | Price Per Share | |
| | | | | | | | | |
| Outstanding, December 31, 2001 | | | 1,049,600 | | | $1.50 - $5.00 | | $ | 3.30 | |
| Granted | | | 345,000 | | | 7.00 - 8.70 | | | 8.70 | |
| Canceled or forfeited | | | (6,200 | ) | | 3.00 - 5.00 | | | 3.59 | |
| Exercised | | | (247,500 | ) | | 1.50 - 5.00 | | | 1.93 | |
| | | | | | | | | |
| Outstanding, December 31, 2002 | | | 1,140,900 | | | 1.50 - 8.70 | | | 5.23 | |
| Granted | | | 10,000 | | | 8.75 | | | 8.75 | |
| Canceled or forfeited | | | (61,781 | ) | | 3.82 - 8.70 | | | 7.28 | |
| Exercised | | | (62,819 | ) | | 1.50 - 5.00 | | | 3.38 | |
| | | | | | | | | |
| Outstanding, December 31, 2003 | | | 1,026,300 | | | 1.50 - 8.75 | | | 5.25 | |
| Granted | | | 403,750 | | | 4.26 | | | 4.26 | |
| Canceled or forfeited | | | (118,500 | ) | | 3.00 - 8.75 | | | 7.22 | |
| Exercised | | | (146,300 | ) | | 1.50 - 5.00 | | | 2.92 | |
| | | | | | | | | |
| Outstanding, December 31, 2004 | | | 1,165,250 | | | $1.50 - $8.70 | | $ | 5.00 | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | Number | | | Weighted Average | | | | | Number | | | |
| Range of | | Outstanding at | | | Remaining | | | Weighted Average | | | Exercisable at | | | Weighted Average | |
| Exercise Prices | | December 31, 2004 | | | Contractual Life | | | Exercise Price | | | December 31, 2004 | | | Exercise Price | |
| | | | | | | | | | | | | | | | |
| $1.50 | | | 111,000 | | | | 1 year | | | $ | 1.50 | | | | 111,000 | | | $ | 1.50 | |
| $3.00-3.82 | | | 183,000 | | | | 1 year | | | $ | 3.81 | | | | 183,000 | | | $ | 3.81 | |
| $5.00 | | | 264,000 | | | | 2 years | | | $ | 5.00 | | | | 264,000 | | | $ | 5.00 | |
| $5.00 | | | 6,000 | | | | 3 years | | | $ | 5.00 | | | | 6,000 | | | $ | 5.00 | |
| $8.70 | | | 237,500 | | | | 3 years | | | $ | 8.70 | | | | 237,500 | | | $ | 8.70 | |
| $4.26 | | | 10,000 | | | | 5 years | | | $ | 4.26 | | | | 10,000 | | | $ | 4.26 | |
| $4.26 | | | 353,750 | | | | 10 years | | | $ | 4.26 | | | | 353,750 | | | $ | 4.26 | |
| | | | | | | | | | | | | | | | |
| | | | 1,165,250 | | | | | | | | | | | | 1,165,250 | | | | | |
| | | | | | | | | | | | | | | | |
F-23
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following is the weighted average fair value of warrants and options granted to employees:
| | | | | |
| | | Weighted Average | |
| Period Ending December 31, | | Fair Value | |
| | | | |
| 2002 | | $ | 7.10 | |
| 2003 | | $ | 5.25 | |
| 2004 | | $ | 4.22 | |
Subsequent to December 31, 2004, and through March 23, 2005, options on 62,700 shares were exercised for proceeds of approximately $222,000.
The Company granted 177,500 options to employees outside its stock option plans prior to March 31, 2001 with exercise prices ranging from $1.55 to $4.00 and a weighted average price per share of $2.76. These options were exercised during 2002.
Note 9 — Income Taxes
The provision for income taxes consists of the following:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Current income tax expense | | $ | — | | | $ | — | | | $ | — | |
| Deferred income tax benefit | | | (1,784,000 | ) | | | (4,003,321 | ) | | | (1,226,874 | ) |
| Change in valuation allowance and other | | | 1,784,000 | | | | 4,003,321 | | | | 82,846 | |
| | | | | | | | | | |
| Total income tax benefit | | $ | — | | | $ | — | | | $ | (1,144,028 | ) |
| | | | | | | | | | |
The effective income tax rate varies from the statutory federal income tax rate as follows:
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Federal income tax rate | | | (34 | )% | | | (34 | )% | | | (34 | )% |
| State income tax rate | | | (6 | ) | | | (6 | ) | | | (6 | ) |
| Other temporary and permanent differences | | | — | | | | — | | | | 1 | |
| Change in valuation allowance and other | | | 40 | | | | 40 | | | | (3 | ) |
| | | | | | | | | | |
| Effective tax rate | | | 0 | % | | | 0 | % | | | (42 | )% |
| | | | | | | | | | |
F-24
INFINITY, 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, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Deferred tax assets | | | | | | | | |
| | Accruals and other | | $ | 132,000 | | | $ | 741,000 | |
| | Net operating loss carry-forward | | | 10,387,000 | | | | 9,551,000 | |
| | | | | | | |
| | Gross deferred tax assets | | | 10,519,000 | | | | 10,292,000 | |
| | | | | | | |
| Deferred tax liabilities | | | | | | | | |
| | Property and equipment | | | 4,694,000 | | | | 4,872,000 | |
| | | | | | | |
| | Gross deferred tax liabilities | | | 4,694,000 | | | | 4,872,000 | |
| | | | | | | |
| | Net deferred tax asset | | | 5,825,000 | | | | 5,420,000 | |
| | | Less valuation allowance | | | (5,825,000 | ) | | | (5,420,000 | ) |
| | | | | | | |
| | Deferred tax asset | | $ | — | | | $ | — | |
| | | | | | | |
For income tax purposes, the Company has approximately $26,979,000 of net operating loss carry-forwards expiring from 2015 through 2024.
During 2004, 2003 and 2002, the Company realized certain tax benefits related to stock option plans in the amounts of $172,000, $164,000 and $232,000, 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.
The Company has provided for a valuation allowance of $5,825,000 due to the uncertainty of realizing the tax benefits from its net operating loss carry-forwards.
Note 10 — Commitments and Contingencies
In June 2001, the Company entered into a long-term gas gathering contract, which expires in December 2008. This contract was amended April 4, 2003. Under the amended contract, the Company will pay gas gathering fees per thousand cubic feet (“Mcf”) delivered. The Company is obligated to pay a fee of $.40 per Mcf on the first 7,500,000 Mcf and $.25 per Mcf thereafter. Additionally, the Company has an annual volume commitments starting September 1, 2001. The Company’s minimum volume for (i) Year one 600,000 Mcf, (ii) Year two 1,600,000 Mcf, (iii) Year three 2,000,000 Mcf, (iv) Year four 1,800,000 Mcf, and (v) Year five 1,500,000 Mcf. If the Company exceeds the minimum in any year, the excess reduces the following year’s commitment. If the Company does not meet the minimum in any year, the shortfall is added to the following years and at the end of the three years, the Company was to pay for any shortfall. Through December 31, 2004, the Company had delivered approximately 3,137,000 Mcf. While the Company has failed to deliver the volumes required under the contract, the pipeline operator has also not provided the compression and gathering capabilities it was required to provide under the contract. Management has received a verbal commitment from the operator that the volume commitments will be adjusted and management does not believe there will be a contract shortfall under the renegotiated volumes and therefore, anticipates no additional costs under the contract.
F-25
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We have certain lease agreements for the use of office space. The terms of the various leases extend through September 2009. The following is a schedule by year of future minimum lease obligations under operating lease arrangements at December 31, 2004:
| | | | | |
| Year Ending December 31, | | |
| | | |
| 2005 | | $ | 122,413 | |
| 2006 | | | 111,795 | |
| 2007 | | | 87,743 | |
| 2008 | | | 18,675 | |
| 2009 | | | 14,175 | |
| | | | |
| | | $ | 354,801 | |
| | | | |
Rental expense for these and other leases was $133,524, $142,926 and $103,824 for the years ended December 31, 2004, 2003 and 2002, respectively.
| |
| Financial Consulting Agreement |
In July 2003 the Company entered into an eighteen month financial consulting agreement with a related party. The Company issued options to purchase 125,000 shares of common stock that were valued at approximately $1,094,000 using the Black-Scholes valuation model, as compensation for entering into the agreement (see Note 7.) The related party helped facilitate the $3,850,000 bridge loan that was obtained in July 2003.
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.
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.
| |
| Fixed Price Delivery Contracts |
The Company entered into fixed price delivery contracts for natural gas from April 1, 2004 through March 31, 2006. See Note 1.
Note 11 — Retirement Plan
The Company has a 401(k) plan covering substantially all of the employees of the oil field services subsidiary. There were no Company contributions made to the plan during 2003 and 2002. Effective January 1, 2004, the Company began matching, dollar for dollar, employee contributions up to 4% of gross pay. The Company expensed $111,739 of such contributions during 2004.
F-26
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note 12 — Industry Segments
The Company reports segment information in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”, which requires disclosure of information related to certain operating segments of the Company.
The Company’s operations have been classified into two industry segments: (i) Oil Field Services; and (ii) Oil and Gas Production. The Oil Field Services segment of the Company is directed at services associated with the drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, nitrogen pumping and water hauling and has operations in Kansas, Oklahoma, and Wyoming. The Oil and Gas Production segment of the Company is engaged in the acquisition, exploration, development and production of natural gas and crude oil in Colorado, Texas and Wyoming.
The Oil Field Services segment had eliminated inter-company sales of approximately $2,100,000 in 2002 and less than $20,000 during 2003. There were no such sales in 2004.
| | | | | | | | | | | | | | | | | |
| | | Oil Field | | | Oil & Gas | | | Corporate and | | | |
| | | Services | | | Production | | | Other | | | Total | |
| | | | | | | | | | | | | |
Revenue | | | | | | | | | | | | | | | | |
| December 31, 2002 | | $ | 8,570,631 | | | $ | 2,367,713 | | | $ | — | | | $ | 10,938,344 | |
| December 31, 2003 | | | 11,634,457 | | | | 6,589,281 | | | | — | | | | 18,223,738 | |
| December 31, 2004 | | | 14,720,979 | | | | 6,267,453 | | | | — | | | | 20,988,432 | |
Depreciation, depletion, amortization and accretion | | | | | | | | | | | | | | | | |
| December 31, 2002 | | | 1,485,495 | | | | 273,936 | | | | 23,155 | | | | 1,782,586 | |
| December 31, 2003 | | | 1,420,952 | | | | 1,561,247 | | | | 92,048 | | | | 3,074,247 | |
| December 31, 2004 | | | 1,450,450 | | | | 3,611,056 | | | | 136,475 | | | | 5,197,981 | |
Ceiling write-down | | | | | | | | | | | | | | | | |
| December 31, 2002 | | | — | | | | — | | | | — | | | | — | |
| December 31, 2003 | | | — | | | | 2,975,000 | | | | — | | | | 2,975,000 | |
| December 31, 2004 | | | — | | | | 4,100,000 | | | | — | | | | 4,100,000 | |
Operating income (loss) | | | | | | | | | | | | | | | | |
| December 31, 2002 | | | 37,285 | | | | (299,079 | ) | | | (1,670,865 | ) | | | (1,932,659 | ) |
| December 31, 2003 | | | 1,411,218 | | | | (1,629,866 | ) | | | (2,061,353 | ) | | | (2,280,001 | ) |
| December 31, 2004 | | | 2,669,319 | | | | (4,823,147 | ) | | | (2,144,479 | ) | | | (4,298,307 | ) |
Total assets, net | | | | | | | | | | | | | | | | |
| December 31, 2003 | | | 9,069,144 | | | | 40,220,115 | | | | 5,977,019 | | | | 55,266,278 | |
| December 31, 2004 | | | 10,972,094 | | | | 48,001,256 | | | | 5,074,913 | | | | 64,048,263 | |
Capital expenditures | | | | | | | | | | | | | | | | |
| December 31, 2002 | | | 1,561,357 | | | | 14,695,044 | | | | 865,505 | | | | 17,121,906 | |
| December 31, 2003 | | | 459,820 | | | | 6,076,125 | | | | 197,567 | | | | 6,733,512 | |
| December 31, 2004 | | | 2,246,622 | | | | 15,652,421 | | | | 52,921 | | | | 17,951,964 | |
Note 13 — Significant Customers
During 2004, the Company had oil field service sales to three unrelated third parties of approximately $4,980,000, representing approximately 34% of net sales. In addition, during 2004, the Company sold approximately $6,209,000 or 99% of its oil and gas revenue to two unrelated customers.
F-27
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During 2003, the Company had oil field service sales to one unrelated third party of approximately $1,150,000, representing approximately 10% of net sales. In addition, during 2003, the Company sold approximately $6,453,000 or 98% of its oil and gas revenue, to two unrelated customers.
During 2002, the Company had oil field service sales to one unrelated third party of approximately $1,569,000, representing approximately 14% of net sales. In addition, during 2002, the Company sold approximately $2,107,000 or 89% of its oil and gas revenue to three unrelated companies.
Receivables outstanding at December 31, 2004 and 2003 from significant customer sales were approximately $1,879,000 and $529,000, or 53% and 30% of total accounts receivable at such date, respectively.
| |
Note 14 — | Fair Value of Financial Instruments |
The carrying value of the Company’s cash balance, accounts receivable, accounts payable and accrued liabilities represents the fair value of the accounts. The fair value of the Company’s long-term debt with financial institutions and equipment financing companies approximates the carrying value because (i) interest rates are variable or (ii) the debt instruments were executed at rates comparable to current rates for similar notes. The fair value of the Company’s other long-term debt obligations cannot be determined due to the nature of the transactions which created the debt, and comparable market value information is not readily determinable without incurring excessive costs. See Note 7 for the terms of the long-term debt obligations.
| |
Note 15 — | Earnings Per Share |
For the years ended December 31, 2004, 2003 and 2002, all potential Company shares of common stock are anti-dilutive.
As of December 31, 2004, 2003, and 2002, the impact of 5,320,892, 4,991,746, and 4,473,413, respectively, of potential shares of common stock were not included because their effect was anti-dilutive.
See Note 8 and Note 16 regarding options and warrants issued in 2005.
| |
Note 16 — | Subsequent Event |
| |
| Senior Secured Notes Facility |
On January 13, 2005, the Company entered into a securities purchase agreement (the “Senior Secured Notes Facility”) with affiliates of Promethean Asset Management, LLC and Angelo, Gordon & Co., L.P. (collectively, the “Buyers”), pursuant to which Infinity sold, and the Buyers purchased, $30 million aggregate principal amount of senior secured notes (the “Notes”“Initial Notes”) due January 13, 2009 and five-year warrants to purchase 924,194 shares of the Company’s common stock at an exercise price of $9.09 per share and 732,046 shares of the Company’s common stock at an exercise price of $11.06 per share (collectively, the “Warrants”“Initial Warrants”). The Initial Notes have an initial maturity of 48 months subject to extension for an additional twelve months upon the mutual agreement of Infinity and the Buyers. Pursuant to the terms of the Senior Secured Notes Facility, on September 7, 2005 and December 9, 2005, the Company sold, and the Buyers purchased, $9.5 million and $5.5 million, respectively, of additional principal amount of senior secured notes (the “Additional Notes” and together with the Initial Notes, the “Notes”) due March 7, 2009 and June 9, 2009, respectively, and five-year warrants to purchase 283,051 shares, 224,202 shares, 191,882 shares and 151,988 shares of the Company’s common stock at exercise prices of $9.40 per share, $11.44 per share, $8.03 per share and $9.77 per share, respectively (collectively, the “Additional Warrants” and together with the Initial Warrants, the “Warrants”). The Additional Notes have initial maturities of 42 months (54 months if the maturity of the Initial Notes is extended). The Notes bear interest at the3-month LIBOR (London Interbank Offered Rate) plus 675 basis points, adjusted the first business day of each calendar quarter. quarter (11.23% at December 31, 2005).
The Notes are secured by essentially all of the assets of Infinity and its subsidiaries and are guaranteed by each of Infinity’s active subsidiaries. The Notes are redeemable by Infinity for cash at any time during the first year at 105% of par value, declining by 1% per year thereafter (101% during any extended maturity period), together with any accrued and unpaid interest. Under certain circumstances, Infinity has the option to repay the Notes with direct issuances of shares of registered common stock in lieu of cash.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 (the “Conversion Option”). See Note 16.
At
Under certain circumstances at quarterly intervals and over a three-yearthree year period, commencing in the third quarter of 2005, Infinity has the option to sell additional notes (the “Additional Notes”),Notes, along with additional warrants,Warrants, in amounts of up to $15 million in any rolling twelve-month period, and up to a maximum of $45an additional $30 million. The Additionaladditional Notes would have an initial maturity of 42 months (54 months if the maturity of the initialInitial Notes is extended). The
F-28
INFINITY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
issuance of Additionaladditional Notes is subject to Infinity’s future satisfaction of various closing conditions. The ability to issue Additionaladditional Notes or the requirement to prepay Notes prior to maturity will depend upon a maximum Notes balance calculated quarterly based generally upon a combination of the financial performance of Consolidated Oil Well Services, Inc. and the SEC after-taxPV-10% value of the Company’s proved reserves. The maximum Notes balance at December 31, 2005 exceeded the Notes outstanding on that date. The Notes include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions.
F-16
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Under the provisions of SFAS No. 133 andEITF 00-19,Accounting for Derivative Financial Instruments Index to, and Potentially Settled in, a Company’s Own Stock, the Conversion Option and the Warrants qualify as derivatives. As a result, effective with the issuance of each series of Notes, the Company bifurcated the Conversion Option from the Notes and accounted for it and the Warrants as derivatives (see Note 7). The initial fair values of the Conversion Option and the Warrants, which aggregated $388,000 and $8,440,000, respectively, for all three series of Notes issued in 2005, were recorded as debt discount. The debt discount is being amortized over the initial maturities of the Notes utilizing the effective interest method.
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. As of December 31, 2005, the interest rate on the promissory note was 7.0% with interest payable quarterly. The note and accrued interest were settled in full in February 2006 in connection with the sale of the aircraft (see Note 16). Since the promissory note was settled with the proceeds from the sale of a non-current asset, the full balance of the promissory note has been classified as long-term.
8% Convertible Subordinated Notes
Effective June 13, 2001, the Company sold $6,475,000 in 8% Subordinated Convertible Notes in a private placement. Interest on the notes accrued at a rate of 8% per annum. The notes were convertible into one share of common stock at $5 per share and were scheduled to mature on June 13, 2006. The Company incurred costs of $502,000 associated with the placement, which were capitalized as loan costs. The Company also issued warrants to purchase 220,000 shares of common stock at $5.90 per share. The Company capitalized additional loan costs of $925,000 related to the fair value of the warrants.
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 at December 31, 2004 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. During 2004 and 2003, the holders of $300,000 and $1,450,000, respectively, of 8% Subordinated Convertible Notes converted the debt and accrued interest into 63,197 shares and 295,689 shares, respectively, of the Company’s common stock.
7% Convertible Subordinated Notes
Effective April 22, 2002, the Company sold $12,540,000 in 7% Subordinated Convertible Notes in a private placement. Interest on the notes accrued at a rate of 7% per annum. The notes were convertible to one share of common stock at $8.625 per share and were scheduled to mature on April 22, 2007. The Company incurred costs of $866,000 associated with the placement, which were capitalized as loan costs. The Company also issued warrants to purchase 200,000 shares of common stock at $9.058 per share. The Company capitalized additional loan costs of $1,386,000 related to the fair value of the warrants.
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 at December 31, 2004 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. During 2004 and 2003, the holders of $462,000 and $1,735,000, respectively, of 7% Subordinated Convertible Notes converted the debt and accrued interest into 62,685 shares and 203,712 shares, respectively, of the Company’s common stock.
F-17
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$25 Million Development Credit Facility
In September 2003, the Company established a secured revolving credit facility with a bank. Interest on the amounts outstanding accrued at prime rate plus 1.0%. The Company incurred $110,000 in loan costs and approximately $57,000 in legal costs to establish the facility. These costs were capitalized as loan costs. The facility was repaid in full with proceeds from the Senior Secured Notes Facility discussed above and terminated on January 13, 2005.
Revolving Credit and Term Loans
Effective July 9, 2004, Consolidated borrowed $5,400,000 under an amended credit facility with a bank. Amounts outstanding accrued interest at the prime rate plus 1.25% per annum. The credit facility was repaid in full with proceeds from the Senior Secured Notes Facility discussed above and terminated on January 13, 2005.
Debt Discount
As discussed above, in connection with the issuance of the Notes the Company recorded debt discount of $8,828,000, which is being amortized over the initial 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 2005 was $647,000, net of $764,000 capitalized to oil and gas properties. There was no debt discount amortization capitalized for 2004 and 2003.
Note 7 — Derivative Instruments
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 cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. As of December 31, 2005 the Company had the following oil collar derivative arrangements outstanding:
| | | | | | | | | | | | | |
Term of Arrangements | | Bbls per Day | | Floor Price | | Ceiling Price |
| |
| January 1, 2006 — June 30, 2006 | | | 50 | | | $ | 50.00 | | | $ | 64.40 | |
| October 1, 2005 — December 31, 2006 | | | 50 | | | $ | 52.50 | | | $ | 74.00 | |
All of the Company’s collar arrangements have been designated as cash flow hedges. As of December 31, 2005, the Company had a derivative liability of approximately $28,000, which is included in Accrued liabilities on the accompanying Consolidated Balance Sheet. During the year ended December 31, 2005, the Company recognized ineffectiveness of approximately $28,000 under its collar arrangements, which is reflected in Other expense in the accompanying Consolidated Statements of Operations. No amounts were received or paid by the Company during 2005 under its collar arrangements. During 2004 and 2003, the Company reclassified from other comprehensive income to natural gas revenue, gains of approximately $155,000 and $133,000, respectively, related to certain fixed-price delivery contracts that had been designated as cash flow hedges.
Subsequent to December 31, 2005, the Company entered into the following oil collar:
| | | | | | | | | | | | | |
Term of Arrangement | | Bbls per Day | | Floor Price | | Ceiling Price |
| |
| January 1, 2007 — June 30, 2007 | | | 50 | | | $ | 57.50 | | | $ | 77.50 | |
F-18
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Derivatives
As more fully discussed in Note 6 above, in January, September and December 2005, the Company issued Notes and Warrants. Under the provisions of SFAS No. 133 andEITF 00-19 the Company bifurcated the Conversion Option associated with the Notes and accounted for it and the Warrants as derivatives. The initial fair values of the Conversion Option and the Warrants, which aggregated $388,000 and $8,440,000, respectively, for all three series of Notes issued in 2005, were recorded as debt discount. Subsequent changes in the fair value of those derivatives have been recorded as Changes in derivative fair value in the accompanying Consolidated Statements of Operations. During 2005, the Company recognized Changes in derivative fair value of $34,000 and $1,885,000 related to the decrease in the fair value of the Conversion Option and Warrants, respectively. The terms of the Notes and Warrants contain 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 ofEITF 00-19, the Company was no longer able to conclude that it has sufficient authorized and unissued shares available to settle its previously issued non-employee options and warrants (the “Non-employee Options and Warrants”) (see Note 8) after considering the commitment to potentially issue common stock under terms of the Notes if ever there is 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 will be recorded as Change in derivative fair value in the accompanying Consolidated Statements of Operations so long as they continue to not qualify for equity classification. Non-employee Options and Warrants that are ultimately settled in common stock will be remeasured prior to settlement and then reclassified back to stockholders’ equity; however, any gains or losses previously recognized on those instruments will remain in earnings. During 2005, in connection with the exercise of 538,850 Non-employee Options and Warrants, the Company reclassified $2,174,000 back to stockholders’ equity. During 2005, the Company recognized Changes in derivative fair value of $989,000 related to the decrease in the fair value of these instruments.
Note 8 — 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 2005, the Company issued five-year warrants to purchase an aggregate of 2,507,363 shares of the Company’s common stock at a weighted average price of $9.87 per share. Through December 31, 2005, 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 contains anti-dilution provisions that require the Company to adjust the exercise price and Warrants, Infinitythe 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, the exercise price of the warrants was adjusted to $7.88 per share and the number of shares to be acquired under the warrants was increased by 27,746. The associated value of approximately $120,000 was recorded as offering costs.
F-19
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes non-employee option and warrant activity for the years ended December 31, 2005, 2004 and 2003:
| | | | | | | | | | | | | |
| | | | | | | | | Weighted Average
| |
| | | | | | Weighted Average
| | | Grant Date Fair
| |
| | | Number of Shares | | | Price Per Share | | | Value Per Share | |
| |
| Outstanding, January 1, 2003 | | | 1,030,000 | | | $ | 7.66 | | | $ | | |
| Granted | | | 1,163,500 | | | | 8.75 | | | | 4.98 | |
| Exercised | | | (83,350 | ) | | | 7.34 | | | | | |
| | | | | | | | | | | | | |
| Outstanding, December 31, 2003 | | | 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 | | | | | |
| | | | | | | | | | | | | |
The following table summarizes information about non-employee warrants and options outstanding at December 31, 2005:
| | | | | | | | | | | |
| | | Number
| | | | | | |
| | | Outstanding and
| | | | | | |
| | | Exercisable at
| | | Weighted Average
| | | |
| | | December 31,
| | | Remaining
| | Weighted Average
| |
Range of Exercise Prices | | 2005 | | | Contractual Life | | Exercise Price | |
| |
| $7.34 - 8.03 | | | 558,428 | | | 3.1 years | | $ | 7.85 | |
| $8.75 - 9.77 | | | 2,603,733 | | | 3.2 years | | $ | 9.02 | |
| $11.06 - 11.44 | | | 956,248 | | | 4.2 years | | $ | 11.15 | |
| | | | | | | | | | | |
| | | | 4,118,409 | | | | | | | |
| | | | | | | | | | | |
Options Under Employee Option Plans
In 2005, the Company’s stockholders approved the 2005 Equity Incentive Plan (the “2005 Plan”), under which both incentive and non-statutory stock options may be granted to employees, officers, non-employee directors and consultants. An aggregate of 475,000 shares of the Company’s common stock are reserved for issuance under the 2005 Plan. Options granted under the 2005 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 2005 Plan.
The Company granted 530,000, 403,750 and 10,000 options to employees under the plans during the years ended December 31, 2005, 2004 and 2003, respectively. At December 31, 2005, there were 140,881 shares available for grant under the plans, of which 140,000 are available under the 2005 Plan.
F-20
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes stock option activity for the years ended December 31, 2005, 2004 and 2003:
| | | | | | | | | | | | | |
| | | | | | | | | Weighted Average
| |
| | | | | | Weighted Average
| | | Grant Date Fair
| |
| | | Number of Shares | | | Price Per Share | | | Value Per Share | |
| |
| Outstanding, January 1, 2003 | | | 1,140,900 | | | $ | 5.23 | | | $ | | |
| Granted | | | 10,000 | | | | 8.75 | | | | 5.25 | |
| Canceled or forfeited | | | (61,781 | ) | | | 7.28 | | | | | |
| Exercised | | | (62,819 | ) | | | 3.38 | | | | | |
| | | | | | | | | | | | | |
| Outstanding, December 31, 2003 | | | 1,026,300 | | | | 5.25 | | | | | |
| Granted | | | 403,750 | | | | 4.26 | | | | 4.22 | |
| Canceled or forfeited | | | (118,500 | ) | | | 7.22 | | | | | |
| Exercised | | | (146,300 | ) | | | 2.92 | | | | | |
| | | | | | | | | | | | | |
| Outstanding, December 31, 2004 | | | 1,165,250 | | | | 5.00 | | | | | |
| Granted | | | 530,000 | | | | 7.83 | | | | 6.00 | |
| Exercised | | | (312,000 | ) | | | 3.07 | | | | | |
| | | | | | | | | | | | | |
| Outstanding, December 31, 2005 | | | 1,383,250 | | | | 6.52 | | | | | |
| | | | | | | | | | | | | |
The following table summarizes information about stock options outstanding at December 31, 2005:
| | | | | | | | | | | | | | | | | | | | | |
| | | Number
| | | | | | | | | Number
| | | | |
| | | Outstanding at
| | | Weighted Average
| | | | | | Exercisable at
| | | | |
Range of
| | December 31,
| | | Remaining
| | | Weighted Average
| | | December 31,
| | | Weighted Average
| |
Exercise Prices | | 2005 | | | Contractual Life | | | Exercise Price | | | 2005 | | | Exercise Price | |
| |
| $4.26 - 5.00 | | | 620,250 | | | | 2.2 years | | | $ | 4.58 | | | | 620,250 | | | $ | 4.58 | |
| $7.51 - 7.80 | | | 365,000 | | | | 9.6 years | | | $ | 7.53 | | | | 365,000 | | | $ | 7.53 | |
| $8.50 - 8.70 | | | 398,000 | | | | 5.2 years | | | $ | 8.62 | | | | 398,000 | | | $ | 8.62 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 1,383,250 | | | | | | | | | | | | 1,383,250 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Note 9 — Income Taxes
The provision for income taxes consists of the following:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Current income tax expense | | $ | — | | | $ | — | | | $ | — | |
| Deferred income tax benefit | | | (5,464 | ) | | | (1,784 | ) | | | (4,003 | ) |
| Change in valuation allowance and other | | | 5,464 | | | | 1,784 | | | | 4,003 | |
| | | | | | | | | | | | | |
| Total income tax benefit | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
F-21
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The effective income tax rate varies from the statutory federal income tax rate as follows:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Federal income tax rate | | | (34.0 | )% | | | (34.0 | )% | | | (34.0 | )% |
| State income tax rate | | | (4.5 | ) | | | (6.0 | ) | | | (6.0 | ) |
| Tax benefit of derivatives settled with equity | | | 1.9 | | | | — | | | | — | |
| Other temporary and permanent differences | | | (3.6 | ) | | | — | | | | — | |
| Change in valuation allowance and other | | | 40.2 | | | | 40.0 | | | | 40.0 | |
| | | | | | | | | | | | | |
| Effective tax rate | | | — | % | | | — | % | | | — | % |
| | | | | | | | | | | | | |
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, | |
| | | 2005 | | | 2004 | |
| | | (In thousands) | |
| |
| Deferred tax assets | | | | | | | | |
| Accruals and other | | $ | 214 | | | $ | 132 | |
| Net operating loss carry-forward | | | 13,635 | | | | 10,387 | |
| | | | | | | | | |
| Gross deferred tax assets | | | 13,849 | | | | 10,519 | |
| | | | | | | | | |
| Deferred tax liabilities | | | | | | | | |
| Property and equipment | | | 1,185 | | | | 4,694 | |
| Derivative liabilities | | | 1,375 | | | | — | |
| | | | | | | | | |
| Gross deferred tax liabilities | | | 2,560 | | | | 4,694 | |
| | | | | | | | | |
| Net deferred tax asset | | | 11,289 | | | | 5,825 | |
| Less valuation allowance | | | (11,289 | ) | | | (5,825 | ) |
| | | | | | | | | |
| Deferred tax asset | | $ | — | | | $ | — | |
| | | | | | | | | |
For income tax purposes, the Company has net operating loss carry-forwards of approximately $35,416,000, which expire from 2015 through 2025. The Company has provided for a valuation allowance of $11,289,000 due to the uncertainty of realizing the tax benefits from its net deferred tax asset.
During the years ended December 31, 2005, 2004 and 2003, the Company realized certain tax benefits related to stock option plans in the amounts of $505,000, $172,000 and $164,000, 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 10 — Commitments and Contingencies
Gas Gathering Contracts
In June 2001, the Company entered into a registrations rights agreementlong-term gas gathering contract, which expires in December 2008, for natural gas production from the Company’s field in Sweetwater County, Wyoming. Under the contract, as amended on April 4, 2003, the Company pays gas gathering fees per thousand cubic feet (“Mcf”) delivered. The Company is obligated to pay a fee of $.40 per Mcf on the first 7,500,000 Mcf and $.25 per Mcf thereafter. 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
F-22
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
did not meet the minimum in any year, the shortfall was added to the following years. Through December 31, 2005, the Company had delivered approximately 4,000,000 Mcf. While the Company has failed to deliver the volumes required under the contract, the pipeline operator has also not provided the compression and gathering capabilities it was required to provide under the contract. Management has received a verbal commitment from the operator that the volume commitments will be adjusted and management does not believe there will be a contract shortfall under the renegotiated volumes and therefore, anticipates no additional costs under the contract.
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. The Company may, at its discretion and with notice, reduce the Buyers pursuantminimum daily delivery volumes by up to which Infinity agreed to file50%. Based on production volumes through December 31, 2005, the Company has accrued a shelf registration statement covering resalesliability of approximately $248,000 as a delivery commitment shortfall under the ordinary shares issuable upon exercise of the Warrants.contract.
The Securities Purchase Agreement dated as
Fixed Price Delivery Contracts
During 2004, the Company entered into a fixed price delivery contract for the period from April 1, 2004 through March 31, 2006 for 2,000 MMbtu per day of January 13, 2005 by and among Infinity and the Buyers of the Notes includes a covenant that at each date that is the end of a quarterly or annual period covered by a quarterly report on Form 10-Q or annual report on Form 10-K (a “Determination Date”), at least 20%natural gas from certain of the Company’s estimateWyoming properties. The fixed price for the period April 1, 2004 through March 31, 2005 was $4.40 per MMBtu and the fixed price for the period April 1, 2005 through March 31, 2006 is $4.15 per MMBtu. Sales under this fixed price contract are accounted for as normal sales agreements under the exemption in SFAS No. 133.
Lease Agreements
The Company leases office space under an operating lease with a lease term through September 2007. Future minimum lease payments under the non-cancelable operating lease are as follows at December 31, 2005:
| | | | | |
Year Ending December 31, | | Operating Lease | |
| | | (In thousands) | |
| |
| 2006 | | $ | 97 | |
| 2007 | | | 69 | |
| | | | | |
| Total minimum lease payments | | $ | 166 | |
| | | | | |
Rental expense for the years ended December 31, 2005, 2004 and 2003 was $153,000, $133,524 and $142,926, 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 11 — 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 $152,000 and $112,000 related to such contributions during the years ended December 31, 2005 and 2004, respectively. There were no Company contributions made to the plan during 2003.
F-23
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note 12 — Industry Segments
Segment information has been prepared in accordance with SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, which requires disclosure of information related to certain operating segments of the Company. The Company has two reportable segments: (i) oil and gas production and (ii) oil field services. The Company’s oil and gas production segment is engaged in the acquisition, exploration, development and production of natural gas and crude oil in Colorado, Texas and Wyoming. The Company’s oil field services segment provides pressure-pumping services associated with the drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, and water hauling and has operations principally in Kansas, Oklahoma, and Wyoming.
The segment data presented below was prepared on the same basis as the consolidated financial statements:
| | | | | | | | | | | | | | | | | |
| | | Oil Field
| | | Oil & Gas
| | | Corporate and
| | | | |
| | | Services | | | Production | | | Other | | | Total | |
| | | (In thousands) | |
| |
Revenue | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2005 | | $ | 21,583 | | | $ | 9,192 | | | $ | — | | | $ | 30,775 | |
| For the year ended December 31, 2004 | | | 14,721 | | | | 6,267 | | | | — | | | | 20,988 | |
| For the year ended December 31, 2003 | | | 11,634 | | | | 6,589 | | | | — | | | | 18,223 | |
Depreciation, depletion, amortization and accretion | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2005 | | | 1,268 | | | | 6,033 | | | | 150 | | | | 7,451 | |
| For the year ended December 31, 2004 | | | 1,450 | | | | 3,611 | | | | 137 | | | | 5,198 | |
| For the year ended December 31, 2003 | | | 1,421 | | | | 1,561 | | | | 92 | | | | 3,074 | |
Ceiling write-down | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2005 | | | — | | | | 13,450 | | | | — | | | | 13,450 | |
| For the year ended December 31, 2004 | | | — | | | | 4,100 | | | | — | | | | 4,100 | |
| For the year ended December 31, 2003 | | | — | | | | 2,975 | | | | — | | | | 2,975 | |
Operating income (loss) | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2005 | | | 6,712 | | | | (14,870 | ) | | | (2,998 | ) | | | (11,156 | ) |
| For the year ended December 31, 2004 | | | 2,669 | | | | (4,823 | ) | | | (2,144 | ) | | | (4,298 | ) |
| For the year ended December 31, 2003 | | | 1,411 | | | | (1,630 | ) | | | (2,061 | ) | | | (2,280 | ) |
Total assets | | | | | | | | | | | | | | | | |
| As of December 31, 2005 | | | 14,552 | | | | 68,299 | | | | 11,433 | | | | 94,284 | |
| As of December 31, 2004 | | | 10,972 | | | | 48,001 | | | | 5,075 | | | | 64,048 | |
| As of December 31, 2003 | | | 9,069 | | | | 40,220 | | | | 5,977 | | | | 55,266 | |
Capital expenditures | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2005 | | | 4,190 | | | | 39,590 | | | | 11 | | | | 43,791 | |
| For the year ended December 31, 2004 | | | 2,247 | | | | 15,652 | | | | 53 | | | | 17,952 | |
| For the year ended December 31, 2003 | | | 460 | | | | 6,076 | | | | 198 | | | | 6,734 | |
Note 13 — Significant Customers
During 2005, oil field services provided to one unrelated third party represented 10% of total revenue. In addition, during 2005, oil and gas sales to one unrelated customer represented 10% of total revenue.
During 2004, oil field services provided to one unrelated third party represented 10% of total revenue. In addition, during 2004, oil and gas sales to one unrelated customer represented 26% of total revenue.
F-24
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During 2003, oil and gas sales to two unrelated third parties represented 27% and 12% of total revenue.
Note 14 — 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. Long-term debt at December 31, 2005, with a carrying value of approximately $40.2 million, is estimated to have a fair value between $44 million and $45 million. See Note 6 for the 12-month period commencing immediately after such Determination Date shall be protected from price fluctuations using derivatives, fixed price agreements and/or volumetric production payments.
Infinity used approximately $9.2 millionterms of the long-term debt obligations.
The fair value of the Company’s non-current derivative liabilities, all of which relate to the Conversion Option, Warrants and Non-employee Options and 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, interest rates and the probability of conversion, redemption or exercise, among other items.
Note 15 — Earnings Per Share
For the years ended December 31, 2005, 2004 and 2003, all of the Company’s common stock equivalents were anti-dilutive. Therefore, the impact of 5,501,659, 5,320,892 and 4,991,746 common stock equivalents outstanding as of December 31, 2005, 2004 and 2003, respectively, were not included in the calculation of diluted loss per share because their effect was anti-dilutive. The number of common stock equivalents excluded from the diluted loss per share calculations does not include any shares that may be issued in the future should the Company elect to repay Notes outstanding under the Senior Secured Notes Facility with direct issuances of shares of registered common stock in lieu of cash. See Note 16.
Note 16 — Subsequent Events
Conversion of Accrued Interest and Senior Secured Notes
In accordance with terms of the Senior Secured Notes Facility, in January 2006, the Company elected to settle approximately $861,000 of interest accrued at December 31, 2005 (due January 3, 2006) through the issuance of 126,084 shares of common stock. Since the interest was settled with other than current assets, the accrued interest at December 31, 2005 has been classified as long-term. In addition, also in accordance with terms of the Senior Secured Notes Facility, in 2006, through March 3, 2006, the Company converted $3 million principal amount of Notes, along with accrued interest of $37,000, into 382,062 shares of common stock.
Sale of Aircraft
In February 2006, the Company sold its 50% interest in an aircraft for net proceeds fromof approximately $2.3 million and recognized a gain of approximately $292,000. In conjunction with the sale of the Notesaircraft, the Company settled the related promissory note and Warrants to repay all amounts outstanding pursuant to a Loanaccrued interest.
Note 17 — Supplemental Oil and Security Agreement between LaSalle Bank N.A.Gas Information
Estimated Proved Oil and Consolidated, a Credit Agreement between U.S. Bank National Association and Infinity-Wyoming, and certain other secured lending agreements, and those credit agreements have been terminated. See Note 7 to the Consolidated Financial Statements. Infinity is using the remainder of the proceeds to pay costs and expenses related to the sale of the Notes and Warrants and to fund itsGas Reserves (Unaudited)
Proved oil and gas explorationreserves 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 activities.expenditures. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered.
F-25
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
| |
Note 17 — | Supplemental Oil and Gas Information |
| |
| Proved Oil and Gas Reserves (Unaudited) |
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 December 31, 2001 | | | 9,224,600 | | | | 138,164 | |
| Sales or other deletions | | | — | | | | (128,788 | ) |
| Revisions of previous estimates | | | (2,042,255 | ) | | | 85,277 | |
| Extension, discoveries and other additions | | | 89,284,734 | | | | 141,169 | |
| Production | | | (676,879 | ) | | | (53,122 | ) |
| | | | | | | |
| Proved reserves as of December 31, 2002 | | | 95,790,200 | | | | 182,700 | |
| Revisions of previous estimates | | | (90,374,776 | ) | | | 1,991 | |
| Extension, discoveries and other additions | | | 3,175,927 | | | | 66,102 | |
| Production | | | (1,080,456 | ) | | | (57,654 | ) |
| | | | | | | |
| Proved reserves as of December 31, 2003 | | | 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 | |
| | | | | | | |
F-29
INFINITY, INC. AND SUBSIDIARIES
| | | | | | | | | |
| | | Natural Gas
| | | Crude Oil
| |
| | | (Mcf) | | | (Barrels) | |
| |
| Proved reserves as of December 31, 2002 | | | 95,790,200 | | | | 182,700 | |
| Revisions of previous estimates | | | (90,374,776 | ) | | | 1,991 | |
| Extension, discoveries and other additions | | | 3,175,927 | | | | 66,102 | |
| Production | | | (1,080,456 | ) | | | (57,654 | ) |
| | | | | | | | | |
| Proved reserves as of December 31, 2003 | | | 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 | |
| | | | | | | | | |
| Proved Developed Reserves as of: | | | | | | | | |
| December 31, 2003 | | | 4,724,523 | | | | 124,968 | |
| | | | | | | | | |
| December 31, 2004 | | | 3,773,033 | | | | 117,031 | |
| | | | | | | | | |
| December 31, 2005 | | | 5,031,235 | | | | 712,094 | |
| | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The 2003 revisionrevisions to the previous estimateestimates of reserves is due primarily to the following factors:
| | |
| | • | operational issues at the existing Labarge wells; |
| |
| | • | a lack of financial resources to rectify the operational issues on a timely basis or to complete exploration on other wells; and |
| |
| | • | geological studies that indicate the producing Pipeline wells were producing from the sands rather than the coals thus leading the Company to change the classification of Pipeline from a coal play to a sand play. |
F-26
Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
There are uncertainties inherent
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Costs Incurred in estimating quantities of proved oilOil and gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.Gas Activities
All proved reserves are located in the United States.
| |
| Proved Developed Oil and Gas Reserves (Unaudited) |
The following information sets forth the estimated quantities of proved developed oil and gas reserves of the Company as of the end of each year.
| | | | | | | | | |
| | | | | Crude Oil and | |
| | | Natural Gas | | | Condensate | |
| Proved Developed Reserves | | (Mcf) | | | (Barrels) | |
| | | | | | | |
| December 31, 2002 | | | 38,590,600 | | | | 182,700 | |
| December 31, 2003 | | | 4,724,523 | | | | 124,968 | |
| December 31, 2004 | | | 3,773,033 | | | | 117,031 | |
| |
| 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 Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Property acquisition costs | | | | | | | | | | | | |
| | Proved | | $ | 516,239 | | | $ | 1,099,120 | | | $ | 72,383 | |
| | Unproved | | | 3,717,280 | | | | 661,224 | | | | 2,279,587 | |
| | | | | | | | | | |
| | | Total property acquisition costs | | | 4,233,519 | | | | 1,760,344 | | | | 2,351,970 | |
| Development costs | | | 6,156,131 | | | | 3,167,700 | | | | 786,095 | |
| Exploration costs | | | 5,294,148 | | | | 3,491,953 | | | | 11,955,351 | |
| | | | | | | | | | |
| Total costs | | $ | 15,683,798 | | | $ | 8,419,997 | | | $ | 15,093,416 | |
| | | | | | | | | | |
F-30
| | | | | | | | | | | | | |
| | | For the Years Ended December 31 | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Property acquisition costs | | | | | | | | | | | | |
| Proved | | $ | 330 | | | $ | 516 | | | $ | 1,099 | |
| Unproved | | | 5,745 | | | | 3,625 | | | | 661 | |
| | | | | | | | | | | | | |
| Total property acquisition costs | | | 6,075 | | | | 4,141 | | | | 1,760 | |
| Development costs | | | 17,099 | | | | 6,156 | | | | 3,168 | |
| Exploration costs | | | 17,583 | | | | 5,294 | | | | 3,492 | |
| Asset retirement costs | | | 907 | | | | 93 | | | | 503 | |
| | | | | | | | | | | | | |
| Total costs | | $ | 41,664 | | | $ | 15,684 | | | $ | 8,923 | |
| | | | | | | | | | | | | |
INFINITY, INC. AND SUBSIDIARIESAggregate Capitalized Costs
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| 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:
| | | | | | | | | | |
| | | As of December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Proved oil and gas properties | | $ | 41,210,195 | | | $ | 28,194,858 | |
| Unproved oil and gas properties | | | 15,595,508 | | | | 12,715,834 | |
| | | | | | | |
| | Total | | | 56,805,703 | | | | 40,910,692 | |
| Less accumulated depreciation, depletion, and amortization and ceiling write-down | | | (12,418,315 | ) | | | (4,748,515 | ) |
| | | | | | | |
| Net capitalized costs | | $ | 44,387,388 | | | $ | 36,162,177 | |
| | | | | | | |
| | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
| | | (In thousands) | |
| |
| Proved oil and gas properties | | $ | 75,484 | | | $ | 41,210 | |
| Unproved oil and gas properties | | | 22,849 | | | | 15,595 | |
| | | | | | | | | |
| Total | | | 98,333 | | | | 56,805 | |
| Less accumulated depreciation, depletion, amortization and ceiling write-down | | | (31,785 | ) | | | (12,418 | ) |
| | | | | | | | | |
| Net capitalized costs | | $ | 66,548 | | | $ | 44,387 | |
| | | | | | | | | |
| |
| Costs Not Being Amortized |
Costs Not Being Amortized
Oil and gas property costs not being amortized at December 31, 2004,2005, by year that the costs were incurred are as follows:
| | | | | |
| Year Ended December 31, | | |
| | | |
| 2004 | | $ | 6,700,461 | |
| 2003 | | | 1,644,654 | |
| 2002 and prior | | | 7,250,393 | |
| | | | |
| Total costs not being amortized | | $ | 15,595,508 | |
| | | | |
| | | | | |
Year Ended December 31, | | (In thousands)
| |
| |
| 2005 | | $ | 12,879 | |
| 2004 | | | 2,601 | |
| 2003 | | | 1,745 | |
| Prior | | | 5,624 | |
| | | | | |
| Total costs not being amortized | | $ | 22,849 | |
| | | | | |
Unevaluated costs include $6,063,000$5,897,000 relating to our prospect in the Fort Worth Basin of North Central Texas. During 2004, the Company acquired interests in approximately 32,000 acres in the Fort Worth Basin of North Central Texas. In October 2004, the Company commenced the drilling of several exploratory gas wells. Approximately $3,600,000 associated with wells in progress is expected to be classified as evaluated during 2005.
Unevaluated costs include $6,933,000 relating to ourCompany’s Labarge prospect in Southwestsouthwest 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 Company can continue development. Approximately $2,100,000 associated with wells in progress is expected to be classified as evaluated during 2005.
Unevaluated costs include approximately $925,000$1,160,000 relating to ourthe Company’s concessions offshore Nicaragua. The Company expects to execute a definitive exploration and production contract covering the approximate 1,400,000 acres during 2005.
F-31
F-27
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
during 2006. The Company anticipates that the majority of all the unproved costs in the table above will be classified as proved costs within the next five years.
| |
| Capitalized Financing Costs |
From inception through December 31, 2004 the Company has capitalized the following financing costs related to properties not subject to amortization. As these properties are developed, the costs are transferred to properties subject to amortization:
| | | | | | | | | |
| | | As of December 31, | |
| | | | |
| | | 2004 | | | 2003 | |
| | | | | | | |
| Beneficial conversion feature related to the 8% subordinated convertible notes | | $ | 1,165,500 | | | $ | 1,165,500 | |
| Capitalized interest | | | 2,880,608 | | | | 2,246,019 | |
| Capitalized amortization of loan costs | | | 5,440,961 | | | | 4,885,586 | |
| | | | | | | |
| Total capitalized finance costs | | $ | 9,487,069 | | | $ | 8,297,105 | |
| | | | | | | |
Oil and Gas Operations
Aggregate results of operations in connection with the Company’s oil producing activities are shown below:
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Revenue | | $ | 6,267,453 | | | $ | 6,589,281 | | | $ | 2,367,713 | |
| Production costs and taxes | | | (2,635,892 | ) | | | (2,920,493 | ) | | | (1,820,692 | ) |
| Depreciation, depletion, amortization, accretion and ceiling write-down | | | (7,677,968 | ) | | | (4,442,097 | ) | | | (196,627 | ) |
| | | | | | | | | | |
| Results of operations from producing activities (excluding corporate overhead and interest costs) | | $ | (4,046,407 | ) | | $ | (773,309 | ) | | $ | 350,394 | |
| | | | | | | | | | |
| Depletion per Mcf equivalent | | $ | 3.06 | | | $ | 0.92 | | | $ | 1.11 | |
| | | | | | | | | | |
F-32
INFINITY, INC. AND SUBSIDIARIES
| | | | | | | | | | | | | |
| | | For the Years Ended December 31 | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Revenue | | $ | 9,192 | | | $ | 6,268 | | | $ | 6,589 | |
| Production costs and taxes | | | (4,425 | ) | | | (2,636 | ) | | | (2,920 | ) |
| Depreciation, depletion, amortization and accretion | | | (6,033 | ) | | | (3,578 | ) | | | (1,467 | ) |
| Ceiling write-down | | | (13,450 | ) | | | (4,100 | ) | | | (2,975 | ) |
| | | | | | | | | | | | | |
| Results of operations from producing activities (excluding corporate overhead and interest costs) | | $ | (14,716 | ) | | $ | (4,046 | ) | | $ | (773 | ) |
| | | | | | | | | | | | | |
| Depletion per Mcf equivalent | | $ | 4.60 | | | $ | 3.06 | | | $ | 0.92 | |
| | | | | | | | | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) |
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows asRelating 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 December 31, 2004, 2003,the years indicated, except in those instances where the sale of oil and 2002,natural gas is covered by contracts, as required by SFAS No. 69. The Statement69,Disclosures about Oil and Gas Producing Activities. SFAS No. 69 requires the use of a 10 percent discount rate.that net cash flow amounts be discounted at 10%. This information does not represent the fair market value nor the expected present value of future cash flows of the Company’s proved oil and gas reserves.
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Future cash inflows | | $ | 56,584,600 | | | $ | 51,591,800 | | | $ | 303,392,537 | |
| Future production costs | | | (18,552,100 | ) | | | (16,204,800 | ) | | | (109,060,912 | ) |
| Future development costs | | | (3,450,000 | ) | | | (2,912,800 | ) | | | (16,424,600 | ) |
| Future income tax expense | | | (399,302 | ) | | | (2,765,262 | ) | | | (59,269,174 | ) |
| | | | | | | | | | |
| Future net cash flows | | | 34,183,198 | | | | 29,708,938 | | | | 118,637,851 | |
| 10% annual discount for estimated timing on cash flows | | | (10,470,718 | ) | | | (8,887,283 | ) | | | (63,585,181 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future cash flows | | $ | 23,712,480 | | | $ | 20,821,655 | | | $ | 55,052,670 | |
| | | | | | | | | | |
Future cash inflows are computed by applying a
| | | | | | | | | | | | | |
| | | For the Years Ended December 31 | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (In thousands) | |
| |
| Future cash inflows | | $ | 141,982 | | | $ | 56,585 | | | $ | 51,592 | |
| Future production costs | | | (49,010 | ) | | | (18,552 | ) | | | (16,205 | ) |
| Future development costs | | | (16,785 | ) | | | (3,450 | ) | | | (2,913 | ) |
| Future income tax expense | | | (656 | ) | | | (400 | ) | | | (2,765 | ) |
| | | | | | | | | | | | | |
| Future net cash flows | | | 75,531 | | | | 34,183 | | | | 29,709 | |
| 10% annual discount for estimated timing on cash flows | | | (32,014 | ) | | | (10,471 | ) | | | (8,887 | ) |
| | | | | | | | | | | | | |
| Standardized measure of discounted future cash flows | | $ | 43,517 | | | $ | 23,712 | | | $ | 20,822 | |
| | | | | | | | | | | | | |
The following table presents the average year-end spot market gas price and oil price for the areas of production. The following table shows the prices that have been used to compute future cash inflows for each period:
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Weighted average gas price per Mcf | | $ | 6.07 | | | $ | 6.06 | | | $ | 3.11 | |
| Weighted average oil price per barrel | | $ | 40.25 | | | $ | 31.34 | | | $ | 31.20 | |
A subsequent decline in prices received for oil and gas sales from those used to compute cash inflows ($6.53 per Mcf and $54.55 per barrel at March 15, 2005) could result in a requirement that the Company recognize a ceiling write-down to oil and gas properties in a future period. See also Note 1 to the Consolidated Financial Statements.
| | | | | | | | | | | | | |
| | | For the Years Ended December 31 | |
| | | 2005 | | | 2004 | | | 2003 | |
| |
| Weighted average gas price per Mcf | | $ | 8.21 | | | $ | 6.07 | | | $ | 6.06 | |
| Weighted average oil price per barrel | | $ | 60.74 | | | $ | 40.25 | | | $ | 31.34 | |
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 at December 31, 2005, 2004 2003 and 20022003 assuming continuation of existing economic conditions.
F-33
F-28
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following reconciles the change in the standardized measure of discounted future net cash flow:
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | | |
| | | 2004 | | | 2003 | | | 2002 | |
| | | | | | | | | | |
| Beginning of period | | $ | 20,821,655 | | | $ | 55,052,670 | | | $ | 5,622,483 | |
| Extensions, discoveries and other additions | | | 2,911,800 | | | | 9,004,500 | | | | 77,054,495 | |
| Purchases of reserves in place | | | 2,839,535 | | | | — | | | | — | |
| Sales and transfers | | | — | | | | — | | | | (547,245 | ) |
| Net change in sales and transfer prices, net of production costs | | | (4,117,528 | ) | | | 76,822,907 | | | | 371,265 | |
| Revision of previous quantity estimates | | | 241,269 | | | | (170,455,255 | ) | | | (1,590,027 | ) |
| Development costs incurred during the period | | | 5,023,365 | | | | 976,462 | | | | 786,095 | |
| Sales of oil and gas, net of production costs and taxes | | | (3,631,561 | ) | | | (3,678,788 | ) | | | (547,021 | ) |
| Changes in future development costs | | | (3,025,685 | ) | | | 13,143,811 | | | | (252,092 | ) |
| Net change in income taxes | | | 1,816,525 | | | | 26,834,091 | | | | (25,423,043 | ) |
| Changes in production rates and other | | | (1,461,405 | ) | | | 4,718,632 | | | | (1,337,938 | ) |
| Accretion of discount | | | 2,294,510 | | | | 8,402,625 | | | | 915,698 | |
| | | | | | | | | | |
| End of period | | $ | 23,712,480 | | | $ | 20,821,655 | | | $ | 55,052,670 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31 | |
| | | 2005 | | | 2004 | | | 2003 | |
| |
| Beginning of period | | $ | 23,712 | | | $ | 20,822 | | | $ | 55,053 | |
| Extensions, discoveries and other additions | | | 12,328 | | | | 2,912 | | | | 9,004 | |
| Purchases of reserves in place | | | 442 | | | | 2,840 | | | | — | |
| Net change in sales and transfer prices, net of production costs | | | (1,305 | ) | | | (4,118 | ) | | | 76,823 | |
| Revision of previous quantity estimates | | | 12,809 | | | | 241 | | | | (170,455 | ) |
| Development costs incurred during the period | | | 1,525 | | | | 5,023 | | | | 976 | |
| Sales of oil and gas, net of production costs and taxes | | | (4,767 | ) | | | (3,632 | ) | | | (3,679 | ) |
| Changes in future development costs | | | 402 | | | | (3,026 | ) | | | 13,144 | |
| Net change in income taxes | | | (156 | ) | | | 1,817 | | | | 26,834 | |
| Changes in production rates and other | | | (3,875 | ) | | | (1,462 | ) | | | 4,719 | |
| Accretion of discount | | | 2,402 | | | | 2,295 | | | | 8,403 | |
| | | | | | | | | | | | | |
| End of period | | $ | 43,517 | | | $ | 23,712 | | | $ | 20,822 | |
| | | | | | | | | | | | | |
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 properties involved.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.
Note 18 — Quarterly Consolidated Financial Information (Unaudited)
The following table provides selected quarterly consolidated financial results for the years ended December 31, 20042005 and 2003.2004.
| | | | | | | | | | | | | | | | | |
| | | Quarter | |
| | | | |
| | | First | | | Second | | | Third | | | Fourth | |
| | | | | | | | | | | | | |
| | | ($ in thousands, except per share information) | |
2004 | | | | | | | | | | | | | | | | |
| Total revenue | | $ | 3,567 | | | $ | 5,045 | | | $ | 6,606 | | | $ | 5,770 | |
| Gross profit | | $ | 1,628 | | | $ | 2,518 | | | $ | 3,542 | | | $ | 2,774 | |
| Net (loss) income | | $ | (1,765 | ) | | $ | (1,102 | ) | | $ | 3,121 | | | $ | (4,887 | ) |
| (Loss) earning per share | | $ | (0.19 | ) | | $ | (0.12 | ) | | $ | 0.33 | | | $ | (0.49 | ) |
| (Loss) earning per diluted share | | $ | (0.19 | ) | | $ | (0.12 | ) | | $ | 0.29 | | | $ | (0.49 | ) |
2003 | | | | | | | | | | | | | | | | |
| Total revenue | | $ | 3,605 | | | $ | 5,003 | | | $ | 5,241 | | | $ | 4,375 | |
| Gross profit | | $ | 1,450 | | | $ | 2,706 | | | $ | 2,764 | | | $ | 2,160 | |
| Net (loss) income | | $ | (622 | ) | | $ | (224 | ) | | $ | (4,525 | ) | | $ | (4,554 | ) |
| (Loss) earning per share | | $ | (0.08 | ) | | $ | (0.03 | ) | | $ | (0.55 | ) | | $ | (0.57 | ) |
| (Loss) earning per diluted share | | $ | (0.08 | ) | | $ | (0.03 | ) | | $ | (0.55 | ) | | $ | (0.57 | ) |
| | | | | | | | | | | | | | | | | |
| | | Quarter | |
| | | First | | | Second | | | Third | | | Fourth | |
| | | (In thousands, except per share amounts) | |
| |
2005 | | | | | | | | | | | | | | | | |
| Total revenue | | $ | 5,515 | | | $ | 7,651 | | | $ | 8,805 | | | $ | 8,804 | |
| Gross profit | | $ | 2,903 | | | $ | 3,924 | | | $ | 4,439 | | | $ | 4,315 | |
| Net income (loss) | | $ | (9,463 | ) | | $ | 4,356 | | | $ | 646 | | | $ | (9,116 | ) |
| Earnings (loss) per share | | $ | (0.81 | ) | | $ | 0.33 | | | $ | 0.05 | | | $ | (0.68 | ) |
| Earnings (loss) per diluted share | | $ | (0.81 | ) | | $ | 0.31 | | | $ | 0.00 | | | $ | (0.68 | ) |
2004 | | | | | | | | | | | | | | | | |
| Total revenue | | $ | 3,567 | | | $ | 5,045 | | | $ | 6,606 | | | $ | 5,770 | |
| Gross profit | | $ | 1,628 | | | $ | 2,518 | | | $ | 3,542 | | | $ | 2,774 | |
| Net (loss) income | | $ | (1,765 | ) | | $ | (1,102 | ) | | $ | 3,121 | | | $ | (4,887 | ) |
| (Loss) earning per share | | $ | (0.19 | ) | | $ | (0.12 | ) | | $ | 0.33 | | | $ | (0.49 | ) |
| (Loss) earning per diluted share | | $ | (0.19 | ) | | $ | (0.12 | ) | | $ | 0.29 | | | $ | (0.49 | ) |
F-34
F-29
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company recorded full cost ceiling writedowns during the fourth quarters of 2005 and 2004, of $13,450,000 and 2003, of $4,100,000, and $2,975,000, respectively.
Note 19 — Schedule
The Company restated net income (loss), earnings (loss) per share and earnings (loss) per diluted share for the first, second and third quarters of Condensed Financial Information
The oil and gas production subsidiary2005 to correct the accounting for certain derivatives embedded in or resulting from the issuance of the Company that owns more than 25% of the net assets of the Company was restricted from distributing more than $300,000 to the parent at December 31, 2004 under the $25,000,000 development credit facility executedCompany’s senior secured notes in September 2003. However as such credit facility was repaid in full and terminated on January 13, 2005; the restriction is no longer applicable. Accordingly, the condensed balance sheet, statement of operations and cash flow statement for the parent have not been provided as of and for the period ended December 31, 2004.2005.
F-35
F-30
EXHIBIT INDEX
| | | | |
Exhibit | | | |
Number | | | Description of Exhibits |
| | | |
| 21 | | | Subsidiaries of the Registrant |
| 23.1 | | | Consent of Ehrhardt, Keefe, Steiner & Hottman, P.C. |
| 23.2 | | | Consent of Netherland Sewell and Associates, Inc. |
| 31.1 | | | Certification of Chief Executive Officer of Periodic Report Pursuant to Rule 13a_14(a) and Rule 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 13a_14(a) and Rule 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) |
| | | | | |
Exhibit
| | |
Number | | Description of Exhibits |
| |
| | 21 | | | Subsidiaries of the Registrant |
| | 23 | .1 | | Consent of Ehrhardt Keefe Steiner & Hottman PC |
| | 23 | .2 | | Consent of Netherland Sewell and 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) |
| | 99 | .1 | | Calculation of the Maximum Notes Balance at December 31, 2005 under the Senior Secured Notes Facility Dated January 13, 2005 |