Item 1. Business
Overview
Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects. The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in companies focused on commercializing environmentally preferred energy technologies.
Our Strategy
Our exploration strategy is predicated upon two core beliefs: (1) that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers and (2) that virtually all the exploration and production industry’s value creation occurs through the drilling of successful exploratory wells. As a result, our business strategy includes the following elements:
Funding exploration prospects generated by our alliance partners. We depend on our alliance partners for prospect generation expertise. Our alliance partners, Juneau Exploration, L.P. (“JEX”) and Alta Resources, LLC (“Alta”) perform all of our prospect generation and evaluation functions.
Using our capital availability to increase our reward/risk potential on selective prospects. Beginning in the spring of 2005, we decided to increase our capital investment in certain exploration prospects, including our onshore Arkansas Fayetteville Shale prospect and offshore Gulf of Mexico prospects. This represents a major increase in the risk profile of the Company, which in the past has limited its dry hole risk exposure on any one well to approximately $1.0 million. COI drills and operates our offshore prospects. Should we be successful in any of our offshore prospects, we will incur additional costs to complete development and bring the discovery to producing status.
Operating in the Gulf of Mexico. COI was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. COI has drilled four exploration wells in the Gulf of Mexico, of which two were successful, and is currently drilling one additional exploration well. This represents a significant increase in the risk profile of the Company since the Company has limited operating experience. Our estimated drilling costs could be significantly higher if we encounter difficultly in drilling offshore wells.
Arkansas Fayetteville Shale. We have made a major commitment to our Arkansas Fayetteville Shale program and this commitment is expected to continue to grow as we participate in the drilling of hundreds of gross exploration/development wells over the next five to ten years.
Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future may continue to sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to further our exploration, LNG and alternative energy investment activities. Since its inception, the Company has sold over $80.0 million worth of oil and natural gas properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.
Index to Financial Statements Controlling general and administrative and geological and geophysical costs. Our goal is to be among the most efficient in the industry in revenue and profit per employee and among the lowest in general and administrative costs. We plan to continue outsourcing our geological, geophysical, reservoir engineering and land functions. We currently have six employees.
Structuring transactions to share risk. Our alliance partners share in the upfront costs and the risk of our exploration prospects.
Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our partners, employees, and stockholders. Our directors and executive officers beneficially own approximately 26% of our common stock.
Exploration Alliances with JEX and Alta
Alliance with JEX. JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. JEX focuses on the Gulf of Mexico, and generates offshore exploration prospects via our affiliated companies, Republic Exploration, LLC (“REX”), Contango Offshore Exploration, LLC (“COE”) and Magnolia Offshore Exploration LLC (“MOE”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).
Alliance with Alta. Alta is a private company formed for the purpose of assembling domestic, onshore natural gas and oil prospects. Our arrangement with Alta generally provides for us to pay a disproportionate share of seismic and lease costs, with Alta generally receiving a negotiated overriding royalty interest (“ORRI”) and a carried or back-in working interest.
Onshore Exploration and Properties
Alta Activities
Arkansas Fayetteville Shale
In March 2005, Contango, Alta and another private company (the “Alta Group”) entered into a Participation Agreement to acquire natural gas, oil, and mineral leases in the Arkansas Fayetteville Shale play area located in Pope, Van Buren, Conway, Faulkner, Cleburne, and White Counties, Arkansas. As of August 31, 2006, the Alta Group has acquired or received commitments on approximately 44,000 net mineral acres at a cost of approximately $12.0 million. Contango has a 70% working interest prior to a basket payout. At project payout, Alta will be assigned a 20% reversionary working interest, proportionately reduced to Contango, Alta and the other participant. Alta will receive an ORRI in each lease assignment contingent on the amount of lease burden assigned to the third party royalty owners. Our 70% share of the lease acquisition costs as of August 31, 2006 is approximately $8.3 million.
The Arkansas Oil & Gas Commission has now approved thirteen 640-acre drilling units in Conway County, Arkansas that we estimate will allow our partnership to drill and operate approximately 117 horizontal wells. The horizontal wells are estimated to cost between $2.8 to $2.2 million each. We estimate our working interest and net revenue interest in these Alta operated wells will average approximately 45% and 35%, respectively. Alta intends to continue to seek approval from the Arkansas Oil & Gas Commission for additional 640-acre units.
In March 2006, we spud the first of the 21 wells currently planned to be operated by Alta during our fiscal-year ending June 30, 2007, the Alta-Beck #1-32H (the “Alta-Beck”) with a 38.65% working interest. We expect to complete the Alta-Beck and have pipeline hookup in February 2007. In June 2006, we spud the Alta-Briggler #1-31H, with a 69.74% working interest. We finished drilling in July 2006 and expect to begin producing in February 2007. In July 2006, we moved the rig onto the Alta-Thines #1-30H, with a 34.87% working interest.
Index to Financial Statements We completed drilling this well in August 2006, and anticipate completion and pipeline hookup in February 2007. The 8/8ths cost for drilling these three wells as of August 31, 2006 was $5.6 million ($2.5 million net to Contango). We encountered significant time and cost overruns over our pre-drill Authorization for Expenditure (“AFE”) estimates in all three wells. We estimate an additional 8/8ths cost of $3.8 million will be required for frac, completion and hook-up of the three wells. Our share of these costs will be $1.9 million. For the remaining 18 wells, our estimated costs in the 12 wells for which we have received an AFE as of August 31, 2006 is $11.2 million. Alta has executed a drilling contract with a second contract drilling company and we anticipate we will have two rigs running beginning in September 2006. We currently anticipate and are budgeting for Alta to operate both rigs throughout our fiscal year-end of June 30, 2007. Our plans and budgets, however, are subject to anticipated drilling improvements and cost efficiencies as we develop a learning curve from drilling multiple wells.
In addition, we have been integrated into 54 wells located in our Arkansas Fayetteville Shale play as of August 31, 2006, that are being operated by a third party independent oil and gas exploration company (“Integrated Wells”). Of these, three are vertical natural gas wells that are currently producing. Thirteen more are producing horizontal wells. Of the 16 producing wells, the 8/8ths production from 13 wells is over 15 million cubic feet per day (“MMcf/d”) as of August 31, 2006. Production data from the remaining three wells is not yet available. The remaining 38 horizontal wells are either currently being drilled or are expected to be drilled over the next three months with our net share of the total drilling costs estimated at $5.8 million. Our average working and net revenue interest in these 54 Integrated Wells thus far is 7.28% and 5.78%, respectively.
Other Drilling Activities
As a result of the Company’s intent to focus on developing our Arkansas Fayetteville Shale play and our offshore Gulf of Mexico prospects, we have discontinued our south Texas drilling program with Ameritex Minerals and Exploration, Ltd. and Coastline Exploration, Inc. We do anticipate, however, drilling three onshore wells in each of Louisiana, Texas and Alabama with Alta prior to our fiscal year-end June 30, 2007.
Offshore Gulf of Mexico Exploration Joint Ventures
Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of June 30, 2006, Contango and its affiliates had interests in 63 offshore leases. On August 16, 2006, REX was the apparent high bidder on three lease blocks at the Central Gulf of Mexico Lease Sale #200. To date, none of the lease blocks have been awarded. The outcome of the August 16 lease sale is being challenged in the U.S. District Court in New Orleans by the State of Louisiana. The sale covered areas in the western part of the Outer Continental Shelf, offshore from the Texas coastline. See “Offshore Properties” below for additional information on our offshore properties.
As of June 30, 2006, Contango owned a 42.7% equity interest in REX, a 76.0% equity interest in COE, and a 50.0% equity interest in MOE, all of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 3,900 blocks of 3-D seismic data and have focused on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed drilling obligations plus retained reversionary interests in favor of REX, COE and MOE.
Republic Exploration LLC. On September 2, 2005, Contango purchased an additional 9.4% ownership interest in REX for $5.625 million from JEX. As a result of this purchase, our equity ownership interest in REX increased from 33.3% to 42.7%. As of June 30, 2006, Contango had approximately $5.8 million invested in REX. The three other members of REX are JEX, its managing member, a privately held investment company, and a privately held seismic company. REX holds a non-exclusive license to approximately 2,083 blocks of 3-D seismic data in the shallow waters of the Gulf of Mexico. This data is used to identify, acquire and exploit natural gas and oil prospects. All leases owned by REX are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for more information on REX’s offshore properties.
Index to Financial Statements West Delta 43 (“Skip Jack”), a REX prospect was spud in June 2006 and determined to be a dry hole. Our dry hole costs were approximately $3.2 million.
Contango Offshore Exploration LLC. On September 2, 2005, Contango purchased an additional 9.4% ownership interest in COE for $1.875 million from JEX. As a result of this purchase, our equity ownership interest in COE increased from 66.6% to 76.0%. As of June 30, 2006, Contango had approximately $15.0 million invested in COE, which COE has used to acquire and reprocess 1,815 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. The two other members of COE are JEX, its managing member, and a privately held investment company. All leases are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on COE’s offshore properties.
Grand Isle 72 (“Liberty”), a COE prospect, was successfully tested in March 2006. We believe, subject to Gulf of Mexico weather conditions, that this well will be on-stream by November 2006, with an estimated initial 8/8ths equivalent production rate of 7-10 million cubic feet equivalent per day (“MMcfe/d”). COE has a 50% working interest and a 40% net revenue interest in this well, while COI has a 25% working interest and a 20% net revenue interest. Our third party partners have a 25% working interest and a 20% net revenue interest in the well.
During the year, COE borrowed $250,000 from the Company under a promissory note (the “Note”) to fund a portion of its share of development costs at Grand Isle 72. In July 2006, COE borrowed an additional $500,000 under the same Note. The Note bears interest at a per annum rate of 10% and is payable upon demand. We anticipate that COE will need to borrow an additional $1.5 million from the Company to complete pipeline hook-up and begin production.
Grand Isle 70, a COE prospect, was spud in July 2006 and proved to be a discovery. The well has been temporarily abandoned while alternative development scenarios are being evaluated. COE has a 52.6% working interest and a 42.1% net revenue interest in this well. Our third party partners have a 43.75% working interest and a 37.9% net revenue interest, and COI has a 3.65% working interest and a 0% net revenue interest.
Magnolia Offshore Exploration LLC. As of June 30, 2006, Contango had approximately $1.0 million invested in MOE. JEX is the only other member of MOE and acts as the managing member, deciding which prospects MOE may acquire, develop, and exploit. MOE’s license rights to 3-D seismic data have been assigned to COE. All leases are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on MOE’s offshore properties.
Current Activities. In August 2005, Hurricane Katrina struck the Gulf of Mexico and the Gulf Coast of the United States, and in September 2005, Hurricane Rita struck the same region. At the time, the Company did not operate or own any production platforms or pipeline facilities in the Gulf of Mexico. However, the Company did have a non-operating working interest or ORRI in three offshore blocks: Ship Shoal 358, Eugene Island 113-B and Eugene Island 76 and depends on third-party operators for the operation and maintenance of these production platforms. In the aftermath of the hurricanes, the Ship Shoal 358 and the Eugene Island 113-B platforms sustained damage and have now been repaired. Eugene Island-113B resumed production in April 2006, and at August 31, 2006 was producing at a rate of 7.7 MMcfe/d, while the Ship Shoal 358 A-3 well resumed production in April 2006 and on August 28, 2006 was producing at a rate of approximately 2.5 MMcfe/d. Contango’s net revenue interest in these wells is 3.1% and 5.8%, respectively. The Company was not responsible for any of the capital costs required to repair the damaged platforms, pipelines, or other damaged facilities related to these wells. The Company was not materially impacted by the temporary loss of production from these two wells. Eugene Island 76, a REX prospect, was successfully tested in 2005 and began producing in January 2006. The well is currently producing at approximately 7.5 MMcfe/d. Contango’s net revenue interest is 2.14%. REX owns an ORRI of 5% until payout, after which REX has the option to elect an 8.33% ORRI or a 25% working interest after payout.
Index to Financial Statements We are currently drilling our Eugene Island 10 (“Dutch”) prospect in the Gulf of Mexico, which is operated by COI. Our capital expenditure budget calls for us to invest approximately $3.7 million in estimated dry hole costs in the drilling of Eugene Island 10. In the event we have exploration success, our capital budget will be significantly increased as we will incur additional costs to complete the well and pay for production facilities. In the event Eugene Island 10 is determined to be a dry hole, we will incur a $5.4 million dry hole cost charge and an impairment charge of approximately $2.0 million. In the event of tropical storms or hurricanes in the Gulf of Mexico while Eugene Island 10 is drilling, our estimated dry hole costs could be significantly greater.
In March 2006, REX was awarded the following six lease blocks from the Central Gulf of Mexico Lease Sale #198 for an aggregate purchase price of approximately $0.9 million: South Marsh Island 57, South Marsh Island 59, South Marsh Island 75, South Marsh Island 282, Ship Shoal 14 and Ship Shoal 25. The blocks are complimentary to our existing Ship Shoal and South Marsh Island prospects. In June 2006, REX was awarded the Vermillion 194 and West Delta 77 lease blocks for an aggregate purchase price of approximately $1.8 million.
In April 2006, COE was awarded the following two lease blocks from the Central Gulf of Mexico Lease Sale #198 for an aggregate purchase price of approximately $1.4 million: Grand Isle Block 70 and Ship Shoal Block 263. In May 2006, COE was awarded the Viosca Knoll 119 and 383 lease blocks for an aggregate purchase price of approximately $0.4 million.
REX and COE have farmed out the following lease blocks: Main Pass 221, East Breaks 369/370, and Vermillion 154. Main Pass 221 was drilled and was determined to be a dry hole. East Breaks 369 and East Breaks 370 are expected to spud in 2007. COE will receive a 4.3% ORRI before project payout and a 7.2% ORRI after project payout on the East Breaks 369/370 prospects. Vermillion 154 has been farmed out, and the operator expects to drill an exploratory well prior to July 2008. During the fiscal year, two lease blocks, Viosca Knoll 116 and 119, were relinquished to the Minerals Management Service (“MMS”). West Delta 36 was farmed out during the last quarter and has been completed as a discovery. REX holds a 3.67% ORRI with an option at payout to increase the ORRI to 5% or convert the ORRI to a 25% working interest.
Record title interest in the Vermilion 73 and South Marsh Island 247 leases has been farmed out to a common third party. A timetable for drilling the two prospects has not yet been established. Under the farm-out agreement, REX reserves a 5% ORRI before payout in both prospects. In the Vermilion 73 prospect, REX also has the option after payout to maintain its 5% ORRI or acquire a 25% working interest in the prospect.
The MMS has implemented a rule on royalty relief for shallow water, deep shelf natural gas production from certain Gulf of Mexico leases. “Deep shelf gas” refers to natural gas produced from depths greater than 15,000 feet in waters of 200 meters or less. Royalty relief is available on the first 15 billion cubic feet (“Bcf”) of natural gas production if produced from an interval between 15,000 to less than 18,000 feet. Royalty relief is available on the first 25 Bcf of natural gas production if produced from an interval between 18,000 to less than 20,000 feet. Royalty relief is available on the first 35 Bcf of natural gas production if produced from well depths at or greater than 20,000 feet. This royalty relief is expected to have a positive impact on the economics of deep gas wells drilled on the shelf of the Gulf of Mexico.
Index to Financial Statements
Contango Operators, Inc.
COI is a wholly-owned subsidiary of Contango formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. As part of our strategy, COI will operate and acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement with either REX or COE. COI expects to take working interests in these prospects under the same arms-length terms offered to industry third party participants. COI may also operate and acquire significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.
Current Activities. The Company had an offshore exploration discovery at its Grand Isle 72 (“Liberty”) prospect in March 2006. As of August 31, 2006, the Company has invested approximately $8.6 million to drill and complete this well. We estimate an additional $1.8 million will be required to build production and pipeline facilities to commence production. We believe the well will be on-stream by November 2006, with an estimated initial 8/8ths equivalent production rate of 7-10 MMcfe/d. The net revenue interests to COI and COE after well completion is estimated to be 20% and 40%, respectively.
COI began drilling its Eugene Island 10 (“Dutch”) prospect in July 2006. COI will pay a 35% working interest through completion of the well and will pay an 18.3% working interest thereafter. After a back-in by the farmors of the block, this working interest will be reduced to 13.75%. REX will pay a 15% working interest through completion and will have a 65% working interest thereafter, reduced to 48.75% after the farmors’ back-in. COI’s share of the dry hole costs is estimated to be $3.7 million. The prospect is being drilled under a fixed turn-key drilling contract. The net revenue interests to COI and REX, should the well be successful, and after the farmors’ back-in working interest, is estimated to be 11% and 39%, respectively.
In the event Dutch is successful, the Company will have the opportunity to drill additional wells but may be required to pay higher costs for rigs and related marine services as a result of the demand for such equipment related to generally strong commodity prices and the demand for offshore services.
COI began drilling the High Island A279 (“Juice”) in June 2006, and determined it to be a dry hole. Our dry hole costs were approximately $2.7 million.
Offshore Properties
Producing Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which are producing natural gas or oil as of August 31, 2006:
(1) REX has a 5% of 8/8ths ORRI in the lease before payout. At payout, REX may elect to either (i) escalate its ORRI in the lease from 5% to 8 1/3% of 8/8ths or (ii) convert the 5% ORRI to a 25% working interest (“WI”).
Index to Financial Statements Farmed-Out Properties. The following table sets forth the working interests and net revenue interests owned by Contango and related entities in the Gulf of Mexico which have been farmed out as of August 31, 2006:
(2) REX and COE will split a 25% back-in WI after payout.
(3) REX will retain a 3.67% ORRI before payout. Upon payout REX will either increase to 5% ORRI or convert to a 25% WI after payout.
(4) COE has a 5% of 8/8ths ORRI before payout. Upon payout, COE’s ORRI will escalate to 7.2% of 8/8ths.
(5) COE will receive a 4.27% ORRI before project payout and a 7.27% ORRI after project payout.
(6) Record title interest in lease has been assigned to a third party. REX has a 5% of 8/8ths ORRI in the lease before payout. At payout, REX may elect to either (i) maintain its 5% ORRI in the lease or (ii) convert the 5% ORRI to a 25% WI.
(7) Record title interest in lease has been assigned to a third party. REX has reserved a 5% of 8/8ths ORRI before payout.
Farmed-In Properties. The following table sets forth the working interests and net revenue interests owned by Contango and related entities in the Gulf of Mexico which have been farmed in as of August 31, 2006:
(8) COI has a 35% WI through completion, an 18.3% WI after completion, and a 13.75% WI following a farmor back-in of 25%. COI will be awarded the lease on a produce-to-earn basis. REX has a 15% WI through completion, a 65.0% WI after completion, and a 48.75% W following a farmor back-in of 25%.
(9) COI has a 46.7% WI before casing point and a 37.5% working interest after casing point.
Index to Financial Statements Leases. The following table sets forth the working interests owned by Contango and related entities in the Gulf of Mexico as of August 31, 2006:
Index to Financial Statements
(10) REX was the apparent high bidder. Lease block has not yet been awarded. Due to pending litigation between the State of Louisiana and the MMS, we do not know if or when these leases will be awarded.
Freeport LNG Development, L.P.
As of June 30, 2006, the Company has invested $3.2 million and owns a 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”), a limited partnership formed to develop, construct and operate a 1.5 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas.
In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the financing, construction and use of the LNG receiving terminal in Freeport, Texas. ConocoPhillips executed a terminal use agreement for 1.0 Bcf/d of regasification capacity, purchased a 50% interest in the general partner managing the Freeport LNG project and agreed to provide construction funding to the venture. This construction funding is non-recourse to Contango. The Dow Chemical Company (“Dow Chemical”) has also executed a terminal use agreement for regasification capacity of 500 MMcf/d and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Freeport LNG is responsible for the commercial activities of the partnership, while ConocoPhillips, under a construction advisory and management agreement, is managing the construction of the facility.
In January 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the Federal Energy Regulatory Commission (the “FERC”) and construction of the 1.5 Bcf/d
Index to Financial Statements facility commenced on January 17, 2005. The terminal’s Phase I capacity has been sold to ConocoPhillips (1.0 Bcf/d) and Dow Chemical (0.5 Bcf/d) and construction is expected to be completed by January 2008. The engineering, procurement and construction contractor is a consortium of Technip USA, Zachry Construction of San Antonio, and Saipem SpA of Italy.
A majority of the Freeport LNG financing for Phase I is being provided by ConocoPhillips through a construction loan, with debt service being provided by the terminal use agreement with ConocoPhillips. Additional financing has been obtained through a $383.0 million private placement note issuance by Freeport LNG which closed on December 19, 2005. The funds from the notes are being used to fund the balance of the Phase I construction of Freeport LNG’s liquefied natural gas regasification terminal. The funds will also be used to fund the development of an integrated natural gas storage salt cavern and a portion of the cost of an expansion of the LNG terminal (“Phase II”). The notes are secured primarily by payments obligated under the terminal use agreement with Dow Chemical.
Phase II expansion of the LNG terminal may include a second LNG unloading dock, additional send-out and additional storage capacity. Expansion applications have been submitted to the FERC and other governmental agencies and assuming approval of these applications in late 2006, Phase II capacity could be available in late 2009. Part of the Phase II capacity has been sold to MC Global Gas Corporation, a wholly-owned subsidiary of Mitsubishi Corporation and to ConocoPhillips under long-term contracts. Expansions of the terminal included in the current applications are planned and will be constructed as additional capacity is sold.
Although we anticipate that we may, from time-to-time, be required to provide funds to the Freeport LNG project, and intend to provide our pro rata 10% of any required equity participation, we believe the project will continue through Phase I construction and Phase II pre-development with no further significant funds likely being required from Contango.
Contango Venture Capital Corporation
As of June 30, 2006, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in the three alternative energy companies described below. Our investment in these companies is less than 20% and we account for these investments under the cost method.
Trulite, Inc. As of June 30, 2006, CVCC had invested $0.9 million in Trulite, Inc. (“Trulite”) in exchange for 2,001,014 shares of Trulite common stock, which represents an approximate 17% ownership interest. Trulite develops lightweight hydrogen generators for fuel cell systems. In August 2006, the Company loaned $125,000 to Trulite under a promissory note (the “Trulite Note”). The Trulite Note bears interest at a per annum rate of 11.25% until February 9, 2007, at which point the per annum rate will change to prime rate plus three percentage points. All principal and accrued and unpaid interest on the Trulite Note is due on May 1, 2007.
Moblize Inc. As of June 30, 2006, CVCC had invested $0.6 million in Moblize Inc. (“Moblize”) in exchange for 324,324 shares of Moblize convertible preferred stock, which represents an approximate 19% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas industry using open-standards based technologies. Moblize is currently deploying its technology in oil fields near Houston belonging to Chevron U.S.A. Inc. and on our Grand Isle 72 development, which will allow COI to remotely monitor, control and record, in real time, daily production volumes.
In August 2006, the Company exercised its right pursuant to two warrants, to purchase an additional 324,324 shares of Moblize convertible preferred stock for $0.6 million. This brings the Company’s total investment in Moblize to $1.2 million, with approximately a 33% ownership interest.
Gridpoint, Inc. In May 2006, CVCC invested $1.0 million in Gridpoint, Inc. (“Gridpoint”) in exchange for 333,333 shares of Gridpoint preferred stock, which represents an approximate 3% ownership interest.
Index to Financial Statements Gridpoint’s intelligent energy management (IEM) products ensure clean, reliable power, increase energy efficiency, and integrate renewable energy. With GridPoint, residential and business owners can protect themselves from power outages, manage their energy online and reduce their carbon footprint. GridPoint’s “plug-and-play” appliances are easy to install and are sold through a network of premium home builders, utilities, retail chains and government entities as well as installers and contractors of electrical, heating, air-conditioning, home automation, power quality and renewable energy systems.
In June 2004, CVCC acquired a 32% membership interest in Contango Capital Partnership Management, LLC (“CCPM”) for $0.5 million. CCPM was formed by us and other investors to invest in the energy venture capital market. CVCC is the 25% limited partner of, and CCPM is the general partner of, Contango Capital Partners, L.P., which was formed in January 2005 for the purpose of investing in the energy venture capital market. Contango Capital Partners, L.P. then formed Contango Capital Partners Fund, L.P. (the “Fund”).
On January 31, 2005, the Fund was closed to new investments with a total capitalization of $8.2 million in the form of contributed stock, cash, and future cash commitments. Prior to CVCC holding a direct interest in Trulite and Moblize, the Fund previously held these investments. The Fund also had an investment in Synexus Energy, Inc. (“Synexus”). Synexus is a portable and stationary fuel cell integrator developing technology with a lightweight fuel cell stack that will create both portable and stationary power solutions for customers.
During the year ended June 30, 2006, the Fund invested an additional $0.8 million in Trulite, $0.6 million in Moblize, and an additional $1.0 million in Synexus. In April 2006, Trulite acquired Synexus’ technology. In May 2006, the Fund distributed its pro rata shares of Trulite to CVCC. In June 2006, the Fund sold its investment in Moblize to CVCC for $0.6 million.
As of June 30, 2006, CVCC owns 25% of the Fund. The Fund currently holds a direct investment in the two alternative energy companies described below. We account for these investments under the equity method. CCPM is the general partner of the Fund.
Protonex Technology Corporation. As of June 30, 2006, the Fund has invested $1.5 million in Protonex Technology Corporation (“Protonex”) in exchange for 2,400,000 shares of Protonex stock, which represents an approximate 7% ownership interest. Protonex provides long-duration portable and remote power sources with a focus on providing solutions to the U.S. military and supplies complete power solutions and application engineering services to original equipment manufacturers customers. During the period, Protonex began trading its common shares on the AIM market of the London Stock Exchange under the symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At June 30, 2006, the Fund’s investment in Protonex had a mark-to-market value of approximately $3.8 million.
Jadoo Power Systems. The Fund has invested approximately $1.2 million and owns 2,200,000 shares of Jadoo Power Systems (“Jadoo”) stock, which represents an approximate 5% ownership interest. Jadoo develops high energy density power products for the law enforcement, military and electronic news gathering applications. As of June 30, 2006, the Fund’s investment in Jadoo had a valuation of approximately $1.2 million.
Since the Fund’s inception, the Company has recorded a cumulative $0.8 million increase to our investment resulting primarily from unrealized gains of the Fund as a result of mark-to-market adjustments that have been made due to the increase in the value of our alternative energy investments, bringing our total investment in alternative energy investments, including cumulative mark-to-market adjustments, as of June 30, 2006, to approximately $4.5 million, consisting of $3.7 million of cash invested and $0.8 million of aggregate fund mark-to-market increases, net of equity earnings and losses.
Index to Financial Statements
Marketing and Pricing
The Company currently derives its revenue principally from the sale of natural gas and oil. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas and oil prices. The Company currently sells its natural gas and oil on the open market at prevailing market prices. Market prices are dictated by supply and demand, and the Company cannot predict or control the price it receives for its natural gas and oil. The Company has outsourced the marketing of its offshore natural gas and oil production volume to a privately-held third party marketing firm.
Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:
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The domestic and foreign supply of natural gas and oil
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Overall economic conditions
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The level of consumer product demand
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Adverse weather conditions and natural disasters
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The price and availability of competitive fuels such as heating oil and coal
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Political conditions in the Middle East and other natural gas and oil producing regions
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The level of LNG imports
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Domestic and foreign governmental regulations
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Potential price controls and special taxes
Competition
The Company competes with numerous other companies in all facets of its business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise.
Governmental Regulations
Federal Income Tax. Federal income tax laws significantly affect the Company’s operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development costs” and to claim depletion on a portion of its domestic natural gas and oil properties based on 15% of its natural gas and oil gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas).
Environmental Matters. Domestic natural gas and oil operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) also known as the “Super Fund Law”. The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.
The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage
Index to Financial Statements of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.
The Company’s onshore operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general. Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s operations are also subject to additional federal, state and local laws and regulations relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.
The Company believes that, in the course of conducting its natural gas and oil operations, the costs attributable to environmental control facilities were not considered material to the Company’s overall operations. For the fiscal year ending June 30, 2007, the Company does not anticipate any material capital expenditures for environmental control facilities.
Other Laws and Regulations. Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.
The MMS administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea floor. The MMS requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. Prior to the Company’s decision to act as the operator in the drilling of offshore prospects, the Company was required by the MMS to obtain surety bonds, typically providing $50,000 in coverage per lease, an amount of coverage that ensures a minimum level of performance. As an operator, however, the Company is required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities.
Index to Financial Statements The FERC has embarked on wide-ranging regulatory initiatives relating to natural gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC’s rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the natural gas prices received by the Company for the sale of its production, the FERC’s actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated natural gas producers and sellers.
Government Regulation of LNG Operations. Our LNG operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and other laws. Among other matters, these laws require the acquisition of certain permits and other authorizations before commencement of construction and operation of an LNG receiving terminal. Failure to comply with such rules, regulations and laws could result in substantial penalties.
In order to site, construct and operate the Freeport LNG receiving terminal, authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (the “NGA”) was required. The FERC permitting process includes detailed engineering and design work, extensive data gathering, preparation and final issuance of an Environmental Impact Statement under the National Environmental Policy Act, and public notices and opportunities for public hearings relating to:
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Siting requirements
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Design standards
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Construction standards
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Equipment, operations and maintenance
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Personnel qualifications and training
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Fire protection
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Security
The FERC approved the project in June 2004. On January 2005, the FERC granted Freeport LNG authorization under Section 3 of the NGA to site, construct and operate an LNG receiving terminal and to construct a 9.4 mile pipeline, together with related facilities, in Brazoria County, Texas. The Freeport LNG send-out pipeline will not interconnect with any interstate natural gas pipelines and will not be used to provide interstate transportation service under the NGA.
Other Federal Governmental Permits, Approvals and Consultations. In addition to the FERC authorization under Section 3 of the NGA, the construction and operation of LNG receiving terminals is also subject to additional federal and state permits, approvals and consultations including: Texas Commission on Environmental Quality, U.S. Coast Guard, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency (the “EPA”) and U.S. Department of Homeland Security and the Advisory Counsel on Historic Preservation.
Environmental Matters. LNG operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. In some cases, these laws and regulations could require Freeport LNG to obtain governmental authorizations before conducting certain activities or may require Freeport LNG to limit certain activities in order to protect endangered or threatened species or sensitive areas. These environmental laws may impose substantial penalties for noncompliance and substantial liabilities for
Index to Financial Statements pollution. As with the industry generally, compliance with these laws increases the overall cost of business. Environmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations.
Employees
We have six employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We are dependent on our alliance partners for prospect generation, evaluation and prospect leasing. As a working interest owner, we rely on outside operators to drill, produce and market our natural gas and oil for our onshore prospects and certain offshore prospects where we are a non-operator. In the offshore prospects where we are the operator, we rely on a turn-key contractor to drill and will rely on independent contractors to produce and market our natural gas and oil. In addition, we utilize the services of independent contractors to perform field and on-site drilling and production operation services and an independent third party engineering firm to calculate our reserves.
Directors and Executive Officers
The following table sets forth the names, ages and positions of our directors and executive officers:
Name
Age
Position
Kenneth R. Peak
Chairman, President, Chief Executive Officer,
Chief Financial Officer, Secretary and Director
Lesia Bautina
Senior Vice President and Controller
Sergio Castro
Vice President and Treasurer
Marc Duncan
President & Chief Operating Officer, Contango Operators, Inc.
Jay D. Brehmer
Director
Charles M. Reimer
Director
Steven L. Schoonover
Director
Darrell W. Williams
Director
Kenneth R. Peak. Mr. Peak has been Chairman and CEO of Contango since its formation in September 1999. Mr. Peak entered the energy industry in 1972 as a commercial banker and held a variety of financial and executive positions in the oil and gas industry prior to starting Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University in 1967, and an MBA from Columbia University in 1972. He currently serves as a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to exploration and production companies in North America.
Lesia Bautina. Ms. Bautina joined Contango in November 2001 as Controller and was appointed Vice President and Controller in August 2002. In July 2005, Ms. Bautina was promoted to Senior Vice President. Prior to joining Contango, Ms. Bautina worked as an auditor for Arthur Andersen LLP from 1997 to 2001. Her primary experience is accounting and financial reporting for exploration and production companies. Ms. Bautina received a degree in History from the University of Lvov in the Ukraine in 1990 and a BBA in Accounting in 1996 from Sam Houston State University, where she graduated with honors. Ms. Bautina is a Certified Public Accountant and member of the Petroleum Accounting Society of Houston.
Sergio Castro. Mr. Castro joined Contango in March 2006 as Treasurer and was appointed Vice President and Treasurer in April 2006. Prior to joining Contango, Mr. Castro spent two years as a Litigation Consultant for UHY Advisors TX, LP. From 2001 to 2004, Mr. Castro was a lead credit analyst for Dynegy Inc. From 1997 to 2001, Mr. Castro worked as an auditor for Arthur Andersen LLP, where he specialized in energy companies. Mr. Castro was honorably discharged from the U.S. Navy in 1993 as an E-6, where he served onboard a nuclear powered submarine. Mr. Castro received a BBA in Accounting in 1997 from the University of Houston, graduating summa cum laude. Mr. Castro is a Certified Public Accountant and a Certified Fraud Examiner.
Index to Financial Statements Marc Duncan. Mr. Duncan joined Contango Oil & Gas Company in June 2005 as President and Chief Operating Officer of Contango Operators, Inc. Mr. Duncan has over 25 years of experience in the energy industry and has held a variety of domestic and international engineering and senior-level operations management positions relating to natural gas and oil exploration, project development, and drilling and production operations. Prior to joining Contango, Mr. Duncan served in a senior executive position with USENCO International, Inc. and related companies in China and Ukraine from 2000-2004 and as a senior project and drilling engineer for Hunt Oil Company from 2004-2005. He holds an MBA in Engineering Management from the University of Dallas, an MEd from the University of North Texas and a BS in Science and Education from Stephen F. Austin University.
Jay D. Brehmer. Mr. Brehmer has been a director of Contango since October 2000. Mr. Brehmer is Managing Director of Catalina Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank. From November 2002 until August 2004, he advised various energy and energy-related companies on corporate finance and merger and acquisition activities through Southplace, LLC. From May 1998 until November 2002, Mr. Brehmer was responsible for structured-finance energy related transactions at Aquila Energy Capital Corporation. Prior to joining Aquila, Mr. Brehmer founded Capital Financial Services, which provided mid-cap companies with strategic merger and acquisition advice coupled with prudent financial capitalization structures. Mr. Brehmer holds a BBA from Drake University in Des Moines, Iowa.
Charles M. Reimer. Mr. Reimer was elected as a director of Contango in 2005. Mr. Reimer is President of Freeport LNG Development, L.P, and has experience in exploration, production, liquefied natural gas (“LNG”) and business development ventures, both domestically and abroad. From 1986 until 1998, Mr. Reimer served as the senior executive responsible for the VICO joint venture that operated in Indonesia, and provided LNG technical support to P. T. Badak. Additionally, during these years he served, along with Pertamina executives, on the board of directors of the P.T. Badak LNG plant in Bontang, Indonesia. Mr. Reimer began his career with Exxon Company USA in 1967 and held various professional and management positions in Texas and Louisiana. Mr. Reimer was named President of Phoenix Resources Company in 1985 and relocated to Cairo, Egypt, to begin eight years of international assignments in both Egypt and Indonesia. Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President and Chief Executive Officer of Cheniere Energy, Inc.
Steven L. Schoonover. Mr. Schoonover was elected as a director of Contango in 2005. Mr. Schoonover currently serves as Chief Executive Officer of Cellxion, L.L.C., a company specializing in construction and installation of telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. From 1990 until its sale in November 1997 to Telephone Data Systems, Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-service cellular telephone company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with two different companies, Entrepreneur of the Year, sponsored by Ernst & Young, Inc Magazine and USA Today.
Darrell W. Williams. Mr. Williams has been a director of Contango since 1999. Mr. Williams is President and CEO of Porta-Kamp International LP, which specializes in the manufacture, supply and construction of remote area housing, and CEO of Clearwater Environmental Systems, a manufacturer of sewage and water treatment systems. From 2002 until 2005, Mr. Williams was Managing Director of Catalina Capital Advisors, LP. Prior to joining Catalina, Mr. Williams was in senior executive positions with Deutug Drilling, GmbH (1993-2002), Nabors Drilling (1988-1993), Pool Company (1985-1988), Baker Oil Tools (1980-1983), SEDCO (1970-1980), Tenneco (1966-1970), and Humble Oil (1964-1966). Mr. Williams graduated from West Virginia University with a degree in Petroleum Engineering in 1964. Mr. Williams is past Chairman of the Houston Chapter of International Association of Drilling Contractors, a life member of the Society of Petroleum Engineers and a registered professional engineer in Texas.
Index to Financial Statements Directors of Contango serve as members of the board of directors until the next annual stockholders meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of Contango are elected by the board of directors and hold office until their successors are chosen and qualified, until their death or until they resign or have been removed from office. All corporate officers serve at the discretion of the board of directors. During the fiscal year ended June 30, 2006, each outside director received a quarterly retainer of $5,000 and a quarterly stock option grant to purchase 3,000 shares of common stock. Each outside director also receives a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting attended. The Chairman of the Audit Committee receives an additional quarterly stock option grant to purchase 1,500 shares of common stock. There are no family relationships between any of our directors or executive officers.
Corporate Offices
We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. Effective June 1, 2004, we increased our office space from 2,850 square feet to 5,377 square feet. Our agreement provides for a monthly rental of $9,970 per month through October 2006. We expect to exercise our option to extend our lease term for five years, beginning on November 1, 2006.
Code of Ethics
We adopted a Code of Ethics for senior management in December 2002. A copy of our Code of Ethics is filed as an exhibit to this Form 10-K and is also available on our Website at www.contango.com.
Available Information
General information about us can be found on our Website at www.contango.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our Website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission.
Index to Financial Statements
Item 1A.
Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss. The risk factors listed below are not all inclusive.
We have outsourced the marketing of our production and have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices would have a material adverse effect on our revenues, profitability and growth.
Our revenues, profitability and future growth will depend significantly on natural gas and crude oil prices. Prices received also will affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and will affect our ability to raise additional capital. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:
• The domestic and foreign supply of natural gas and oil.
• Overall economic conditions.
• The level of consumer product demand.
• Adverse weather conditions and natural disasters.
• The price and availability of competitive fuels such as heating oil and coal.
• Political conditions in the Middle East and other natural gas and oil producing regions.
• The level of LNG imports.
• Domestic and foreign governmental regulations.
• Potential price controls and special taxes.
We depend on the services of our chairman, chief executive officer and chief financial officer, and implementation of our business plan could be seriously harmed if we lost his services.
We depend heavily on the services of Kenneth R. Peak, our chairman, chief executive officer, and chief financial officer. We do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.
We are highly dependent on the technical services provided by our alliance partners and could be seriously harmed if our alliance agreements were terminated.
Because we have only six employees, none of whom are geoscientists or petroleum engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of one or more of our alliance partners could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by our alliance partners of certain explorationists could have a material adverse effect on our operations as well.
Index to Financial Statements Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.
Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and will require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, our credit facility imposes limits on our ability to borrow under the facility based on adjustments to the value of our hydrocarbon reserves, and our credit facility limits our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.
We lack experience as Operator in drilling high pressure wells in the Gulf of Mexico.
Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico and is a recent addition to our business strategy. COI is currently the operator for our exploration prospect at Eugene Island 10. Although as a company we have previously taken working interests in offshore prospects, our recent exploration prospects are the first wells in which we have assumed the role of operator. Estimated drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells.
Drilling activities are subject to numerous risks, including the risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including inexperience as an operator, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and we cannot assure that new wells will be productive or that we will recover all or any portion of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.
We may have excessive resources committed to our Arkansas Fayetteville Shale Play.
During fiscal year 2006, we invested $7.7 million in our Arkansas Fayetteville Shale play. Our capital budget for our fiscal year ending June 30, 2007 calls for us to invest over $40 million in the Arkansas Fayetteville Shale. This represents approximately 75% of our exploration and development budget, and approximately 70% of our total CAPEX budget. We intend to borrow significant capital against anticipated revenues and production, and should the wells not perform as expected, we will likely encounter difficulty repaying this debt. There can be no assurance that our drilling activity in this area will produce economically feasible wells. It is early in the process and we are still learning how to drill, complete, frac and produce these wells. Additionally, all of our wells are operated by outside companies. As a result, we have a limited ability to exercise influence over operations or their associated costs and risks.
Increasing capital investment in certain prospects increases our dry hole risk exposure.
Beginning in the spring of 2005, we decided to increase our capital investment in certain exploration
Index to Financial Statements prospects, including our onshore Arkansas Fayetteville Shale prospect and our offshore Gulf of Mexico prospects. From July 1, 2005 through August 31, 2006, we have invested, or committed to invest, approximately $24.4 million in our offshore prospects, and $17.8 million in the Arkansas Fayetteville Shale. This represents a major increase in the risk profile of the Company which in the past has limited its dry hole risk exposure on any one well to approximately $1.0 million.
The construction of our LNG receiving terminal in Freeport, Texas is subject to various development and completion risks.
We own a 10% limited partnership interest in the Freeport LNG receiving facility that is being constructed in Freeport, Texas. The LNG project received approval from the Federal Energy Regulatory Commission (the “FERC”) in June 2004. On January 11, 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the FERC. Construction of the 1.5 Bcf/d facility commenced on January 17, 2005. Freeport LNG is seeking an additional order from the FERC that would authorize the construction of an expansion that would increase the capacity at its currently permitted 1.5 Bcf/d Freeport LNG terminal to 2.6 Bcf/d. The LNG receiving facility is subject to development risk such as permitting, cost overruns and delays. Key factors that may affect the completion of the LNG receiving terminal include, but are not limited to: timely issuance of necessary additional permits, licenses and approvals by governmental agencies and third parties; sufficient financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; environmental conditions; unforeseen events, such as hurricanes, explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.
If completion of the LNG receiving facility is delayed beyond the estimated development period, the actual cost of completion may increase beyond the amounts currently estimated in our capital budget. A delay in completion of the LNG receiving facility would also cause a delay in the receipt of revenues projected from operation of the facility, which may cause our business, results of operations and financial condition to be substantially harmed.
If we are not able to fund or finance our 10% ownership in the LNG receiving facility in Freeport, Texas, including any expansion of the facility, we may lose our 10% investment in the project.
A majority of the Freeport LNG financing is being provided by ConocoPhillips through a $620.0 million construction loan, with debt service being provided by the terminal use agreement with ConocoPhillips. Additional financing has been obtained through a $383.0 million private placement note issuance by Freeport LNG which closed on December 19, 2005. The notes are secured primarily by payments obligated under the terminal use agreement with Dow Chemical. Upon any significant increase in construction costs to complete construction of the receiving facility or upon a call to fund construction of the proposed expansion, we may not have the financial resources to fund our 10% ownership share of construction costs. If we are unable to fund our share of the project costs or if the project is unable to secure third-party project financing, we could lose our investment in the project or be forced to sell our interest in an untimely fashion or on less than favorable terms.
If we default on our Sundance loan we could lose our 10% investment in the LNG receiving facility in Freeport, Texas.
Our three-year $20.0 million term loan agreement dated April 27, 2006 with The Royal Bank of Scotland plc is secured with the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG Development, LP, which owns the Freeport LNG facility. If an event of default occurs under the term loan agreement, we could lose our investment in the Freeport LNG facility.
Index to Financial Statements Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.
Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves.
The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.
In order to prepare these estimates, our independent third party petroleum engineer must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Some of the producing wells included in our reserve report have produced for a relatively short period of time. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.
You should not assume that the pre-tax net present value of our proved reserves prepared in accordance with SEC guidelines referred to in this report is the current market value of our estimated natural gas and oil reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.
We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineers.
We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to us by our independent third party reservoir engineers. If those reports
Index to Financial Statements prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.
Exploration is a high risk activity, and our participation in drilling activities may not be successful.
Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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Unexpected drilling conditions.
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Blowouts, fires or explosions with resultant injury, death or environmental damage.
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Pressure or irregularities in formations.
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Equipment failures or accidents.
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Tropical storms, hurricanes and other adverse weather conditions.
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Compliance with governmental requirements and laws, present and future.
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Shortages or delays in the availability of drilling rigs and the delivery of equipment.
Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations.
In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.
The natural gas and oil business involves many operating risks that can cause substantial losses.
The natural gas and oil business involves a variety of operating risks, including:
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Blowouts, fires and explosions.
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Surface cratering.
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Uncontrollable flows of underground natural gas, oil or formation water.
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Natural disasters.
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Pipe and cement failures.
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Casing collapses.
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Stuck drilling and service tools.
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Abnormal pressure formations.
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Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.
If any of these events occur, we could incur substantial losses as a result of:
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Injury or loss of life.
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Severe damage to and destruction of property, natural resources or equipment.
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Pollution and other environmental damage.
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Clean-up responsibilities.
Index to Financial Statements
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Regulatory investigations and penalties.
•
Suspension of our operations or repairs necessary to resume operations.
Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.
If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
Not hedging our production may result in losses.
Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.
Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems and pipelines that transport our natural gas and oil.
All of our natural gas and oil is transported through gathering systems and pipelines, which we do not own. Transportation capacity on gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations.
We have no assurance of title to our leased interests.
Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of our alliance partners to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. We have no assurance, however, that any such deficiencies have been cured by the operator of any such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.
Index to Financial Statements Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than most of our competitors.
We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Most of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.
We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment. Failure to comply with such rules and regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations may:
• Require that we obtain permits before commencing drilling.
• Restrict the substances that can be released into the environment in connection with drilling and production activities.
• Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas.
• Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.
Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated factual developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could have an adverse effect on our business and results of operations.
We cannot control the activities on properties we do not operate.
Other companies currently operate properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:
• Timing and amount of capital expenditures.
• The operator’s expertise and financial resources.
• Approval of other participants in drilling wells.
• Selection of technology.
Index to Financial Statements Acquisition prospects are difficult to assess and may pose additional risks to our operations.
We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to increase our domestic natural gas and oil reserves. The successful acquisition of natural gas and oil properties requires an assessment of:
• Recoverable reserves.
• Exploration potential.
• Future natural gas and oil prices.
• Operating costs.
• Potential environmental and other liabilities and other factors.
• Permitting and other environmental authorizations required for our operations.
In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.
Future acquisitions could pose additional risks to our operations and financial results, including:
• Problems integrating the purchased operations, personnel or technologies.
• Unanticipated costs.
• Diversion of resources and management attention from our exploration business.
• Entry into regions or markets in which we have limited or no prior experience.
• Potential loss of key employees, particularly those of the acquired organization.
We do not currently intend to pay dividends on our common stock.
We have never declared or paid a dividend on our common stock and do not expect to do so in the foreseeable future. Our current plan is to retain any future earnings for funding growth, and, therefore, holders of our common stock will not be able to receive a return on their investment unless they sell their shares.
Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely effect a potential acquisition by third parties that may ultimately be in the financial interests of our stockholders.
Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of inhibiting fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts, preventing changes in our management or limiting the price that investors may be willing to pay for shares of common stock. These provisions, among other things, authorize the board of directors to:
• Designate the terms of and issue new series of preferred stock.
• Limit the personal liability of directors.
• Limit the persons who may call special meetings of stockholders.
• Prohibit stockholder action by written consent.
• Establish advance notice requirements for nominations for election of the board of directors and for proposing matters to be acted on by stockholders at stockholder meetings.
• Require us to indemnify directors and officers to the fullest extent permitted by applicable law.
• Impose restrictions on business combinations with some interested parties.
Index to Financial Statements Our common stock is thinly traded.
Contango has approximately 15 million shares of common stock outstanding, held by approximately 124 holders of record. Directors and officers own or have voting control over approximately 4 million shares. Since our common stock is thinly traded, the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Description of Properties
Production, Prices and Operating Expenses
The following table presents information regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas and oil for the periods indicated. Oil and condensate are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil or condensate is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas.
Index to Financial Statements
Development, Exploration and Acquisition Capital Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:
Drilling Activity
The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells.
(1) The Company has not drilled any development wells since fiscal year 2004, when it drilled one gross development well (0.8 net developmental wells). The well was a productive well.
Exploration and Development Acreage
Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2006:
(1) Excludes any interest in acreage in which we have no working interest before payout or before initial production.
(2) Developed acreage consists of acres spaced or assignable to productive wells.
(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
(4) Gross acres refer to the number of acres in which we own a working interest.
(5) Net acres represent the number of acres attributable to an owner’s proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).
Index to Financial Statements Included in the Offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango has in the offshore acreage owned by its partially owned subsidiaries. The above table includes (i) our 42.7% interest in Republic Exploration LLC’s 101,197 net undeveloped acres, (ii) our 76.0% interest in Contango Offshore Exploration LLC’s 3,000 net developed acres and 77,463 net undeveloped acres, and (iii) our 50% interest in Magnolia Offshore Exploration LLC’s 13,640 net undeveloped acres. In addition, the Company holds royalty interests in approximately 31,092 gross undeveloped acres (779 net undeveloped acres) and 10,000 gross developed acres (261 net developed acres), offshore in the Gulf of Mexico.
Productive Wells
The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2006:
(1) Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally producing wells are not considered here as a “productive” well.
(2) A gross well is a well in which we own an interest.
(3) The number of net wells is the sum of our fractional working interests owned in gross wells.
Natural Gas and Oil Reserves
The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net present value of our reserves at June 30, 2006, based on a reserve report generated by W.D. Von Gonten & Co. The pre-tax net present value, discounted at 10%, is not intended to represent the current market value of the estimated natural gas and oil reserves we own.
The pre-tax net present value of future cash flows attributable to our proved reserves prepared in accordance with SEC guidelines as of June 30, 2006 was based on $6.09 per million British thermal units (“MMbtu”) for natural gas at the NYMEX and $73.93 per barrel of oil at the West Texas Intermediate Posting, in each case before adjusting for basis, transportation costs and British thermal unit (“Btu”) content. For further information concerning the present value of future net cash flows from these proved reserves, see “Supplemental Oil and Gas Disclosures”.
Index to Financial Statements The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
It should not be assumed that the pre-tax net present value is the current market value of our estimated natural gas and oil reserves. In accordance with requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
Item 3.
Item 3. Legal Proceedings
As of the date of this Form 10-K, we are not a party to any legal proceedings and we are not aware of any proceeding contemplated against us.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
During the quarter ended June 30, 2006, no matters were submitted to a vote of security holders.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock was listed on the American Stock Exchange in January 2001 under the symbol “MCF”. The table below shows the high and low closing prices of our common stock for the periods indicated.
On August 31, 2006, the closing price of our common stock on the American Stock Exchange was $13.30 per share, and there were approximately 15 million shares of Contango common stock outstanding, held by approximately 124 holders of record.
Index to Financial Statements We have not declared or paid any dividends on our shares of common stock and do not currently anticipate paying any dividends on our shares of common stock in the future. Currently, except for the regular dividends that we pay on our preferred stock, our plan is to retain any future earnings for use in the operations and expansion of our natural gas and oil exploration business and as needed in our LNG and alternative energy activities. Our credit facilities currently prohibit us from paying any cash dividends on our common stock. The credit facilities do, however, permit the payment of stock dividends on our common stock. Any future decision to pay dividends on our common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital requirements, and other factors our board may deem relevant.
On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The sale of the Series D preferred stock was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, as a transaction not involving a public offering. The Series D preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $12.00 per share. The dividend on the Series D preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. We used the net proceeds to fund our Arkansas Fayetteville Shale play, to fund our offshore Gulf of Mexico deep shelf exploration program, to fund our alternative energy investments, and for working capital and general corporate purposes. We have filed a registration statement with the Securities and Exchange Commission, covering the 833,330 shares of common stock issuable upon conversion of the Series D preferred stock.
On July 19, 2005, we exercised our mandatory conversion rights pursuant to the terms of our Series C preferred stock, and converted all of the 1,400 shares of our Series C preferred stock issued and outstanding at that time into 1,166,662 shares of common stock. The outstanding shares of the Series C preferred stock prior to their conversion, had a face value of $7.0 million, and paid a 6.0% per annum quarterly cash dividend. The shares of common stock issued upon conversion of the Series C preferred stock are registered with the Securities and Exchange Commission.
The following table sets forth information about our equity compensation plan at June 30, 2006:
No equity securities of the Company were repurchased during the fiscal year ended June 30, 2006. We do not have a publicly announced program to repurchase shares of our common stock.
Index to Financial Statements
Item 6.
Item 6. Selected Financial Data
(1) EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, impairment expenses, exploration expenses, including gain (loss) from hedging activities, and sale of assets and other. We have reported EBITDAX because we believe EBITDAX is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. We believe EBITDAX assists investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization, impairment of natural gas and oil properties and exploration expenses, which can vary significantly depending upon accounting methods. EBITDAX is not a calculation based on U.S. generally accepted accounting principles and should not be considered an alternative to net income (loss) in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash, which are disclosed in our statements of cash flows. Investors should carefully consider the specific items included in our computation of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service, preferred stock dividends and other commitments.
Index to Financial Statements Item 6. Selected Financial Data - continued
A reconciliation of EBITDAX to income (loss) from operations and operating results for discontinued operations for the periods indicated is presented below.
Index to Financial Statements
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report.
Overview
Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects. The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in companies focused on commercializing environmentally preferred energy technologies.
Revenues and Profitability. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable and the completion and successful operation of our Freeport LNG project. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.
Reserve Replacement. Generally, our producing properties in the Arkansas Fayetteville Shale and offshore in the Gulf of Mexico have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire natural gas and oil reserves.
Sale of proved properties. From time-to-time as part of our business strategy, we have sold, and in the future may continue to sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to further our exploration, LNG and alternative energy investment activities.
Use of Estimates. The preparation of our financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oil reserves and the timing and costs of our future drilling, development and abandonment activities.
Please see “Risk Factors” on page 18 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.
Results of Operations
The following is a discussion of the results of our operations for the fiscal year ended June 30, 2006, compared to the fiscal year ended June 30, 2005 and for the fiscal year ended June 30, 2005, compared to the fiscal year ended June 30, 2004.
Revenues. All of our revenues are from the sale of our natural gas and oil production. Our revenues may vary significantly from year to year depending on changes in commodity prices and production volumes.
Index to Financial Statements The table below sets forth revenue and production data for both continuing and discontinued operations for the fiscal years ended June 30, 2006, 2005 and 2004:
* Not meaningful
Natural Gas and Oil Sales. We reported natural gas and oil sales from discontinued and continuing operations of approximately $5.8 million for the year ended June 30, 2006, down from approximately $16.3 million reported for the year ended June 30, 2005. The decrease in revenue was primarily the result of the $11.6 million property sale effective April 1, 2006 and the property sale to an independent oil and gas company for $2.0 million, effective February 1, 2006, and the property sale to Edge Petroleum Corporation (“Edge Petroleum”) for $50.0 million, completed in December 2004. Of the $16.3 million revenue reported for the year ended June 30, 2005, $15.2 million was attributed to the sold properties. The remaining $1.1 million of revenue for 2005 is more comparable to the $0.9 million for 2006. The slight decrease mainly reflects normal production declines. Of the $5.8 million of natural gas and oil sales for the year ended June 30, 2006, $0.9 million relates to continuing operations from our offshore activities and the Arkansas Fayetteville Shale.
We reported natural gas and oil sales from discontinued and continuing operations of approximately $16.3 million for the year ended June 30, 2005, down from approximately $27.6 million reported for the year ended June 30, 2004. The decrease in revenue was primarily the result of the sale of our south Texas natural gas and oil interests to Edge Petroleum Corporation (“Edge Petroleum”) completed in December 2004 along with normal production declines in our existing south Texas properties. These declines were partially offset by increases in average prices received for our natural gas and oil production. Of the $16.3 million of natural gas and oil sales for the year ended June 30, 2005, and the $27.6 million of natural gas and oil sales for the year ended June 30, 2004, $1.1 million and $0.1 million, respectively, relates to continuing operations from our offshore and onshore activities.
Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the year ended June 30, 2006 was approximately 1.2 MMcf/d, down from approximately 5.8 MMcf/d for the year ended June 30, 2005. Net oil production for the period was down from 139 barrels of oil per day to 100 barrels of oil per day. The decrease in natural gas and oil production was primarily the result of the property sale effective April 1, 2006, the property sale to an independent oil and gas company effective February 1, 2006, and the sale of our south Texas natural gas and oil interests to Edge Petroleum effective July 1, 2004. For the year ended June 30, 2006, prices for natural gas and oil were $8.24 per Mcf and $55.74 per barrel, compared to $6.53 per Mcf and $48.13 per barrel for the year ended June 30, 2005.
For the year ended June 30, 2005, our net natural gas production was approximately 5.8 MMcf/d, down from approximately 11.8 MMcf/d for the year ended June 30, 2004. Net oil production for the period was down from 272 barrels of oil per day to 139 barrels of oil per day. These decreases primarily were due to normal
Index to Financial Statements production declines in our existing south Texas properties and the sale of non-core producing properties in Brooks County, Texas. For the year ended June 30, 2005, prices for natural gas and oil were $6.53 per Mcf and $48.13 per barrel, up from $5.65 per Mcf and $31.99 per barrel for the year ended June 30, 2004.
Gain (loss) from Hedging Activities. The Company did not engage in any hedging activity for the fiscal years ended June 30, 2006 and 2005. We reported a gain from hedging activities for the year ended June 30, 2004 of $58,171.
Operating Expenses. Operating expenses, including severance taxes, for the year ended June 30, 2006 was a credit of approximately $1.5 million. Included in this amount was a $2.1 million credit for production and severance taxes and approximately $0.6 million of lease operating expense. The Railroad Commission of Texas has extended a natural gas incentive allowing for severance tax reduction on tight sand gas wells. As a result, some of our former south Texas properties were eligible for severance tax reduction. Comparable low levels of severance taxes should not necessarily be expected in future reporting periods. The $2.1 million credit for severance taxes was attributable to previously paid severance taxes from our south Texas properties, which we sold in December 2004 to Edge Petroleum. Of the $1.5 million credit of operating expenses for the year ended June 30, 2006, $0.01 million in lease operating expenses relates to continuing operations from our offshore activities and Arkansas Fayetteville Shale.
Operating expenses, including severance taxes, for the year ended June 30, 2005 were approximately $1.2 million. Included in this amount was approximately $1.5 million of lease operating expense, approximately $0.3 million for workover costs and a $0.6 million credit for production and severance taxes as a result of the natural gas incentive provided by the Railroad Commission of Texas. Of the $1.2 million of operating expenses for the year ended June 30, 2005, $0.02 million relates to continuing operations from our offshore and onshore activities.
Operating expenses, including severance taxes, for the year ended June 30, 2004 were approximately $3.9 million. Of this amount, approximately $3.1 million was attributable to lease operating expense and approximately $0.8 million was attributable to production and severance taxes as a result of the natural gas incentive provided by the Railroad Commission of Texas. Of the $3.9 million of operating expenses for the year ended June 30, 2004, $0.09 million relates to continuing operations from our offshore and onshore activities.
Exploration Expense. We reported approximately $9.3 million of exploration expenses for the year ended June 30, 2006. Of this amount, approximately $2.0 million was related to unsuccessful wells drilled in south Texas and Alabama, approximately $5.9 million was related to unsuccessful wells drilled in the Gulf of Mexico during the period, approximately $0.5 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore along the Gulf Coast and offshore in the Gulf of Mexico, approximately $0.6 million was attributable to the cost of delay rentals, and approximately $0.3 million was attributable to other exploration expenses. Of the $9.3 million of exploration expenses for the year ended June 30, 2006, $8.2 million relates to continuing operations from our offshore activities and the Arkansas Fayetteville Shale.
We reported approximately $6.6 million of exploration expenses for the year ended June 30, 2005. Of this amount, approximately $3.8 million was related to unsuccessful wells drilled in south Texas, approximately $0.8 million was related to unsuccessful wells drilled in the Gulf of Mexico during the period, approximately $1.6 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore along the Gulf Coast and offshore in the Gulf of Mexico, and $0.4 million was attributable to the cost of delay rentals. Of the $6.6 million of exploration expenses for the year ended June 30, 2005, $5.9 million relates to continuing operations from our offshore and onshore activities.
We reported approximately $9.9 million of exploration expenses for the year ended June 30, 2004. Of this amount, approximately $3.6 million was attributable to dry holes drilled in south Texas ($2.8 million) and to our unsuccessful well drilled in France ($0.8 million), approximately $2.7 million was attributable to seismic costs and delay rentals associated with activities onshore in south Texas and approximately $3.6 million was attributable to seismic costs and delay rentals associated with activities offshore in the Gulf of Mexico. Of the $9.9 million of exploration expenses for the year ended June 30, 2004, $6.4 million relates to continuing operations from our offshore and onshore activities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended June 30, 2006 was approximately $1.2 million. For the year ended June 30, 2005, we recorded approximately $2.8 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily the result of the sale of our producing south Texas and Alabama properties. There was no depreciation, depletion and amortization expense recorded in the fourth quarter of 2006 related to those properties since those properties were classified as held for sale as of March 2006 and subsequently sold. Of the $1.2 million of depreciation, depletion and amortization for the year ended June 30, 2006, $0.2 million relates to continuing operations from our offshore activities and the Arkansas Fayetteville Shale.
Index to Financial Statements Depreciation, depletion and amortization for the fiscal years ended June 30, 2005 and 2004 were approximately $2.8 million and $7.0 million, respectively. Depreciation, depletion and amortization for these periods was attributable primarily to depletion and amortization related to production onshore in south Texas. The decrease in 2004 was primarily due to lower levels of production and a lower unit depreciation, depletion and amortization rate and the sale of our south Texas properties to Edge Petroleum in December 2004. Of the $2.8 million of depreciation, depletion and amortization for the year ended June 30, 2005, and the $7.0 million of depreciation, depletion and amortization for the year ended June 30, 2004, $0.4 million and $0.04 million, respectively, relates to continuing operations from our offshore and onshore activities.
Impairment of Natural Gas and Oil Properties. We reported an impairment of natural gas and oil properties of approximately $0.7 million for the year ended June 30, 2006. These related to impairment of offshore properties held by REX and COE. When Contango acquired an additional interest in REX and COE, the purchase price was allocated to several prospects. Specifically, $0.3 million related to our Main Pass 221 prospect and $0.3 million related to our West Delta 43 prospect were impaired because they were both determined to be dry holes during the period; and $0.1 million relating to our East Cameron 107 prospect was impaired as a result of the expiration of its lease. The entire $0.7 million of impairment charges for the year ended June 30, 2006 relates to continuing operations from our offshore activities.
We reported an impairment of natural gas and oil properties of approximately $0.2 million for the year ended June 30, 2005. This was attributable in part to a $0.1 million write-down of costs associated with offshore lease properties owned by our partially owned subsidiary MOE, of which Contango owns 50%. The remaining $0.1 million was attributable to a write-down of costs associated with a small Barnett Shale exploratory play undertaken during the summer of 2003 that had only marginal success. The entire $0.2 million of impairment charges for the year ended June 30, 2005 relates to continuing operations from our offshore activities.
Impairment expense for the year ended June 30, 2004 was approximately $43,000 which related to impairment of properties held by REX and MOE, and relates to continuing operations.
General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2006 were approximately $4.8 million, up from $3.6 million for the year ended June 30, 2005. Major components of general and administrative expenses for the year ended June 30, 2006 included approximately $1.8 million in salaries, benefits and bonuses, $0.9 million in office administration and other expenses, $0.3 million in insurance costs, $0.5 million in accounting and tax services, $0.4 million in legal and other administrative expenses, and $0.9 million in non-cash expenses related to the cost of expensing stock options. The entire $4.8 million of general and administrative expenses for the year ended June 30, 2006 relates to continuing operations from our offshore activities and the Arkansas Fayetteville Shale.
General and administrative expenses for the year ended June 30, 2005 were approximately $3.6 million, up from $2.7 million for the year ended June 30, 2004. Major components of general and administrative expenses for the year ended June 30, 2005 included approximately $1.3 million in salaries, benefits and bonuses, $1.2 million in office administration and other expenses, $0.3 million in insurance costs, $0.4 million in legal and other professional fees and other administrative expenses, and $0.4 million in non-cash expenses related to the cost of expensing stock options. The entire general and administrative expenses for the years ended June 30, 2005 and June 30, 2004 relate to continuing operations.
Interest Expense. Interest expense for the fiscal years ended June 30, 2006, 2005 and 2004 were approximately $0.1 million, $0.1 million, and $0.4 million, respectively. The higher level of interest for fiscal year 2004 was attributable to a higher level of bank debt outstanding during such period. The lower levels of interest in fiscal years 2005 and 2006 were attributable to the Company retiring all of its long term debt in the second quarter of fiscal year 2005. Interest of $149,365 was capitalized for unevaluated property for the fiscal year ended June 30, 2006.
Gain on Sale of Assets and Other. We reported a gain on sale of assets and other of approximately $7.5 million for the year ended June 30, 2006, which represents a $7.2 million gain on the sale of our producing south Texas and Alabama properties and $0.3 million in other income recognized by our partially-owned subsidiary, COE. Of this $7.5 million gain, $0.2 million relates to continuing operations.
We reported other income of approximately $17.0 million for the year ended June 30, 2005, which represented a $16.3 million gain on the sale of our south Texas natural gas and oil interests, a $0.75 million unrealized gain recorded as a result of a mark-to-market increase in the value of our alternative energy investments, offset by approximately $0.1 million in operating losses related to our alternative energy investments. Of this $17.0 million gain, $0.7 million relates to continuing operations.
Index to Financial Statements For the year ended June 30, 2004, we reported an approximate $7.2 million gain on the sale of assets. In September 2003, we sold properties within our south Texas exploration program consisting of 10 wells in Brooks County, Texas for $5.0 million, reporting a gain of approximately $1.0 million attributable to this producing property sale. In December 2003, Contango and its 42.7%-owned subsidiary, REX, sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million as of June 30, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Because the interests sold were unearned back-in working interests, Contango had no proved reserves attributable to the properties sold. Of this $7.2 million gain, $6.2 million relates to continuing operations.
Capital Resources and Liquidity
Cash Inflow. During the year ended June 30, 2006, we had $49.9 million of cash inflow consisting of: internally generated after-tax net cash flow from operations of $9.5 million; net cash flow from financing activities of $20.5 million, which included borrowing $10.0 million of long-term debt, $9.6 million from the issuance of our Series D convertible preferred equity securities, net of issuance costs, and $1.9 million from the exercise of stock options and warrants, offset by $1.0 million paid in preferred stock dividends and debt issuance costs; $12.9 million in proceeds from the sale of proved reserves and $7.0 million from the sale of short term investments.
Cash Outflow. During the year ended June 30, 2006, we invested a total of $45.8 million consisting of: $34.9 million in exploration and development activities ($24.7 million offshore and $10.2 million onshore). We drilled a total of three offshore wells, one of which was successful (drilling and completion costs of $8.6 million), and two of which were dry holes (drilling costs of $5.9 million). We also invested $1.0 million in the acquisition of additional offshore interests, $7.5 million to purchase additional ownership interests in REX and COE, $0.2 million in our 10% owned Freeport LNG project and $2.2 million in alternative energy companies.
Capital Budget. For fiscal year 2007, our capital expenditure budget calls for us to invest a total of $58.3 million, as we anticipate significantly increasing our capital commitment for developing our Arkansas Fayetteville Shale play, drilling our Eugene Island 10 (“Dutch”) exploration well, and bringing our Grand Isle 72 (“Liberty”) discovery to production.
Of the $58.3 million fiscal year 2007 capital expenditure budget, $13.0 million is anticipated to be invested in offshore activities. Our budget calls for us to invest approximately $2.2 million for production and pipeline facilities for developing Grand Isle 72, approximately $3.7 million for our share of the dry hole drilling costs for Eugene Island 10, our “Dutch” prospect, approximately $3.6 million for our share of the drilling and casing costs for Grand Isle 70, our “Red Queen” discovery and $3.5 million in projected future exploration costs, seismic and delay rentals. We have not yet identified the offshore prospects we intend to drill during the remainder of fiscal year 2007, but in the event we have exploration success at our Dutch prospect, our capital budget will be significantly increased as we will incur additional costs to complete the well and pay for production facilities in addition to follow-on development wells. In addition, depending on how we choose to develop our Grand Isle 70 discovery, our capital budget could be further increased.
Of the $58.3 million fiscal year 2007 capital expenditure budget, $45.3 million is expected to be invested in onshore activities. In the Arkansas Fayetteville Shale, our partners and we have acquired or received commitments on approximately 44,000 net mineral acres and we have received AFEs and committed to a total of 69 wells in this play as of August 31, 2006. Of these 69 wells, 15 are operated by Alta and 54 are operated by a third party independent oil and gas exploration company (“Integrated Wells”). We have an average working interest of 15.19%, and a net revenue interest of 12.04% in these 69 wells.
Of the 15 Alta wells, one well was drilled during fiscal year 2006. We are budgeting to receive an additional six AFEs from Alta for wells to be drilled during fiscal year 2007, and therefore expect to drill 20 Alta wells during fiscal year 2007 at a cost of $23.3 million. This includes drilling, frac, completion and hookup costs for the wells. Additionally, we expect to invest $3.2 million in infrastructure, seismic and additional leasehold costs for the Arkansas Fayetteville Shale. We estimate we will have an average working interest of 43%, and a net revenue interest of 34% in these 21 Alta wells.
Of the 54 Integrated Wells for which we have received an AFE, 16 wells are producing, 19 wells have already been spud, and 19 wells have yet to be drilled. In addition to these 54 Integrated Wells, we are budgeting to receive 57 additional AFEs for Integrated Wells during the remainder of fiscal year 2007 for a total of 111 Integrated Wells. We anticipate having between 40 to 50 producing Integrated Wells by December 2006. Our capital budget for Integrated Wells assumes we will invest $16.6 million in Integrated Wells during fiscal year 2007, assuming we drill the 76 wells currently budgeted. We estimate we will have an average working interest of 7.0%, and a net revenue interest of 6.0% in these 111 Integrated Wells.
Index to Financial Statements Our capital budget also calls for us to invest $2.2 million with Alta in other onshore prospects in Texas, Louisiana, and Alabama.
Freeport LNG closed a $383.0 million private placement note issuance in December 2005, and we believe the LNG project will continue through Phase I construction and Phase II pre-development expansion with no further significant funds being required from Contango.
As of August 31, 2006, we have approximately $12.5 million in cash, cash equivalents, and short term investments. We have $10.0 million in long-term debt outstanding and $10.0 million of unutilized borrowing capacity available. The Company has estimated production during August 2006 of approximately 1.4 MMcfe/d.
We will need additional financing to fund our offshore exploration and Arkansas Fayetteville Shale development programs. We intend to access our additional funding needs by first seeking a hydrocarbon borrowing base bank loan. Depending on the terms, conditions and amount of traditional bank financing made available to us, we may be further required to pursue mezzanine debt, equity financing, the sale of assets or seek other financing to fund our opportunities. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.
Income Taxes. During the year ended June 30, 2006, we paid $1.0 million in estimated income taxes, in large part related to the $50.0 million sale of our onshore producing south Texas wells to Edge Petroleum Corporation.
Off Balance Sheet Arrangements
None.
Contractual Obligations
The following table summarizes our known contractual obligations as of June 30, 2006:
We intend to borrow the remaining $10.0 million under our loan agreement with The Royal Bank of Scotland (“RBS”) at anytime prior to October 27, 2006. This additional borrowing will be due in April 2009.
Long-Term Debt
On April 27, 2006, the Company completed the arrangement of a new three-year $20.0 million secured term loan agreement with RBS. The term loan agreement is secured with the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG Development, LP, which owns the Freeport LNG facility. The Company has borrowed the first $10.0 million under the term loan agreement and intends to borrow the remaining $10.0 million at anytime prior to October 27, 2006. Borrowings under the term loan agreement bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The average interest rate charged as of June 30, 2006 was 11.69%. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty. The term loan agreement required an arrangement fee of 2%, or $400,000, which was paid upon closing.
The term loan agreement requires a minimum level of working capital, as defined in the term loan agreement. Additionally, the term loan agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with the term loan agreement’s covenants could result in a default and acceleration of all indebtedness under the term loan agreement. As of June 30, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of the term loan agreement.
Index to Financial Statements The Company also maintains a $0.1 million credit facility with Guaranty Bank, FSB that matures on June 29, 2008. As of June 30, 2006 and June 30, 2005, the Company had no long term debt outstanding under the Guaranty Bank facility.
Any future borrowings under the Guaranty Bank facility will bear interest, at the Company’s option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, the Company pays a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability.
The hydrocarbon borrowing base under the Guaranty Bank facility is subject to semi-annual redetermination based primarily on the value of our proved reserves. The credit facility requires the maintenance of certain ratios, including those related to working capital, funded debt to EBITDAX, and debt service coverage, as defined in the credit agreements. Additionally, the credit agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility and the inability to borrow under the facility. As of June 30, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of its credit facility.
Critical Accounting Policies
The application of generally accepted accounting principles involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company. Contango’s critical accounting principles, which are described below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles and stock based compensation, cash and cash equivalents, and short-term investments.
Reclassifications. Certain reclassifications have been made to the 2005 and 2004 financial statements to conform to the 2006 presentation. These reclassifications have no impact on previously reported net income or cash flows.
Use of Estimates. The preparation of 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 financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows therefrom (see “Supplemental Oil and Gas Disclosures”) and the mark to market valuation of the Fund (see Note 9 - Contango Venture Capital Corporation of the Notes to Consolidated Financial Statements).
Revenue Recognition. Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At June 30, 2006 and 2005, the Company had no over or under-produced imbalances.
Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of June 30, 2006, the Company had $10,274,950 in cash and cash equivalents, of which $6,416,527 was invested in highly liquid AAA-rated tax-exempt money market funds. As of June 30, 2005, the Company had cash and cash equivalents of $3,985,775.
Short Term Investments. As of June 30, 2006, the Company had $18,472,327 invested in a portfolio of
Index to Financial Statements periodic auction reset (“PAR”) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk. As of June 30, 2005, the Company had $25,499,869 invested in PAR securities.
Net Income (Loss) per Common Share. Basic and diluted net income (loss) per common share have been computed in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 128, “Earnings per Share”. Basic net income (loss) per common share is computed by dividing income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. (See Note 4 - Net Income (Loss) Per Common Share to the Notes to the Consolidated Financial Statements for the calculations of basic and diluted net income (loss) per common share).
Income Taxes. The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
Concentration of Credit Risk. Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and, as such, are not disclosed in the Consolidated Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity, including shares issued as compensation and issuance of stock options.
Fair Value of Financial Instruments. The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, short-term investments, trade accounts receivable and trade accounts payable, approximate their fair values based on the short maturities of those instruments. The Company’s long-term debt was variable rate debt and, as such, approximated fair value, as interest rates are variable based on prevailing market rates.
Successful Efforts Method of Accounting for Oil and Gas Operations. The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full-cost method. There are several significant differences between these methods. Under the successful efforts method, costs such as geological and geophysical, exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to their respective full-cost pool. In the measurement of impairment of oil and gas properties, the successful efforts method of accounting follows the guidance provided in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS 144”), where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect on the last day of the reporting period (ceiling limitation). If the full-cost pool is in excess of the ceiling limitation, the excess amount is charged through income.
We have elected to use the successful efforts method to account for our investment in oil and gas properties. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, and any such impairment is charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. Depreciation, depletion and amortization is on a cost center by cost center basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. Our financial position and results of operations would have been significantly different had we used the full-cost method of accounting for our oil and gas investments. Generally, the application of the successful efforts method of accounting for oil and gas property results in lower capitalized costs and higher expenses compared to similar companies applying the full-cost method of accounting.
Index to Financial Statements On July 1, 2003, the Company changed its accounting policy for amortizing and impairing the Company’s natural gas and oil properties from a well-by-well cost center basis to a field-by-field cost center basis. Management believes this policy is preferable in providing greater comparability with other successful efforts natural gas and oil companies by conforming to predominant industry practice. In addition, the field level is consistent with the Company’s operational and strategic assessment of its natural gas and oil investments. The Company determined that the cumulative effect of the change in accordance with APB Opinion No. 20 was immaterial to the consolidated financial statements.
In accordance with SFAS 144, the Company classified its $11.6 million property sale effective April 1, 2006, its property sale to an independent oil and gas company for $2.0 million, effective February 1, 2006, and its property sale to Edge Petroleum Corporation (“Edge Petroleum”) for $50.0 million, effective July 1, 2004, as discontinued operations. An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore exploration programs. Thus, it is our intent to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.
Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 42.7% owned REX, 50% owned MOE, and 76.0% owned COE, each as of June 30, 2006, are not controlled by the Company and are proportionately consolidated. By agreement, REX, MOE and COE have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.
By agreement, since the Company was the only owner that contributed cash to REX, MOE, and COE upon formation of these three ventures, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in COE immediately share in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The other owners of REX, MOE and COE who participated in the initial formation of these entities, contributed seismic data and related geological and geophysical services to the ventures in exchange for ownership interests.
On September 2, 2005, the Company purchased an additional 9.4% ownership interest in each of REX and COE. Both interests were purchased from an existing owner, which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. On September 2, 2005, an independent third party also purchased a 9.4% interest in each of REX and COE and the selling owner’s ownership interest thus decreased from 33.3% to 14.6% in each such entity.
Contango’s 10% limited partnership interest in Freeport LNG is accounted for at cost. As a 10% limited partner, the Company has no ability to direct or control the operations or management of the general partner.
Contango’s 32% ownership in CCPM and Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. (“CCPLP”) are accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet. CCPLP formed the Fund in January 2005. The Fund owns equity interests in a portfolio of alternative energy companies. The Fund marks these equity interests to market according to fair market values on a quarterly basis.
Contango’s investments in Trulite, Moblize and Gridpoint are accounted for using the cost method. Under the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment.
Index to Financial Statements Recent Accounting Pronouncements. In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and assessing the impact, if any, it may have on our financial position and results of operations.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”, (“SFAS 154”), which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3”, “Reporting Accounting Changes in Interim Financial Statements-An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005, and was adopted by the Company in the first quarter of 2006.
Stock-Based Compensation. Effective July 1, 2001, the Company adopted the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation”. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes options-pricing model. Effective July 1, 2005, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”). Prior to the adoption of SFAS 123(R), the Company presented all benefits from the exercise of share-based compensation as operating cash flows in the statement of cash flows. SFAS 123(R) requires the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) to be classified as financing cash flows. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2006, 2005 and 2004, respectively: (i) risk-free interest rate of 5.1 percent, 3.68 percent and 3.88 percent, respectively; (ii) expected lives of five years; (iii) expected volatility of 40 percent, 40 percent and 26 percent, respectively; and (iv) expected dividend yield of zero percent.
During the years ended June 30, 2006, 2005 and 2004, the Company recorded a charge of $856,412, $385,193 and $339,005 in stock option expenses to general and administrative expense, respectively.
Derivative Instruments and Hedging Activities. The Company did not enter into any derivative instruments or hedging activities for the fiscal year ended June 30, 2006 or June 30, 2005, nor did we have any open commodity derivative contracts at June 30, 2006.
Contango previously has entered into commodity derivatives contracts and fixed-price physical contracts with investment grade companies to manage its exposure to natural gas and oil price volatility. These took the form of futures contracts, swaps and options. For the year ended June 30, 2004, the Company recognized a gain from hedging activities of $58,171. Although the Company’s hedging transactions were designed as economic hedges for a portion of future natural gas and oil production, the Company elected not to designate the derivative instruments as “hedges” under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. As a result, changes in these derivative instruments’ mark-to-market fair values were recognized in the Company’s earnings.
Asset Retirement Obligation. The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, (“SFAS 143”), as of July 1, 2002. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is
Index to Financial Statements accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Due to the Company’s focus on offshore properties during the year, the ARO has significantly increased. Activities related to the Company’s ARO during the year ended June 30, 2006 and 2005 are as follows:
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the year ended June 30, 2006, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $0.6 million impact on our revenues.
Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. As of August 31, 2006, we had $10.0 million of variable rate long-term debt outstanding due in April 2009. This variable rate obligation exposes us to the risk of increased interest expense in the event of increases in short-term interest rates. The impact on annual cash flow of a 10% change in the floating rate applicable to our variable rate debt would be less than $0.1 million.
Item 8.
Item 8. Financial Statements and Supplementary Data
The financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented on pages through of this Form 10-K.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer and the Controller, of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Security Exchange Act of 1934 (the “Exchange Act”)) as of June 30, 2006, the end of the period covered by this report. Based on that evaluation, the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer and Controller, concluded that the Company’s disclosure controls and procedures were effective as of such date to ensure that information required to be disclosed in the reports that the Company files under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and (ii) would be accumulated and communicated to the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer and Controller, as appropriate, to allow timely decisions regarding required disclosures.
Index to Financial Statements 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, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer and the Controller, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation under the framework in Internal Control-Integrated Framework, the Company’s management concluded that its internal control over financial reporting was effective as of June 30, 2006.
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has audited our management’s assessment of the effectiveness of our internal control over financial reporting as of June 30, 2006, as stated in their report which is included herein.
Report of Independent Registered Public Accounting Firm Over Internal Controls
Board of Directors and
Shareholders of Contango Oil & Gas Company
We have audited management’s assessment, included in the accompanying management’s report on internal control over financial reporting that Contango Oil & Gas Company (a Delaware Corporation) and subsidiaries maintained effective internal control over financial reporting as of June 30, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Contango Oil & Gas Company’s management is responsible 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 management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit provides 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 generally accepted accounting principles. 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.
Index to Financial Statements In our opinion, management’s assessment that Contango Oil & Gas Company and subsidiaries maintained effective internal control over financial reporting as of June 30, 2006, 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 (COSO). Also in our opinion, Contango Oil & Gas Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of June 30, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Contango Oil & Gas Company and subsidiaries as of June 30, 2006 and 2005, and the related statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended June 30, 2006 and our report dated September 8, 2006 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
September 8, 2006
Changes in Internal Control Over Financial Reporting
There was no change in our internal controls over financial reporting during the period covered by this annual report on Form 10-K that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be contained in our Definitive Proxy Statement for our 2006 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Election of Directors”, “Executive Compensation” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The Proxy Statement will be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Exchange Act of 1934, as amended, not later than 120 days after June 30, 2006.
Item 11.
Item 11. Executive Compensation
The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.
Index to Financial Statements
Item 13.
Item 13. Certain Relationships and Related Transactions
The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the heading “Certain Relationships and Related Transactions” and “Executive Compensation” and is incorporated herein by reference.
Item 14.
Item 14. Principal Accountant Fees ands Services
The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the heading “Principal Accountant Fees ands Services” and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Financial Statements and Schedules:
The financial statements are set forth in pages to of this Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.
(b) Exhibits:
The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, which were previously filed, are incorporated herein by reference.
Index to Financial Statements
Index to Financial Statements
 Filed herewith.
* Indicates a management contract or compensatory plan or arrangement.
1. Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.
2. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on November 11, 1999.
3. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on February 14, 2000.
4. Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and Exchange Commission of September 8, 2000.
5. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed with the Securities and Exchange Commission on September 27, 2000.
6. Filed as an exhibit to the Company’s report on Form 8-K, dated September 27, 2000, as filed with the Securities and Exchange Commission on October 3, 2000.
7. Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.
8. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2001, as filed with the Securities and Exchange Commission on September 21, 2001.
9. Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and Exchange Commission on January 8, 2002.
10. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, as filed with the Securities and Exchange Commission on February 14, 2002.
11. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, dated May 2, 2002, as filed with the Securities and Exchange Commission.
12. Filed as an exhibit to the Company’s report on Form 10-QSB/A for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on June 4, 2002.
13. Filed as an exhibit to the Company’s Registration Statement on Form S-1 (Registration No. 333-89900) as filed with the Securities and Exchange Commission on June 14, 2002.
14. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2002, as filed with the Securities and Exchange Commission on September 26, 2002.
15. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.
16. Filed as an exhibit to the Company’s report on Form 8-K, dated June 17, 2003, as filed with the Securities and Exchange Commission on June 18, 2003.
17. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as filed with the Securities and Exchange Commission on September 22, 2003.
18. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2003, dated November 12, 2003, as filed with the Securities and Exchange Commission.
19. Filed as an exhibit to the Company’s report on Form 8-K, dated December 12, 2003, as filed with the Securities and Exchange Commission on December 17, 2003.
20. Filed as an exhibit to the Company’s report on Form 8-K, dated December 19, 2003, as filed with the Securities and Exchange Commission on December 23, 2003.
21. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended December 31, 2003, dated February 13, 2004, as filed with the Securities and Exchange Commission.
22. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2004, dated May 12, 2004, as filed with the Securities and Exchange Commission.
Index to Financial Statements
23. Filed as an exhibit to the Company’s annual report on Form 10-K for the fiscal year ended June 30, 2004, as filed with the Securities and Exchange Commission on September 27, 2004.
24. Filed as an exhibit to the Company’s report on Form 8-K, dated September 27, 2004, as filed with the Securities and Exchange Commission on October 8, 2004.
25. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2004, dated November 12, 2004, as filed with the Securities and Exchange Commission.
26. Filed as an exhibit to the Company’s Registration Statement filed on Form S-3 as filed with the Securities and Exchange Commission on August 2, 2005.
27. Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005.
28. Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2005, as filed with the Securities and Exchange Commission on September 13, 2005.
29. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission.
30. Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTANGO OIL & GAS COMPANY
/s/ KENNETH R. PEAK
/s/ LESIA BAUTINA
Kenneth R. Peak
Lesia Bautina
Chairman, Chief Executive Officer and Chief
Financial Officer (principal executive officer
and principal financial officer)
Senior Vice President and Controller
(principal accounting officer)
Index to Financial Statements In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation) and subsidiaries as of June 30, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended June 30, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Contango Oil & Gas Company and subsidiaries as of June 30, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2006 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Contango Oil & Gas Company and subsidiaries’ internal control over financial reporting as of June 30, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 8, 2006 expressed an unqualified opinion on management’s assertion of the effectiveness of internal control over financial reporting and an unqualified opinion on the effectiveness of internal control over financial reporting.
GRANT THORNTON LLP
Houston, Texas
September 8, 2006
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Business
Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), a wholly-owned subsidiary, acts as operator on certain offshore prospects. The Company also owns a 10% interest in a limited partnership formed to develop a liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas, and holds investments in companies focused on commercializing environmentally preferred energy technologies.
2. Summary of Significant Accounting Policies
The application of generally accepted accounting principles involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company. Contango’s critical accounting principles, which are described below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles and stock based compensation, cash and cash equivalents, and short-term investments.
Reclassifications. Certain reclassifications have been made to the 2005 and 2004 financial statements to conform to the 2006 presentation. These reclassifications related to discontinued operations and have no impact on previously reported net income or cash flows.
Use of Estimates. The preparation of 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 financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows therefrom (see “Supplemental Oil and Gas Disclosures”) and the mark to market valuation of the Fund (see Note 9 - Contango Venture Capital Corporation).
Revenue Recognition. Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At June 30, 2006 and 2005, the Company had no overproduced imbalances.
Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of June 30, 2006, the Company had $10,274,950 in cash and cash equivalents, of which $6,416,527 was invested in highly liquid AAA-rated tax-exempt money market funds. Cash equivalents are considered to be all highly liquid debt investments having an original maturity of three months or less. As of June 30, 2005, the Company had cash and cash equivalents of $3,985,775.
Short Term Investments. As of June 30, 2006, the Company had $18,472,327 invested in a portfolio of periodic auction reset (“PAR”) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk.
Accounts Receivable. The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which the Company serves as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Crude oil and natural gas sales are generally unsecured.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged-off are added to the allowance.
Accounts receivable allowance for bad debt was $0 at June 30, 2006 and 2005. At June 30, 2006 and 2005, the carrying value of the Company’s accounts receivable approximates fair value.
Impairment of Long-Lived Assets. The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), which requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the asset’s carrying amount. In the evaluation of the fair value and future benefits of long-lived assets, the Company performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets. If the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to its fair value.
Net Income (Loss) per Common Share. Basic and diluted net income (loss) per common share have been computed in accordance with SFAS No. 128, “Earnings per Share”. Basic net income (loss) per common share is computed by dividing income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. See Note 4 - Net Income (Loss) Per Common Share for the calculations of basic and diluted net income (loss) per common share.
Income Taxes. The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
Concentration of Credit Risk. Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur that do not directly affect cash balances and, as such, are not disclosed in the Consolidated Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity, including shares issued as compensation and issuance of stock options.
Fair Value of Financial Instruments. The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, short-term investments, trade accounts receivable and trade accounts payable, approximate their fair values based on the short maturities of those instruments. The Company’s long-term debt was variable rate debt and, as such, approximated fair value, as interest rates are variable based on prevailing market rates.
Successful Efforts Method of Accounting. The Company follows the successful efforts method of
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, and any such impairment is charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. Depreciation, depletion and amortization is on a cost center by cost center basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value.
On July 1, 2003, the Company changed its accounting policy for amortizing and impairing the Company’s natural gas and oil properties from a well-by-well cost center basis to a field-by-field cost center basis. Management believes this policy is preferable in providing greater comparability with other successful efforts natural gas and oil companies by conforming to predominant industry practice. In addition, the field level is consistent with the Company’s operational and strategic assessment of its natural gas and oil investments. The Company determined that the cumulative effect of the change in accordance with APB Opinion No. 20 was immaterial to the consolidated financial statements.
In accordance with SFAS 144, the Company classified its $11.6 million property sale effective April 1, 2006, its property sale to an independent oil and gas company for $2.0 million, effective February 1, 2006, and its property sale to Edge Petroleum Corporation (“Edge Petroleum”) for $50.0 million, effective July 1, 2004, as discontinued operations. An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore exploration programs. Thus, it is our intent to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.
Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 42.7% owned Republic Exploration LLC (“REX”), 50% owned Magnolia Offshore Exploration LLC (“MOE”), and 76.0% owned Contango Offshore Exploration LLC (“COE”), each as of June 30, 2006, are not controlled by the Company and are proportionately consolidated. By agreement, REX, MOE and COE have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.
By agreement, since the Company was the only owner that contributed cash to REX, MOE, and COE upon formation of these three ventures, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in COE immediately share in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The other owners of REX, MOE and COE who participated in the initial formation of these entities, contributed seismic data and related geological and geophysical services to the ventures in exchange for ownership interests.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On September 2, 2005, the Company purchased an additional 9.4% ownership interest in each of REX and COE. Both interests were purchased from an existing owner, which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. On September 2, 2005, an independent third party also purchased a 9.4% interest in each of REX and COE.
Contango’s 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”) is accounted for at cost. As a 10% limited partner, the Company has no ability to direct or control the operations or management of the general partner.
Contango’s 32% ownership in Contango Capital Partnership Management, LLC (“CCPM”) and Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. (“CCPLP”) are accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet. CCPLP formed the Contango Capital Partners Fund, LP (the “Fund”) in January 2005. The Fund owns equity interests in a portfolio of alternative energy companies. The Fund marks these equity interests to market according to fair market values on a quarterly basis.
Contango’s investments in Trulite, Inc. (“Trulite”), Moblize, Inc. (“Moblize”) and Gridpoint, Inc. (“Gridpoint”) are accounted for using the cost method. Under the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment.
Recent Accounting Pronouncements. In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and assessing the impact, if any, it may have on our financial position and results of operations.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”), which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements-An Amendment of APB Opinion No. 28”. SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005, and was adopted by the Company in the first quarter of 2006.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Stock-Based Compensation. Effective July 1, 2001, the Company adopted the fair value based method prescribed in SFAS No. 123, “Accounting for Stock Based Compensation” (“SFAS 123”). Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes options-pricing model. Effective July 1, 2005, the Company adopted SFAS No. 123 (revised 2004) (“SFAS 123(R)”), “Share-Based Payment”. Prior to the adoption of SFAS 123(R), the Company presented all benefits from the exercise of share-based compensation as operating cash flows in the statement of cash flows. SFAS 123(R) requires the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) to be classified as financing cash flows. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2006, 2005 and 2004, respectively: (i) risk-free interest rate of 5.1 percent, 3.68 percent and 3.88 percent, respectively; (ii) expected lives of five years; (iii) expected volatility of 40 percent, 40 percent and 26 percent, respectively; and (iv) expected dividend yield of zero percent.
During the years ended June 30, 2006, 2005 and 2004, the Company recorded a charge of $856,412, $385,193 and $339,005 in stock option expenses to general and administrative expense, respectively.
Derivative Instruments and Hedging Activities. The Company did not enter into any derivative instruments or hedging activities for the fiscal year ended June 30, 2006 or June 30, 2005, nor did we have any open commodity derivative contracts at June 30, 2006.
Contango previously has entered into commodity derivatives contracts and fixed-price physical contracts with investment grade companies to manage its exposure to natural gas and oil price volatility. These took the form of futures contracts, swaps and options. For the year ended June 30, 2004, the Company recognized a gain from hedging activities of $58,171. Although the Company’s hedging transactions were designed as economic hedges for a portion of future natural gas and oil production, the Company elected not to designate the derivative instruments as “hedges” under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”. As a result, changes in these derivative instruments’ mark-to-market fair values were recognized in the Company’s earnings.
Marketable Equity Securities. As part of the formation of Freeport LNG Development, L.P., Cheniere Energy, Inc. (“Cheniere”) granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. All of the Company’s marketable securities related to an investment in Cheniere common stock, were sold in fiscal year 2004 resulting in a gain of $710,322 recognized under “Gain on Sale of Marketable Securities”.
Asset Retirement Obligation. The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, (“SFAS 143”), as of July 1, 2002. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Due to the Company’s focus on offshore properties during the year, the ARO has significantly increased. Activities related to the Company’s ARO during the year ended June 30, 2006 and 2005 are as follows:
Capitalized Exploratory Well Costs. As of June 30, 2006, the Company has capitalized exploratory well costs of $10.4 million that is pending final determination of proved reserves.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
3. Sale of Properties - Discontinued Operations
On March 24, 2006, the Company’s Board of Directors approved the sale of all of the Company’s onshore producing assets in Texas and Alabama for an aggregate purchase price of $11.6 million. These properties were held by Contango STEP, LP (“STEP”), an indirect wholly-owned subsidiary of the Company. On April 28, 2006, the Company completed the sale of substantially all of these natural gas and oil interests for $11.1 million pursuant to a purchase and sale agreement. The sale of the remaining two wells under the same purchase and sale agreement for an aggregate purchase price of approximately $0.5 million was completed in June 2006. The sold properties had net reserves of approximately 203 thousand barrels (“Mbbl”) of oil and 849 million cubic feet (“MMcf”) of gas, or 2.1 billion cubic feet equivalent (“Bcfe”). The Company recognized a pre-tax gain of $6.2 million for the year ended June 30, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.
In March 2006, the Company completed the sale of its interest in a producing well in Zapata County, Texas to an independent oil and gas company for approximately $2.0 million. Approximately 227 MMcf of proven reserves were sold. Pre-tax proceeds after netting adjustments were $2.0 million. The Company recognized a pre-tax gain on sale of $1.0 million for the year ended June 30, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.
In December 2004, the Company sold producing properties consisting of 39 wells in south Texas, a majority of our natural gas and oil interests, to Edge Petroleum Corporation for $50.0 million. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 billion cubic feet per day equivalent (“Bcfe/d”) of proven reserves were sold having a pre-tax net present value when using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million. Adjustments were made for net revenues that Contango received for production occurring after July 1, 2004, the effective date of sale, up to the post-closing date of March 29, 2005. The Company recognized a gain on sale of $16.3 million for the year ended June 30, 2005. Our sale of assets to Edge Petroleum has been classified as discontinued operations in our financial statements for all periods presented.
In September 2003, the Company completed the sale of certain reserves in Brooks County, Texas for $5.0 million and recorded a gain of approximately $1.0 million for the year ended June 30, 2004. Proved reserves were 1.5 Bcfe. The sale of the Brooks County reserves was reclassified as discontinued operations since these reserves were part of our original south Texas natural gas and oil interests.
In accordance with SFAS 144, we classified our property sales as discontinued operations in our financial statements for all periods presented.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The summarized financial results for discontinued operations for each of the periods ended June 30 are as follows:
Operating Results:
* Credits due to severance tax refunds
For the year ended June 30, 2006, operating expenses from discontinued operations resulted in a net credit of $1,520,269. The credit was attributable to credits issued for previously paid severance taxes. The Railroad Commission of Texas allows for a severance tax reduction on tight sand gas wells. As a result, some of our former south Texas formation properties, which were included in the sale of our south Texas natural gas and oil interests to Edge Petroleum, were eligible for severance tax reduction. By contractual agreement, revenues and expenses prior to July 1, 2004, the effective date of the sale, accrue to us.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
4. Net Income (Loss) Per Common Share
A reconciliation of the components of basic and diluted net income (loss) per common share for the fiscal years ended June 30, 2006, 2005 and 2004 is presented below:
(a) Anti-dilutive.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
4. Net Income (Loss) Per Common Share - continued
(a) Anti-dilutive.
5. Acquisition of Interest in Partially-Owned Subsidiaries and Overriding Royalties
On September 2, 2005, we purchased an additional 9.4% ownership interest in each of our two partially-owned offshore Gulf of Mexico exploration subsidiaries, REX for $5.6 million and COE for $1.9 million, for a total expenditure of $7.5 million. Both interests were purchased from Juneau Exploration, L.P. (“JEX”), which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. The purchases were financed from the Company’s existing cash on hand. An independent third party also purchased a 9.4% interest in each of REX and COE from JEX for the same total purchase price of $7.5 million. JEX will continue in its capacity as the managing member of both REX and COE and following these two sales, now owns a 14.6% interest in each of REX and COE.
During the year ended June 30, 2006, the Company allocated the purchase price to the net assets acquired (“purchase price allocation”). These assets include planned drilling commitments, unevaluated exploration blocks, and proven developed producing (“PDP”) properties. A significant portion of the purchase price allocation was allocated to our Eugene Island 10 (“Dutch”) exploration prospect. Should Dutch not be successful, the Company will be required under successful efforts accounting to expense all or a portion of this allocation in addition to the drilling costs. During the year ended June 30, 2006, we wrote off $0.3 million of the purchase price relating to our Main Pass 221 prospect and $0.3 million relating to our West Delta 43 prospect, because they were dry holes; and $0.1 million relating to our East Cameron 107 prospect, as a result of the expiration of its lease.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On November 7, 2005, the Company, in a separate transaction, also acquired certain overriding royalty interests in REX, COE and MOE offshore prospects for the purchase price of $1.0 million.
6. Series D Perpetual Cumulative Convertible Preferred Stock
On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The Series D preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $12.00 per share. Each record holder of Series D preferred stock is entitled to one vote per share for each share of common stock into which each share of Series D preferred stock is convertible. The dividend on the Series D preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. Our registration statement filed with the Securities and Exchange Commission, covering the 833,330 shares of common stock issuable upon conversion of the Series D preferred stock, became effective on October 26, 2005. Net proceeds associated with the private placement of the Series D preferred stock was $9,616,358, net of stock issuance costs.
7. Conversion of Series C Cumulative Convertible Preferred Stock into Common Stock
On July 1, 2004, private institutional investors elected to convert 200 of the 1,600 shares of the Company’s Series C cumulative convertible preferred stock into 166,666 shares of Contango common stock.
On July 19, 2005, we exercised our mandatory conversion rights pursuant to the terms of our Series C preferred stock, and converted all of the remaining 1,400 shares of our Series C preferred stock issued and outstanding into 1,166,662 shares of common stock. The outstanding shares of the Series C preferred stock had a face value of $7.0 million, and paid a 6.0% per annum quarterly cash dividend.
Holders of the Company’s common stock are entitled to one vote per share on all matters to be voted on by shareholders and are entitled to receive dividends, if any, as may be declared from time to time by the Board of Directors of the Company. Holders of common stock and holders of Series D preferred stock vote as one class for the election of directors and most other matters. Upon any liquidation or dissolution of the Company, the holders of common stock are entitled to receive a pro rata share of all of the assets remaining available for distribution to shareholders after settlement of all liabilities and liquidating preferences of preferred stockholders.
8. Investment in Freeport LNG
As of June 30, 2006, the Company has invested $3.2 million and owns a 10% limited partnership interest in Freeport LNG, a limited partnership formed to develop a 1.5 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas.
In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the financing, construction and use of the LNG receiving terminal in Freeport, Texas. ConocoPhillips executed a terminal use agreement for 1.0 Bcf/d of regasification capacity, purchased a 50% interest in the general partner managing the Freeport LNG project and agreed to provide construction funding to the venture. This construction funding will be non-recourse to Contango. The Dow Chemical Company has also executed a terminal use agreement for regasification capacity of 500 million cubic feet per day (“MMcf/d”) and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Freeport LNG is responsible for the commercial activities of the partnership, while ConocoPhillips, under a construction advisory and management agreement, is managing the construction of the facility.
In January 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the Federal Energy Regulatory Commission (the “FERC”) and construction of the 1.5 Bcf/day facility commenced on January 17, 2005. The engineering, procurement and construction contractor is a consortium of Technip USA, Zachry Construction of San Antonio, and Saipem SpA of Italy.
Index to Financial Statements 9. Contango Venture Capital Corporation
As of June 30, 2006, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in the three alternative energy portfolio companies described below. Our investment in these companies is less than 20% and we account for these investments under the cost method.
Trulite, Inc. As of June 30, 2006, CVCC had invested $0.9 million in Trulite, Inc. (“Trulite”) in exchange for 2,001,014 shares of Trulite common stock, which represents an approximate 17% ownership interest. Trulite develops lightweight hydrogen generators for fuel cell systems.
Moblize Inc. As of June 30, 2006, CVCC had invested $0.6 million in Moblize Inc. (“Moblize”) in exchange for 324,324 shares of Moblize convertible preferred stock, which represents an approximate 19 % ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas industry using open-standards based technologies. Moblize is deploying its technology in oil fields near Houston belonging to Chevron U.S.A. Inc.
Gridpoint, Inc. In May 2006, CVCC invested $1.0 million in Gridpoint, Inc. (“Gridpoint”) in exchange for 333,333 shares of Gridpoint preferred stock, which represents an approximate 3% ownership interest. Gridpoint’s intelligent energy management (IEM) products ensure clean, reliable power, increase energy efficiency, and integrate renewable energy. With GridPoint, home and business owners can automatically protect themselves from power outages, manage their energy online and reduce their carbon footprint. GridPoint’s “plug-and-play” appliances are easy to install and are sold through a network of premium home builders, utilities, retail chains and government entities as well as installers and contractors of electrical, heating, air-conditioning, home automation, power quality and renewable energy systems.
In June 2004, CVCC acquired a 32% membership interest in Contango Capital Partnership Management, LLC (“CCPM”) for $0.5 million. CCPM was formed by us and other investors to invest in the energy venture capital market. CVCC is the 25% limited partner of, and CCPM is the general partner of, Contango Capital Partners, L.P., which was formed in January 2005 for the purpose of investing in the energy venture capital market. Contango Capital Partners, L.P. then formed Contango Capital Partners Fund, L.P. (the “Fund”).
On January 31, 2005, the Fund was closed to new investments with a total capitalization of $8.2 million in the form of contributed stock, cash, and future cash commitments. Prior to CVCC holding a direct interest in Trulite and Moblize, the Fund previously held these investments. The Fund also had an investment in Synexus Energy, Inc. (“Synexus”). Synexus is a portable and stationary fuel cell integrator developing technology with a lightweight fuel cell stack that will create both portable and stationary power solutions for customers.
During the year ended June 30, 2006, the Fund invested an additional $0.8 million in Trulite, $0.6 million in Moblize, and an additional $1.0 million in Synexus. In April 2006, Trulite acquired Synexus’ technology. In May 2006, the Fund distributed its pro rata shares of Trulite to CVCC. In June 2006, the Fund sold its investment in Moblize to CVCC for $0.6 million.
As of June 30, 2006, CVCC owns 25% of the Fund. The Fund currently holds a direct investment in the two alternative energy companies described below. We account for these investments under the equity method. CCPM is the general partner of the Fund.
Protonex Technology Corporation. To date, the Fund has invested $1.5 million in Protonex Technology Corporation (“Protonex”) in exchange for 2,400,000 shares of Protonex stock, which represents an approximate 7% ownership interest. Protonex provides long-duration portable and remote power sources with a focus on providing solutions to the U.S. military and supplies complete power solutions and application engineering services to original equipment manufacturers customers. During the period, Protonex began trading its common shares on the AIM market of the London Stock Exchange under the stock symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At June 30, 2006, the Fund’s investment in Protonex had a mark-to-market value of approximately $3.8 million.
Jadoo Power Systems. The Fund has invested approximately $1.2 million and owns 2,200,000 shares of Jadoo Power Systems (“Jadoo”) stock, which represents an approximate 5% ownership interest. Jadoo develops high energy density power products for the law enforcement, military and electronic news gathering applications. As of June 30, 2006, the Fund’s investment in Jadoo had a valuation of approximately $1.2 million.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Since the Fund’s inception, the Company has recorded a cumulative $0.8 million increase to our investment resulting primarily from unrealized gains of the Fund as a result of mark-to-market adjustments that have been made due to the increase in the value of our alternative energy investments, bringing our total investment in alternative energy investments, including cumulative mark-to-market adjustments, as of June 30, 2006, to approximately $4.5 million.
10. Income Taxes
Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income (loss) as follows:
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The provision (benefit) for income taxes for the periods indicated are comprised of the following:
The Company’s permanent benefits relate mainly to non-taxable interest on municipal bonds.
The net deferred tax asset (liability) is comprised of the following:
At June 30, 2006, the Company had a net operating loss for federal income tax purposes of $2.8 million, which can be carried back two years and forward twenty years. Realization of net deferred tax assets associated with net operating loss carryovers is dependent upon generating sufficient taxable income prior to its expiration. The Company will fully utilize the net operating loss carryover by applying it to taxable income from the previous two years. The Company has not established a valuation allowance for deferred tax assets, as management currently believes that it is more likely than not that the net operating loss carryover will be fully utilized through taxable income from the past two years.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
11. Long-Term Debt
On April 27, 2006, the Company completed the arrangement of a new three-year $20.0 million secured term loan agreement with The Royal Bank of Scotland (“RBS”). The term loan agreement is secured with the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG, which owns the Freeport LNG facility. The Company has borrowed the first $10.0 million under the term loan agreement and intends to borrow the remaining $10.0 million at anytime prior to October 27, 2006. Borrowings under the term loan agreement bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The average interest rate charged as of June 30, 2006 was 11.69%. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty. The term loan agreement required an arrangement fee of 2%, or $400,000, which was paid upon closing.
The term loan agreement requires a minimum level of working capital, as defined in the term loan agreement. Additionally, the term loan agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with the term loan agreement’s covenants could result in a default and acceleration of all indebtedness under the term loan agreement. As of June 30, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of the term loan agreement.
The Company also maintains a $0.1 million credit facility with Guaranty Bank, FSB that matures on June 29, 2008. As of June 30, 2006 and June 30, 2005, the Company had no long term debt outstanding under the Guaranty Bank facility.
Any future borrowings under the Guaranty Bank facility will bear interest, at the Company’s option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, the Company pays a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability.
The hydrocarbon borrowing base under the Guaranty Bank facility is subject to semi-annual redetermination based primarily on the value of our proved reserves. The credit facility requires the maintenance of certain ratios, including those related to working capital, funded debt to Earnings Before Interest, Taxes, Depreciation, Amortization and Exploration Expenses (“EBITDAX”), and debt service coverage, as defined in the credit agreements. Additionally, the credit agreements contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility and the inability to borrow under the facility. As of June 30, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of its credit facility.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
12. Commitments and Contingencies
Contango leases its office space and certain other equipment. As of June 30, 2006, minimum future lease payments are as follows:
The amount incurred under operating leases during the years ended June 30, 2006, 2005 and 2004 was $139,744, $110,404, and $83,596, respectively.
13. Stock Options
In September 1999, the Company established the Contango Oil & Gas Company 1999 Stock Incentive Plan (the “Option Plan”). Under the Option Plan, the Company may issue up to 2,500,000 shares of common stock with an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant, but in no event less than $2.00 per share. The Company may grant key employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options generally expire after five or ten years. The vesting schedule varies, but vesting generally occurs over a two-year period (1/3 immediately, 1/3 one year from the date of grant and 1/3 two years from the date of grant) or four-year period (1/4 one year from the date of grant and 1/4 two years, three years and four years from the date of grant). As of June 30, 2006, options under the Option Plan to acquire 955,000 shares of common stock at prices between $3.00 and $14.14 per share were outstanding.
In addition to grants made under the Option Plan, the Company has granted other options to purchase common stock outside the Option Plan. These options generally expire after five years. The vesting schedule varies, but vesting generally occurs either (i) immediately, (ii) over a two-year period (1/3 immediately, 1/3 one year from the date of grant and 1/3 two years from the date of grant), or (iii) under a vesting schedule that is tied to the payout and rate of return on specific projects for which the option was granted. As of June 30, 2006, other options to acquire 5,500 shares of common stock at prices between $3.00 and $3.33 per share were outstanding.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
A summary of the status of the option plan and those options granted outside of the option plan as of June 30, 2006, 2005 and 2004, and changes during the fiscal years then ended, is presented in the table below:
(1) The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2006, 2005 and 2004, respectively: (i) risk-free interest rate of 5.1 percent, 3.68 percent and 3.88 percent; (ii) expected lives of five years for the Option Plan and other options; (iii) expected volatility of 40 percent, 40 percent and 26 percent; and (iv) expected dividend yield of zero percent.
The following table summarizes information about options that were outstanding at June 30, 2006:
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Effective July 1, 2001, the Company changed it method of accounting for employee stock-based compensation to the fair value method prescribed in SFAS 123. Effective July 1, 2005, the Company adopted SFAS 123(R). Prior to the adoption of SFAS 123(R), we presented all tax benefits resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123(R) requires that cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) be classified as financing cash flows. For the year ended June 30, 2006, $359,772 of such excess tax benefits was classified as financing cash flows. See Note 2 - Summary of Significant Accounting Policies.
All employee stock options grants are expensed over the stock options vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. During the fiscal year-ended June 30, 2006, 2005 and 2004, the Company recorded stock option expense of $856,412, $385,193 and $339,005, respectively.
As of June 30, 2006, we have $1,387,737 of total unrecognized compensation cost related to non-vested awards granted under our various share-based plans, which we expect to recognize over an average period of three years.
The aggregate intrinsic values of the options exercised during fiscal years 2006, 2005 and 2004 are $2.2 million, $2.2 million and $0.4 million, respectively.
14. Warrants
As of June 30, 2006, the Company had no outstanding warrants. The final remaining issued warrants were exercised during the fiscal year ended June 30, 2006. The Company reserved an equal number of shares of common stock for issuance upon the exercise of its outstanding warrants. A summary of the Company warrants as of June 30, 2006, 2005 and 2004, and changes during the fiscal years then ended, is presented in the table below:
We received cash from options and warrants exercised during the years ended June 30, 2006, 2005 and 2004 of $1.5 million, $1.9 million and $1.1 million, respectively. The impact of these cash receipts is included in financing activities in the accompanying Consolidated Statements of Cash Flows.
15. Natural Gas and Oil Exploration Risk
The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control.
Other factors that have a direct bearing on the Company’s financial condition are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; the timing and costs of our future drilling; development and abandonment activities; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations, the amount of reported assets, liabilities and contingencies, and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
16. Sale of Properties - Continuing Operations
In December 2003, Contango and REX sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million for the year ended June 30, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Contango received approximately $3.7 million in cash proceeds for its portion of the sale. REX received cash proceeds of approximately $8.3 million for its portion of the sale. In connection with this sale, REX subsequently made distributions of $3.0 million to its members, of which $1.0 million was distributed to Contango.
17. Gain on Sale of Marketable Securities
As part of the formation of Freeport LNG, Cheniere Energy, Inc. (“Cheniere”) granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. All of the Company’s marketable securities related to an investment in Cheniere common stock, were sold in fiscal year 2004 resulting in a gain of $710,322 recognized under “Gain on Sale of Marketable Securities”.
18. Related Party Transactions
In the ordinary course of business, the Company contracted with Moblize to install automation equipment that will allow COI to remotely monitor, control and record, in real time, daily production volumes from the Grand Isle 72 #1 well. For the year ended June 30, 2006, the Company paid $25,000 to Moblize for such services.
On March 31, 2006, COE executed in favor of the Company, a Promissory Note (the “Note”) in the aggregate principal amount of $2,800,550. Under the terms of the Note, COE can borrow up to the stated amount to receive funding in connection with a certain Authority for Expenditure dated March 20, 2006 related to the Grand Isle 72 well, in which COE is a working interest owner. The Note is payable upon demand, and bears interest at a per annum rate of 10%. As of June 30, 2006, the outstanding principal balance under the Note was $250,000 and the amount of accrued interest thereon was approximately $6,000.
19. Subsequent Events
In July 2006, COE borrowed an additional $500,000 under the existing Note, bringing the total outstanding principal balance under the Note to $750,000.
In August 2006, the Company loaned $125,000 to Trulite under a Promissory Note (the “Trulite Note”). The Note bears interest at a per annum rate of 11.25% until February 9, 2007, at which point the per annum rate will change to prime rate plus three percentage points until May 1, 2007, which is when the Note plus all accrued and unpaid interest is due.
In August 2006, the Company exercised its right pursuant to two warrants, to purchase 324,324 shares of Moblize convertible preferred stock for $0.6 million. The Company’s total investment in Moblize is $1.2 million, for an approximate 33% ownership interest.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”.
Costs Incurred. The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:
Natural Gas and Oil Reserves. Proved reserves are estimated quantities of natural gas and oil 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 reserves are proved reserves that reasonably can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved natural gas and oil reserve quantities at June 30, 2006, 2005 and 2004, and the related discounted future net cash flows before income taxes are based on estimates prepared by W.D. Von Gonten & Co., petroleum engineering. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
The Company’s net ownership interests in estimated quantities of proved natural gas and oil reserves and changes in net proved reserves as of June 30, 2006, 2005 and 2004, all of which are located in the continental United States, are summarized below:
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Standardized Measure. The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved natural gas and oil reserves as of June 30, 2006, 2005 and 2004 are shown below:
Future cash flows are computed by applying fiscal year-end prices of natural gas and oil to year-end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.
Index to Financial Statements CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Change in Standardized Measure. Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized below:
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Quarterly Results of Operations. The following table sets forth the results of operations by quarter for the years ended June 30, 2006 and 2005:
(1) Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, impairment of natural gas and oil properties, and general and administrative expense and other income after benefit (expense) for income taxes.
(2) The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of common shares outstanding during that quarter.