ITEM 1.
AND ITEM 2. BUSINESS AND PROPERTIES
GENERAL
Infinity Energy Resources, Inc. (“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 central Texas and in the Rocky Mountain region in the Greater Green River Basin in southwest Wyoming and the Sand Wash and Piceance Basins in northwest Colorado. Infinity is also pursuing an oil and gas exploration opportunity offshore Nicaragua in the Caribbean Sea. In addition, we provide oilfield services in eastern Kansas, northeast Oklahoma and northeast Wyoming through our wholly-owned subsidiary, Consolidated Oil Well Services, Inc. (“Consolidated”). As used in this report, Infinity, we and our refer 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 69%, or 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, 2005 were an estimated 16.1 billion cubic feet of gas equivalent (“Bcfe”) with a PV-10 Value (as defined below) of $44.0 million (after-tax PV-10 Value of $43.5 million). During 2005, we purchased reserves in place of approximately 0.8 Bcfe, discovered proved reserves of approximately 6.9 Bcfe, produced approximately 1.2 Bcfe, and experienced net positive revisions of approximately 0.4 Bcfe for a net increase of approximately 6.9 Bcfe.
Subsequent to December 31, 2005 and through March 3, 2006, we have drilled four additional wells and completed two of those wells as producers and two are waiting completion (all in the Fort Worth basin). Activities subsequent to December 31, 2005 were not taken into account in the proved reserve estimate as of December 31, 2005, but will 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 950 Seventeenth Street, Suite 800, Denver, Colorado 80202. Our telephone number is (720) 932-7800. Our website is http://www.infinity-res.com. The information on the website does not constitute part of this Annual Report on Form 10-K.
Infinity-Texas
Infinity-Texas is engaged in the acquisition, exploration, development and production of natural gas in the Fort Worth Basin of north central Texas. This subsidiary is a Delaware corporation with its headquarters located in Denver, Colorado.
Infinity-Texas was formed in June 2004 to acquire, explore, develop and produce natural gas from the Barnett Shale formation and other producing formations in the Fort Worth Basin. The Barnett Shale is a marine shale formation that is natural gas bearing at depths believed to range from 1,000 to 8,500 feet and is believed to be ubiquitous across the Fort Worth Basin. Though this area has been well known for natural gas production for many years, improvements in fracture techniques and the employment of horizontal drilling in recent years have generally improved the economics of producing this reservoir. In addition, the predominance of leases in the region relate to fee acreage and therefore have relatively few operating restrictions and regulations, as compared to the typically federally-owned leases in the Rocky Mountain region that involve more operating restrictions and regulations.
During the three months ended December 31, 2004, Infinity-Texas drilled three gross (2.7 net) wells and completed one gross (0.9 net) well. During 2005, Infinity-Texas drilled an additional 5 wells (4.9 net) and completed seven wells (6.7 net), six as producers and one as a water disposal well. The initial wells were connected to an existing third-party pipeline system beginning 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, 2005, Infinity-Wyoming had total estimated proved reserves of 9.4 Bcfe.
Approximately 5.3 Bcfe of our proved oil and gas reserves were associated with tight sand properties in the Wamsutter Arch Pipeline Field in the Greater Green River Basin in southwest Wyoming (the “Pipeline Field”). Approximately 4.1 Bcfe of our proved reserves related to fractured Niobrara shale properties in the Sand Wash Basin in Colorado (the “Sand Wash Prospect”).
At December 31, 2005, Infinity-Wyoming operated all of its proved developed oil and gas locations. During the year ended December 31, 2005, Infinity-Wyoming drilled seven gross (and net) wells and completed six gross (and net) of such wells. Infinity-Wyoming also completed one 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 awaiting completion or abandonment operations in Wyoming. Operating the oil and gas properties in which it owns an interest allows Infinity-Wyoming to exercise greater control over operating costs, capital expenditures and the timing of exploration, development and exploitation activities.
Nicaragua
Since 1999, Infinity has pursued an oil and gas exploration opportunity offshore Nicaragua in the Caribbean Sea. Over such time period, the relationships which have been built with the Instituto Nicaraguense de Energia (“INE”) and the geological and geophysical research that was done allowed Infinity to become one of only six companies qualified to bid on offshore blocks in the first international bidding round held by INE in January 2003. Infinity was awarded the bid on 24 blocks of acreage, comprising approximately 1.4 million acres, in May 2003, and 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 2006.
Consolidated
Consolidated acquired assets necessary to provide oilfield services in eastern Kansas and northeast Oklahoma in January 1994. Consolidated expanded its operations into northeast Wyoming during September 1999. Consolidated provides pressure-pumping services associated with drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, 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 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 in eastern Kansas, including real property and facilities in Chanute, Kansas, to an exploration and production company
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 our Eureka facility.
BUSINESS STRATEGY
Our principal objective is to create stockholder value through the execution of a business strategy, the key elements of which include:
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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.
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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 (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 becoming a separate publicly traded entity.
We intend to finance our business strategies through employment of working 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 our Senior Secured Notes Facility, and as such, any disposition of material assets would require the approval of the note holders.
OILFIELD SERVICES
Consolidated provides pressure-pumping services associated with drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, 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. 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 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 Company’s Senior Secured Note Facility.
EXPLORATION AND PRODUCTION
This section is an explanation and detail of some of the relevant project groupings from our overall inventory of projects and prospects. Our operations are focused primarily in the Fort Worth Basin of Texas and the Greater Green River and Sand Wash Basins in the Rocky Mountain region. Our other area of interest is in the Caribbean Sea, offshore Nicaragua.
Fort Worth Basin
For purposes of presentation, we divide our Fort Worth Basin operations into two main property areas: Erath and Hamilton Counties, Texas and Comanche County, Texas.
Erath and Hamilton Counties, Texas
At December 31, 2005, Infinity-Texas held leases on approximately 40,000 gross (approximately 29,000 net) acres in this area located in the southwest portion of the Fort Worth Basin in north central Texas. Infinity-Texas currently seeks to explore for, develop and produce natural gas and natural gas liquids from the Barnett Shale, and possibly shallower formations. At December 31, 2005, Infinity-Texas operated eight gross (7.6 net) wells in the area, of which six were active producers, one was shut-in, and one was a water disposal well. Infinity-Texas has a 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 horizontally drilled three wells, completing one of those wells prior to yearend 2004. During 2005, Infinity-Texas horizontally drilled an additional four wells and completed six wells. Infinity-Texas also vertically drilled a water disposal well for the disposal of frac flowback fluids and water produced from its wells in the area. During 2005, Infinity-Texas acquired and interpreted approximately 25 square miles of 3-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 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 of 3-D seismic data generally over the southern portion of its Erath County acreage.
Comanche County, Texas
At December 31, 2005, Infinity-Texas held leases on approximately 30,000 gross (and net) acres in this area, located approximately 30 miles southwest of the Erath and Hamilton County properties. 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 by April 9, 2006. Infinity-Texas expects to commence drilling operations by April 1, 2006.
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, 2005, Infinity-Wyoming held leases on approximately 20,500 gross acres (approximately 18,100 net acres) located on the Wamsutter Arch in the Greater Green River Basin of southwest Wyoming. Infinity-Wyoming currently seeks to exploit hydrocarbons in the cretaceous-aged Upper Almond sand at varying depths between 2,800 and 3,600 feet. At December 31, 2005, Infinity-Wyoming operated 37 wells in the field, of which 21 were active producers, 8 were shut-in, 3 were water disposal wells, and 5 were awaiting completion or plugging and abandonment operations.
During 2005, Infinity-Wyoming produced approximately 670,000 Mcf of natural gas and 25,000 barrels of crude oil, or 820,000 thousand cubic feet of natural gas equivalent (“Mcfe”) from the field, compared to 930,000 Mcf of natural gas and 33,000 barrels of crude oil, or 1,130,000 Mcfe produced from the field in 2004. Production during 2005 represented a 27% decrease from 2004. Production has generally declined since peaking in the quarter ended March 31, 2003.
Production from our Wamsutter Arch Pipeline Field during January and February 2006 was negatively impacted by freeze-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 levels at the Pipeline Field have returned to near-normal levels.
Labarge Field
At December 31, 2005, Infinity-Wyoming held leases on approximately 11,500 gross (and 11,000 net) acres located on the northern extension of the Moxa Arch in southwest Wyoming and held options on an additional approximately 18,000 gross acres. Infinity-Wyoming currently seeks to exploit hydrocarbons in the Cretaceous Upper Mesaverde coals at varying depths between 3,400 and 4,200 feet. At December 31, 2005, Infinity-Wyoming operated 12 wells in the field, of which 10 were shut-in, and 2 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 12,000 Mcf of natural gas from the field during 2005, as compared to approximately 24,000 Mcf of natural gas during 2004. Production during 2005 represented a 50% decrease as compared to 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 generally uneconomic. The completed and recompleted wells 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 2006. Depending on the results of dewatering and the availability of equipment, we may commence drilling and completion activities during the fourth quarter of 2006.
Northwest Colorado
For purposes of presentation, we divide our northwest Colorado operations into two main property areas: Sand Wash Prospect and Piceance Basin Prospect.
Sand Wash Prospect
At December 31, 2005, Infinity-Wyoming held leases on approximately 53,700 gross acres (approximately 46,900 net acres) located in the Sand Wash Basin of northwest Colorado and south central Wyoming. Infinity-
Wyoming currently seeks to explore and develop hydrocarbons in the fractured Niobrara calcareous shale between 5,500 and 6,500 feet. Secondary objectives include exploiting the Williams Fork and Iles coals at varying depths between 2,500 and 3,000 feet.
At December 31, 2005, Infinity-Wyoming operated two producing oil properties and four shut-in wells in the field which were completed in the coals. Drilling was suspended for the winter on one well targeting the fractured Niobrara shale. 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, Infinity-Wyoming produced approximately 53,000 gross barrels (43,000 net barrels) of oil from this field.
Infinity-Wyoming plans to conduct additional geological and geophysical studies to identify potential additional oil locations. As it pertains to the Williams Fork and Iles coals, Infinity-Wyoming suspended dewatering efforts at the original pilot location in 2004 due to the onset of winter and the 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 prior to determining what additional operations, if any, to perform.
Piceance Basin Prospect
At December 31, 2005, Infinity-Wyoming held leases on approximately 9,100 gross (and net) acres in the northeastern corner of the Piceance Basin in northwest Colorado. The acreage is located along the northern rim of the Piceance Basin and the southern extent of the Axial Basin Arch. Immediately adjacent to the prospect are several large oil and gas fields which were discovered and developed as early as 1927. Most notable of these is the Wilson Creek field to the south which has produced approximately 90 million barrels of oil and 75 Bcf of natural gas. Primary reservoir targets would include the Niobrara fractured shale and the Dakota and Morrison-Brushy Creek sandstone formations. Secondary reservoir targets might include the Mesaverde sands and coals, Morrison-Salt Wash, Entrada, Shinarump, Moenkopi, Weber and Morgan-Minturn formations. Infinity-Wyoming plans to conduct additional geological and potentially geophysical studies in 2006 to identify potential 2007 drilling opportunities.
Nicaragua
Since being awarded two concessions in 2003, Infinity has negotiated a number of key terms and conditions of an exploration and production contract covering the approximate 1.4 million acre Tyra (approximately 823,000 acres in the north) and Perlas (approximately 566,000 acres in the south) concession areas offshore Nicaragua. The contract 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 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 total less than $1.0 million, with a total of less than $2.0 million during the second twelve months, to cover costs of environmental studies, geological and geophysical analysis, acquisition of seismic data and other operational expenses.
Exploration offshore Nicaragua would focus on Eocene and Cretaceous Carbonate reservoirs and Infinity’s management and consultants believe: (i) numerous analogies can be made between the Infinity concession block and production from fractured Cretaceous carbonates in Mexico, Venezuela and Guatemala and (ii) the presence of Cretaceous source rocks onshore Honduras and Nicaragua can be projected into the offshore Caribbean Shelf. Infinity plans to seek offers from another industry operator or operators for interests in the acreage in exchange for cash and a carried interest in exploration and development operations. No assurance can be given that any such transactions will be consummated.
Oil and Natural Gas Reserves
We engaged Netherland, Sewell & Associates, Inc., independent petroleum engineers, to prepare estimates of proved reserves, projected future production and related future net revenue for our properties as of December 31, 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, 2005 were utilized. Activity subsequent to December 31, 2005 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, 2005, but will be reflected in future estimates.
The following table sets forth estimates as of December 31, 2005 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 17 - Supplemental Oil and Gas Information (Unaudited) in the Notes to the Consolidated Financial Statements.
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, 2005 were $8.21 per Mcf of natural gas and $60.74 per barrel of crude oil.
Production, Prices and Production Costs
The following table sets forth Infinity’s net oil and gas production, average sales prices realized, and costs and expenses associated with such production during the years indicated.
Infinity owned 28 gross (25.7 net) producing wells and 6 gross (6 net) service wells as of December 31, 2005. Infinity owned an additional 26 gross (25.9 net) wells which were shut in, awaiting completion or plugging and abandonment operations as of December 31, 2005.
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 (in thousands):
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.
As of December 31, 2005, Infinity had an additional 7 wells which were drilled in 2005 or prior awaiting completion, including 4 wells waiting likely plugging and abandonment operations.
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, 2005. Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation.
Infinity-Wyoming held options on an additional approximately 18,000 gross acres in the Labarge field as of December 31, 2005. The table does not reflect any reclassification of our acreage to reflect wells completed after December 31, 2005.
Customers and Markets
Exploration and Production
The majority of Infinity-Wyoming’s gas production from the Pipeline Field is sold to Duke Energy Field Services under a forward contract, 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 fixed price contracts to hedge its production when market conditions are deemed favorable in
order to manage price fluctuations and achieve a more predictable cash flow. The following table identifies the one contract in place at December 31, 2005:
(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 2005, this was a price of $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 and 2003:
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.
Oilfield Services
Consolidated provides its services to oil and gas developers and lease operators throughout eastern Kansas and northeast Oklahoma, which includes the Cherokee, Forest City and Salina Basins, and in the Powder River Basin of northeast Wyoming. Consolidated also provides its services in the Arkoma basin of eastern 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. The following table sets out information about Consolidated’s major customers during each of these periods:
Consolidated has provided services to Infinity-Wyoming 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 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.
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
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:
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Acquisition of desirable producing properties or new leases for future exploration;
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Marketing our oil and natural gas production; and
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Seeking to acquire the services, equipment, labor and materials necessary to explore, operate and develop those properties.
Many of our competitors have financial and technological resources substantially exceeding those available to Infinity. Many oil and gas properties are sold in a competitive bidding process in which we may lack technological information or expertise available to other bidders. We cannot be sure that we will be successful in acquiring and developing profitable properties in the face of this competition.
Oilfield Services
Consolidated’s competition for cementing services in eastern Kansas and 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, Superior Well Services, Inc., Oilwell Fracturing Services, Inc. and Maverick Stimulation Company, LLC. Other less significant competitors in these areas include BJ Services Company, 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 companies, 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 ensure 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 service their own 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. Additionally, the Company had annual volume commitments for five years starting September 1, 2001. If the Company exceeded the
minimum in any year, the excess reduced the following year’s commitment. If the Company did not meet the minimum in any year, the shortfall was added to the following years. To date, Infinity-Wyoming has delivered approximately 4,000,000 Mcf under this contract. The Pipeline sales volumes are also subject to a $0.15 per MMBtu charge for access onto the Overland Trail Transmission line. While Infinity-Wyoming has failed to deliver the volumes required under the terms of the contract, the pipeline operators have also not provided the compression and gathering capabilities they were required to provide under the contract. Management has received a verbal commitment from the operator that the volume commitments would be adjusted and management does not expect that there will be a contract shortfall under the renegotiated 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 was for the period April 1, 2004 through March 31, 2005 at 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, 2005, other than those shown above, to provide quantities of oil or gas in the future.
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, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to Infinity, we cannot predict the overall effect of such laws and regulations on our future operations.
Infinity believes that its operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and regulations and is qualified as mentioned above.
Federal Regulation of the Sale of Oil and Gas
Various aspects of Infinity’s oil and natural gas operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In the past, the federal government has regulated the prices at which oil and gas could be sold. While “first sales” by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B, 636-C and 636-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 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
Various federal, state and local laws and regulations relating to the protection of the environment affect our operations and costs. The areas affected include:
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unit production expenses primarily related to the control and limitation of air emissions, spill prevention and the disposal of produced water;
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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;
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capital costs to construct, maintain and upgrade equipment and facilities;
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operational costs associated with ongoing compliance and monitoring activities; and
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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 costs and/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 civil and/or criminal fines and liability for non-compliance, clean-up costs and other environmental damages. It is also possible that unanticipated developments or changes in law could cause us to make environmental expenditures significantly greater than those we currently expect.
The following is a summary discussion of the framework of key environmental and land use regulations and requirements affecting our oil and natural gas exploration, development, production and transportation operations.
Discharges to Waters. The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and comparable state statutes impose restrictions and controls, primarily through the issuance of permits, on the discharge of produced waters and other oil and natural gas wastes into regulated waters and wetlands. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future, including potential restrictions on the use of hydraulic fracturing. These laws prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters without a permit.
The Clean Water Act also regulates stormwater discharges from industrial properties and construction activities and requires separate permits and implementation of a stormwater management plan establishing best management practices, training, and periodic monitoring. Certain operations are also required to develop and implement “Spill Prevention, Control, and Countermeasure” plans or Facility Response Plans to address potential oil spills.
The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It also imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances into regulated waters.
Oil Spill Regulations. The Oil Pollution Act of 1990, as amended (the “OPA”), amends and augments oil spill provisions of the Clean Water Act, imposing potentially unlimited liability on responsible parties, without regard to fault, for the costs of cleanup and other damages resulting from an oil spill in U.S. waters. Responsible parties include (i) owners and operators of onshore facilities and pipelines and (ii) lessees or permittees of offshore facilities.
Air Emissions. Our operations are subject to local, state and federal regulations governing emissions of air pollution. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies including the MMS, BLM and state agencies.
We may generate wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, although certain oil and natural gas exploration and production wastes currently are exempt from regulation under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA (“Hazardous Wastes”). Furthermore, it is possible that
certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes, and therefore be subject to more rigorous and costly operating, disposal and clean-up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both on- and off-shore.
Superfund. Under some environmental laws, such as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, also known as CERCLA or the Superfund law, and similar state statutes, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon any current or former site owners or operators, or upon any party who discharged one or more designated substances (“Hazardous Substances”) at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of Hazardous Substances, in the course of our operations we may have generated and may generate wastes that fall within CERCLA’s definition of Hazardous Substances. We may also be an owner or operator of facilities at which Hazardous Substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.
Abandonment and Remediation Requirements. Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities, and the environmental restoration of operations sites. The Colorado Oil and Gas Conservation Commission, Wyoming Oil and Gas Conservation Commission and the Texas Railroad Commission are the principal state agencies and BLM the primary federal agency responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state. State and BLM regulations require operators to post performance bonds.
Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations
Significant potential costs relating to environmental and land use regulations associated with our existing properties and operations include those relating to (i) plugging and abandonment of facilities, (ii) clean-up costs and damages due to spills or other releases and (iii) civil penalties imposed for spills, releases or non-compliance with applicable laws and regulations.
Infinity-Texas, 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
operating within current environmental regulations during 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 drilled one disposal well in Erath County, Texas during 2005 at a cost of 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 sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, such as those described under “Risk Factors” In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us.
Employees
On December 31, 2005, Infinity and its subsidiaries had 143 employees. Consolidated had 125 employees in its oilfield services business; Infinity-Texas and Infinity-Wyoming had 14 employees in their exploration and production business; and Infinity had 4 employees in executive and administrative positions.
ITEM 1A.
ITEM 1A.
RISK 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
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:
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prices for oil and gas we produce may be lower than expected;
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the capital, equipment, personnel or services required to develop the leases for production may not be available;
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we may not find oil and gas reserves in the quantities anticipated;
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the reserves we find may not produce oil and gas at the rate anticipated;
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the costs of producing oil and gas may be higher than expected; and
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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:
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worldwide and domestic supplies of oil and gas;
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political instability or armed conflict in oil or gas producing regions;
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the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil prices;
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production controls;
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the price and level of foreign imports;
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worldwide economic conditions;
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marketability of production;
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the level of consumer demand;
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the price, availability and acceptance of alternative fuels;
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the price, availability and capacity of commodity processing and gathering facilities, and pipeline transportation;
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weather conditions; and
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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:
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impairing our financial condition, cash flows and liquidity;
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limiting our ability to finance planned capital expenditures;
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reducing our revenue, operating income and profitability;
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reducing the carrying value of our oil and natural gas properties; and
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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:
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our production is less than expected;
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the counterparties to our contracts fail to perform under the contracts; or
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our production costs on the contracted production significantly increase.
Exploration and development of our oil and gas projects will require large amounts of capital which we may not be able to obtain.
Full exploration and development of our properties could require drilling in excess of 1,000 production wells, 100 disposal wells to handle produced water, and the construction of 100 production facilities. This could require capital expenditures over time of in excess of $1 billion. Currently, our potential sources of financing for these 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-tax PV-10 Value of our proved reserves.
Future cash flows and the availability of financing are subject to a number of variables, such as:
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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;
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our success in locating and producing new reserves;
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prices of crude oil and natural gas;
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the level of production from existing wells; and
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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:
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all or a substantial portion of our operating cash flow being dedicated to the payment of principal and interest;
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an increase in interest expense as the amount of debt outstanding increases or as variable interest rates increase;
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increased vulnerability to competitive pressures and economic downturns; and
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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:
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it may be more difficult for us to satisfy our debt repayment obligations;
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covenant violations, if any, could result in accelerated payment terms on existing debt;
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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;
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we will need to use a portion of our revenue to pay principal and interest on our debt which will reduce the amount of money we have to finance our operations and other business activities; and
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substantially all of our properties are pledged as collateral to lenders and failure to pay could result in foreclosure and loss of assets.
As of March 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:
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any additional financing we obtain may be on unfavorable terms;
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we may have a higher level of debt than many of our competitors, which may place us at a competitive disadvantage;
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we may issue equity securities at an undesired or unanticipated point in time to repay indebtedness, causing additional dilution to our stockholders;
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we may be more vulnerable to economic downturns and adverse developments in our industry; and
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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:
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the quality and quantity of available data;
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the interpretation of that data;
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the accuracy of various mandated economic assumptions; and
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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.
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:
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the amount and timing of actual production;
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the price for which that oil and gas production can be sold;
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supply and demand for oil and natural gas;
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curtailments or increases in consumption by natural gas and oil purchasers; and
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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:
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defects in title;
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the absence of producible quantities of oil and gas;
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insufficient formation attributes, such as porosity, to allow production;
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water production requiring disposal; and
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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:
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availability and cost of equipment and transportation for the production;
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demand for the oil and gas produced; and
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price for the oil and gas produced.
Our business is subject to operating hazards that could result in substantial losses against which we may not be insured.
The oil and natural gas business involves operating hazards, any of which could cause substantial losses, such as:
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well blowouts;
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craterings;
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explosions;
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uncontrollable flows of oil, natural gas or well fluids;
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fires;
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formations with abnormal pressures;
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pipeline ruptures or spills; and
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releases of toxic gas and other environmental hazards and pollution.
As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. Our insurance premiums can be increased or decreased based on the claims made by us under insurance policies. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. Whenever possible, we obtain agreements from customers that limit our liability; however, insurance and customer agreements do not provide complete protection against losses and risks and losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.
In addition, we may be liable for environmental damage caused by previous owners of property we own or lease. As a result, we may face substantial potential liabilities to third parties or governmental entities that could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses. An event that is not fully covered by insurance - for instance, losses resulting from pollution and environmental risks that are not fully insured - could cause us to incur material losses.
We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.
In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is
reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired.
Exploratory drilling is an uncertain process with many risks.
Exploratory drilling involves numerous risks, including the risk that we will not find commercially productive natural gas or oil reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:
•
unexpected drilling conditions;
•
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.
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 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 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
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.
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
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 exercise of Infinity’s warrants issued in connection with the issuance of 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:
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 3, 2006 was $9.40 per share.
Approximate Number of Holders of Common Stock
At March 3, 2006, there were approximately 190 stockholders of record of Infinity’s $0.0001 par value Common Stock and an estimated 4,000 beneficial holders whose Common Stock is held in street name by brokerage houses.
Dividends
Holders of common stock are entitled to receive such dividends as may be declared by Infinity’s Board of Directors. Infinity has not declared nor paid and does not anticipate declaring or paying any dividends on its common stock in the near future. Any future determination as to the declaration and payment of dividends will be at the discretion of Infinity’s board of directors and will depend on then-existing conditions, including Infinity’s financial condition, results of operations, contractual restrictions, capital requirements, business prospects and such other factors as the board deems relevant. Pursuant to the terms of its Senior Secured Notes Facility, Infinity is prohibited from paying dividends.
ITEM 6.
SELECTED FINANCIAL DATA
The selected consolidated financial information presented below for the years ended December 31, 2005, 2004, 2003 and 2002, 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 31st from March 31st effective December 31, 2001. Certain reclassifications have been made to prior financial data to conform to the current presentation. The table gives effect to the two-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.
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 this Form 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 central Texas and Greater Green River, Sand Wash and Piceance Basins of southwest Wyoming and northwest Colorado; and (ii) providing oilfield services in the Mid-Continent region and the Powder River Basin of northeast 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 development 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, 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. Meanwhile, Infinity-Wyoming continued to explore and develop the various projects and prospects in the Rocky Mountains, but continues to be hampered by weather, governmental and environmental restrictions and regulations, as well as various operational issues at the Labarge, Pipeline and Sand Wash fields.
Infinity expects to continue to explore and develop its Fort Worth Basin acreage and its Rocky Mountain prospects. Infinity expects its Rocky Mountain projects to proceed more slowly, due in part to governmental restrictions. Infinity raised incremental debt and equity capital to fund its exploration operations from the net proceeds of the Senior Secured Notes Facility and from the proceeds of option and warrant exercises during 2005. In addition to expected increases in cash flows from operating activities, Infinity will likely require external financing during 2006 and beyond to fund its exploration 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 Infinity’s operations.
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 Statements and in the “Oil and Natural Gas Reserves” section of Item 1. and Item 2.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Infinity’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to Infinity’s crude oil and natural gas production. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Excluding sales under a fixed price contract 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 that period.
Infinity periodically enters into fixed-price physical contracts and commodity derivative contracts on a portion of its projected natural gas and crude oil production in accordance with its Energy Risk Management Policy. These activities are intended to support cash flow at certain levels by reducing the exposure to oil and gas price fluctuations. As of December 31, 2005, the Company had one fixed price physical contract in place with the following terms:
Sales under this fixed price contract are accounted for as normal sales agreements under the exemption in SFAS No. 133. For the years ended December 31, 2005 and 2004, the effect of Infinity’s sale of a portion of its gas production under a fixed price contract, compared to spot sales, was a decrease in revenue of approximately $1.4 million and $0.6 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:
Subsequent to December 31, 2005, the Company entered into the following costless collar arrangement:
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 on Form 10-Q or annual report on Form 10-K (a “Determination Date”), at least 20% of the Company’s estimate of its oil and gas production 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. It is the opinion of management that the Company was in compliance with this hedging requirement at December 31, 2005.
ITEM 8.
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 on Form 8-K” and contained in this Form 10-K commencing on page.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the fiscal year covered by this Annual Report on Form 10-K. The Company’s Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, the Company’s disclosure controls and procedures were effective.
Management’s Report on Internal Control over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of its assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of its financial statements in accordance with generally accepted accounting principles, and that its receipts and expenditures are being made only in accordance with authorizations of its management and directors; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on its financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management’s projections of any evaluation of the effectiveness of internal control over financial reporting as to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 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.
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 on Form 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 fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10:
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 2006 annual meeting of stockholders (the “Proxy Statement”).
ITEM 11:
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 on Form 10-K.
ITEM 12:
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 on Form 10-K.
ITEM 13:
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 on Form 10-K.
ITEM 14:
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 on Form 10-K.
PART IV
ITEM 15:
ITEM 15:
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of this report on Form 10-K or incorporated by reference.
(1) Our consolidated financial statements are listed on the “Index to Consolidated Financial Statements” on Page 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.
EXHIBITS
(1)
Incorporated by reference to our Registration Statement on Form 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 on Form S-3 filed on June 29, 2002 (File No. 333-96671).
(4)
Incorporated by reference to our Current Report on Form 8-K, filed on January 21, 2004.
(5)
Incorporated by reference to our Current Report on Form 8-K, filed on November 16, 2004.
(6)
Incorporated by reference to our Current Report on Form 8-K, filed on January 14, 2005.
(7)
Incorporated by reference to our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2000.
(8)
Incorporated by reference to our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2001.
(9)
Incorporated by reference to our Annual Report on Form 10-KSB for the transition period ended December 31, 2001.
(10)
Incorporated by reference to our Annual Report on Form 10-KSB for the fiscal year ended December 31, 2002.
(11)
Incorporated by reference to our Registration Statement on Form S-8 filed on July 15, 2004 (File No. 333-117390).
(12)
Incorporated by reference to our Registration Statement on form S-8 filed on August 29, 2005 (File No. 333-12794).
(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 Current Report on Form 8-K, filed on September 8, 2005.
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/ JAMES A. TUELL
James A. Tuell
President and Chief Executive Officer
Dated: March 8, 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:
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Infinity Energy Resources, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Infinity Energy Resources, Inc. as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. 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 in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Infinity Energy Resources, Inc. as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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 in Internal Control-Integrated Framework issued 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 in Internal Control-Integrated Framework issued 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
March 3, 2006
Denver, Colorado
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See Notes to Consolidated Financial Statements.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the years ended December 31, 2005, 2004 and
See Notes to Consolidated Financial Statements.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
See Notes to Consolidated Financial Statements.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization and Summary of Significant Accounting Policies
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 the acquisition and exploration of oil and gas properties in Nicaragua. In addition, the Company provides oilfield services in the Mid-Continent region and in northeast 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 & Gas of Wyoming, Inc., Infinity Oil and Gas of Texas, Inc., Infinity Oil & Gas of Kansas, Inc. and CIS - Oklahoma, Inc. All significant intercompany balances and transactions have been eliminated in consolidation.
Reclassifications
Certain prior period amounts in the accompanying consolidated financial statements have been reclassified to conform to the current year presentation.
Management Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to the consolidated financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative liabilities and the realizability of deferred tax assets.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents consist of cash on hand and demand deposits with financial institutions. At times, the Company maintains deposits in financial institutions in excess of federally insured limits. Management monitors the soundness of the financial institutions and believes the Company’s risk is negligible. The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
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
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 the first-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:
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.
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 exploration and development activities. Accordingly, all costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals and dry holes) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Overhead related to exploration and development activities is also capitalized. The Company capitalized $884,000, $652,000 and $49,000 of internal costs during the years ended December 31, 2005, 2004 and 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 ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current costs and prices, including the effects of derivative instruments accounted for as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.
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, respectively.
Depletion of proved oil and gas properties is computed on the units-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 amortized. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Asset Retirement Obligations
The Company records estimated future asset retirement obligations pursuant to the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the obligation is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to present value. The Company’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. Capitalized costs are depleted as a component of the full cost pool using the units of production method. The following table summarizes the activity for the Company’s asset retirement obligations for the years ended December 31, 2005, 2004 and 2003:
Capitalized Interest
The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized in 2005, 2004 and 2003 were $1,451,000, $635,000 and $382,000, respectively.
Intangible Assets
Intangible assets consist principally of loan costs and goodwill. Loan costs are amortized over the terms of the related debt instruments using the effective interest method. Goodwill is not amortized, but is reviewed for impairment at least annually. As of December 31, 2005, goodwill was not impaired.
The Company capitalizes amortization of loan costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Amortization of loan costs is capitalized only for the period that activities are in progress to bring these projects to their intended use. Total loan cost amortization capitalized for 2005, 2004 and 2003 was $261,000, $555,000 and $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 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 collection is reasonably assured.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Transportation Costs
The Company accounts for transportation costs under Emerging Issues Task Force Issue 00-10, Accounting for Shipping and Handling Fees and Costs, whereby amounts paid for transportation are classified as operating expenses.
Per Share Information
Basic earnings per share is computed by dividing net earnings from continuing operations by the weighted average number of shares of common stock outstanding during each period, excluding treasury shares. Diluted earnings per share is computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options, warrants and convertible debt.
Stock Options
The Company applies Accounting Principles Board (“APB”) Opinion No. 25, Accounting 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 been determined based upon the fair value at the grant date consistent with the methodology prescribed under SFAS No. 123, Accounting for Stock-Based Compensation, the Company’s net loss and loss per share would have been as follows (see Note 8):
For options granted during the years ended December 31, 2005, 2004 and 2003, the estimated fair value of the options granted utilizing the Black-Scholes pricing model under the Company’s plan was based on weighted average risk-free interest rates of 4.15%, 1.5% and 1.5%, respectively, expected option life of 10 years for 2005 and 2004 and 5 years for 2003, expected volatility of approximately 67%, 147% and 131%, respectively, and no expected dividends.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred taxes are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax asset. As of December 31, 2005 and 2004, the Company had recorded a full valuation allowance for its net deferred tax asset.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Comprehensive Income (Loss)
The Company has elected to report comprehensive income (loss) in the consolidated 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.
Recently Issued Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement 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. The pro forma disclosures, previously permitted under SFAS No. 123 will no longer 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.
SFAS No. 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two 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 provisions of SFAS No. 123(R) on January 1, 2006 using the modified prospective method. The adoption of SFAS No. 123(R) had no impact on the Company’s results of operations because all employee stock options outstanding at 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 under Stock 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 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. 155, Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140. SFAS No. 155 resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 will become effective for the Company’s fiscal year after September 15, 2006. The impact of
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.
Note 2 - Accounts Receivable
Accounts receivable consists of the following:
Note 3 - Property and Equipment
Property and equipment consists of the following:
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:
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During the years ended December 31, 2005, 2004 and 2003, the Company recorded amortization related to intangible assets of $1,735,000, $2,100,000 and $6,211,000, respectively.
Note 5 - Accrued Liabilities
Accrued liabilities consist of the following:
Note 6 - Debt
Debt consists of the following:
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Maturities of debt are as follows:
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 “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 “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 the 3-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).
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 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.
Under certain circumstances at quarterly intervals and over a three year period, Infinity has the option to sell additional Notes, along with additional Warrants, in amounts up to $15 million in any rolling twelve-month period, up to an additional $30 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 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 financial performance of Consolidated and the SEC after-tax PV-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.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Under the provisions of SFAS No. 133 and EITF 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.
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:
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:
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 and EITF 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 of EITF 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 the number of warrants outstanding if the Company sells stock at less than the exercise price. As a result of the private institutional placements of equity discussed above in January and November 2004, 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.
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:
The following table summarizes information about non-employee warrants and options outstanding at December 31, 2005:
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.
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:
The following table summarizes information about stock options outstanding at December 31, 2005:
Note 9 - Income Taxes
The provision for income taxes consists of the following:
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:
The significant temporary differences and carry-forwards and their related deferred tax asset (liability) and deferred tax asset valuation allowance balances are as follows:
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 long-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
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 minimum daily delivery volumes by up to 50%. Based on production volumes through December 31, 2005, the Company has accrued a liability of approximately $248,000 as a delivery commitment shortfall under the contract.
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 natural gas from certain of the Company’s Wyoming 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:
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.
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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:
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.
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 terms 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 of approximately $2.3 million and recognized a gain of approximately $292,000. In conjunction with the sale of the aircraft, the Company settled the related promissory note and accrued interest.
Note 17 - Supplemental Oil and Gas Information
Estimated Proved Oil and Gas Reserves (Unaudited)
Proved oil and gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
All of the Company’s proved reserves are located in the United States. The following information about the Company’s proved and proved developed oil and gas reserves was developed from reserve reports prepared by independent reserve engineers:
The 2003 revisions to the previous estimates 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.
INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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:
Costs Not Being Amortized
Oil and gas property costs not being amortized at December 31, 2005, by year that the costs were incurred are as follows:
Unevaluated costs include $5,897,000 relating to the Company’s Labarge prospect in southwest Wyoming. Substantially all of the acreage in the prospect is subject to an ongoing Bureau of Land Management environmental impact statement (“EIS”). The EIS must be completed before the Company can continue development. Unevaluated costs include approximately $1,160,000 relating to the Company’s concessions offshore Nicaragua. The Company expects to execute a definitive exploration and production contract covering the approximate 1,400,000 acres
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.
Oil and Gas Operations
Aggregate results of operations in connection with the Company’s oil producing activities are shown below:
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
Future oil and gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, except in those instances where the sale of oil and natural gas is covered by contracts, as required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities. SFAS No. 69 requires that net cash flow amounts be discounted at 10%. This information does not represent the fair market value of the Company’s proved oil and gas reserves.
The following table presents the average year-end spot market gas price and oil price used to compute future cash inflows for each period:
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 and 2003 assuming continuation of existing economic conditions.
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:
Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to the Company’s proved oil and gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company’s proved oil and gas reserves.
Note 18 - Quarterly Consolidated Financial Information (Unaudited)
The following table provides selected quarterly consolidated financial results for the years ended December 31, 2005 and 2004.
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 $4,100,000, respectively.
The Company restated net income (loss), earnings (loss) per share and earnings (loss) per diluted share for the first, second and third quarters of 2005 to correct the accounting for certain derivatives embedded in or resulting from the issuance of the Company’s senior secured notes in 2005.
EXHIBIT INDEX