UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| þ | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
for the fiscal year ended December 31, 2007
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| o | | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File No. 0-6529
DOUBLE EAGLE PETROLEUM CO.
(Name of registrant as specified in its charter)
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| Maryland | | 83-021469 |
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| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
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| 777 Overland Trail (P.O. Box 766) Casper, Wyoming | | 82601 |
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| (Address of principal executive offices) | | (Zip Code) |
(307) 237-9330
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Name of each exchange on which registered |
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| None | | None |
Securities registered pursuant to Section 12(g) of the Act:
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| Title of each class | | Name of each exchange on which registered |
| | | |
| $.10 Par Value Common Stock | | NASDAQ Global Select Market |
| $.10 Par Value Series A Cumulative Preferred Stock | | NASDAQ Global Select Market |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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| Large accelerated filero | | Accelerated filerþ | | Non-accelerated filer o
(Do not check if a smaller reporting company) | | Smaller reporting companyo |
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yeso Noþ
The aggregate market value of the voting common stock held by non-affiliates of the registrant at the close of business on June 30, 2007, was $147,776,215.
The number of shares of the registrant’s common stock outstanding as of March 3, 2008 was 9,148,105 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement relating to its 2008 annual meeting of stockholders to be filed within 120 days after December 31, 2007, are incorporated by reference in Part III of this Form 10-K.
DOUBLE EAGLE PETROLEUM CO.
FORM 10-K
TABLE OF CONTENTS
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The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and its subsidiary, as a consolidated entity, unless the context suggests otherwise. We have included technical terms important to an understanding of our business under “Glossary”, in Items 1 and 2, “Business and Properties”, of this Form 10-K. Throughout this document we make statements that are classified as “forward-looking”. Please refer to the “Cautionary Information about Forward-Looking Statements” section of this document for an explanation of these types of statements.
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. On December 15, 2006, our common shares began trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued and began trading on the NASDAQ Capital Market, under the symbol “DBLEP” on July 3, 2007 and began trading, under the symbol “DBLEP” on the NASDAQ Global Select Market on September 30, 2007. Our corporate offices are located at 777 Overland Trail, Casper, Wyoming 82601, and our telephone number is (307) 237-9330. Our principal executive offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, and our telephone number is (303) 794-8445.
Overview and Strategy
Our objective is to increase stockholder value by pursuing our corporate strategy of economically growing reserves and production through the development of our existing properties, selectively pursuing potential exploration projects where we have accumulated detailed geological knowledge, and selectively pursuing strategic acquisitions that may expand or complement our existing operations.
Our operations are currently focused on the two core development properties located in southwestern Wyoming, where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin and tight sands gas reserves and production in the Pinedale Anticline. Our current exploration activities involve properties in southwestern Wyoming and other Rocky Mountain states.
As of December 31, 2007, we had estimated proved reserves of 71.3 Bcf of natural gas and 413 MBbl of oil, or a total of 73.7 Bcfe. This represents a net increase in reserve quantities of 46% from the prior year, after adjustments for additions, current year production and revision of estimates. These reserves include additions of 45.2 Bcfe or 89% of prior year reserves. The increase in total reserves is due primarily to our drilling program in the Atlantic Rim, including 33 new production wells in our Catalina Unit and further development on the Pinedale Anticline. These proved oil and gas reserves, at December 31, 2007, have a PV-10 value of approximately $182.6 million, an increase of 170% from prior year (see reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 9). Of these reserves, 63% was proved developed and 97% was natural gas. The increase in PV-10 value is due both to an increase in reserve quantities and to higher year-end pricing.
During 2007, we invested $41.3 million in capital expenditures related to the development of our existing properties and $3.6 million related to exploratory activities, up from a total of $21.4 spent in 2006. The increase is due primarily to the Company beginning its Catalina development project and continued participation on the Pinedale Anticline. Our estimated capital budget for the 2008 projects is approximately $40-$60 million for drilling in the Catalina Unit and for ongoing non-operated development programs in the Atlantic Rim and Pinedale Anticline (spending is largely dependent on timing and locations selected for drilling). In our budgeting process we assess projects that are currently in progress and those proposed for future development to determine the risk and estimated rate of return, including our non-operated projects (primarily the Pinedale Anticline and the Doty Mountain and Sun Dog Units in the Atlantic Rim). Our 2008 capital budget is based on drilling programs which are low to medium risk development projects that provide a foundation for steady growth. The 2008 project budget estimate of $40-$60 million does not include the impact of any potential future exploration projects, any ongoing exploration/development activities or possible acquisitions. Although our emphasis is on developing low risk projects and increasing our acreage position of potential drilling prospects, we are continually evaluating exploration opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued.
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We expect to fund our 2008 capital expenditures with cash provided by operating activities and funds made available through our $50 million credit facility. We may find it necessary in the future to raise additional funds through private placements or registered offerings of equity or debt.
We also continue to evaluate acquisition opportunities that complement our existing operations, offer economies of scale and provide further development, exploitation and exploration opportunities. In addition to potential acquisitions, we may also divest certain non-core assets.
Operations
As of December 31, 2007, we owned interests in a total of 888 producing wells and had an acreage position of 521,144 gross acres (266,005 net), of which 390,224 gross acres (257,821 net) are undeveloped, in what we believe are natural gas prone basins of the Rocky Mountains and Nevada. Two developing areas, the Atlantic Rim coal bed natural gas play and the Pinedale Anticline, accounted for over 80% of our proved developed reserves as of December 31, 2007, and over 83% of our 2007 production.
As of December 31, 2007, our estimated acreage holdings by basin are:
| | | | | | | | | |
| Basin | | Gross Acres | | Net Acres |
| Washakie Basin | | | 117,274 | | | | 42,097 | |
| Huntington Basin | | | 192,975 | | | | 185,731 | |
| Greater Green River Basin | | | 38,530 | | | | 3,264 | |
| Powder River Basin | | | 33,353 | | | | 3,082 | |
| Wind River Basin | | | 50,826 | | | | 2,357 | |
| Other | | | 88,186 | | | | 29,474 | |
| | | | | | | | | |
| Total | | | 521,144 | | | | 266,005 | |
| | | | | | | | | |
Our focus is in areas where our geological and managerial expertise can provide us with competitive advantages. We intend to grow our reserves and production primarily through our current areas of development, which are as follows:
The Atlantic Rim Coal Bed Natural Gas Project
This play is a 40-mile long trend located in south central Wyoming, from the town of Baggs at the south end, to the town of Rawlins at the north end. The Mesaverde coals in this area differ from those found in the Powder River Basin in that they are thinner zones, but have higher gas content. Nevertheless, the productivity of coal beds is dependent not only on specific natural gas content, but also on favorable permeability to natural gas. Our current areas of development included within the Atlantic Rim are the Catalina Unit, for which we are the operator, and our non-operated interests in the Sun Dog and the Doty Mountain Units. We have an interest in 50,937 gross acres (29,735 net acres) along the Atlantic Rim.
During 2007, Double Eagle recognized net sales volumes from the coal bed natural gas projects in the Atlantic Rim of 1.7 Bcf, which represented 57% of our total 2007 sales volumes. These wells have been very economic, and we intend to continue to focus our efforts on the drilling of a minimum of 24 wells up to a maximum of 48 wells by us, in 2008. Additionally, Anadarko Petroleum Corporation (“Anadarko”), the operator of the Doty Mountain and Sun Dog Units, has indicated to us that it intends to drill up to 160 additional wells in the Atlantic Rim in 2008.
Catalina Unit
The Catalina Unit consists of 21,725 total acres (8,944 net acres) which the Company operates. We acquired a 100% working interest in the Cow Creek Field in the heart of the Atlantic Rim Coal Bed Natural Gas Project from KCS Mountain Resources in April 1999. The 14 original producing wells in the Cow Creek Field that Double Eagle operated became a part of the Catalina Unit participating area on December 21, 2007, when the new wells drilled by the Company during 2007 established production levels specified in the Unit Operating agreement. Upon reaching required production levels, the Unit participating area was established. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) as a percentage of the entire acreage of the PA. This PA and the associate working interest will change as more wells and acreage are added to the PA.
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On May 21, 2007, the Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”), which allows for the drilling of up to 1,800 coal-bed methane wells and 200 conventional oil and gas wells in the Atlantic Rim area, was published in the Federal Register, allowing Double Eagle to begin its developmental drilling program of up to 268 wells in the Catalina Unit. During June 2007, we were informed by the U.S. Bureau of Land Management (“BLM”) that three separate coalitions of conservation groups appealed, or were in the process of appealing, the approval of the EIS, and requested a stay of Double Eagle’s and others’ activities pending the Internal Board of Land Appeals (“IBLA”) determination of the appeals. We agreed to delay our plans to drill until August 6, 2007, at which time we began construction in preparation for drilling and commenced drilling on August 15, 2007. On September 5, 2007, the IBLA issued an Order denying the request for a stay of Double Eagle’s and others’ activity in the Atlantic Rim pending the determination of the appeals previously filed. On November 30, 2007, United States District Judge Richard J. Leon issued his Order and Memorandum Opinion denying a requested preliminary injunction to stop work at the Company’s Atlantic Rim Coal Bed natural gas project in south central Wyoming and as a result, we have been able to continue with our development in the Atlantic Rim.
As of December 31, 2007, 33 potential producing wells were drilled and cased with six being completed and hooked up to the sales line. The Catalina Unit PA is expected to be approved effective on December 21, 2007 and Double Eagle’s working interest in the PA will be revised to 73.84%. We plan to drill a minimum of 24 wells up to a maximum of 48 wells with drilling to resume in July 2008, when wildlife stipulations allow. The number and specific locations of the wells to be drilled is dependent upon the availability of financing, availability of drilling equipment and contractors and restrictions on drilling activities as set forth by applicable wildlife stipulations. With the drilling of these additional wells, Double Eagle’s working interest in the Catalina Unit will change to between 68.34% and 51.23% depending on the locations selected for these wells.
Double Eagle operates all of the wells in the Catalina Unit. The original 14 wells plus the six wells completed and hooked up in mid-December were producing at a rate of 6,124 MMcfe/day as of December 31, 2007.
Production in the Catalina Unit resulted in net sales volumes to Double Eagle of 1.5 Bcf in 2007 (compared to 1.6 Bcf in 2006 and 1.6 Bcf in 2005), which represented 50% of our total sales volumes for 2007.
Doty Mountain Unit
The Doty Mountain Unit is adjacent to and northeast of the Catalina Unit. The Mesaverde coals at Doty Mountain are thicker than in the Catalina Unit and have higher gas contents. Permeability was measured at over 150 millidarcies in the main coal. This unit is a 24,817 acre unit in which Double Eagle owns 3,280 gross and 3,280 net acres of leasehold working interest. Anadarko currently operates 52 producing wells. We own a 20.55% working interest in the 3,244 acre PA established for the coal bed natural gas production in the unit. This PA and the associated working interest, including Double Eagle’s, will change as more wells and acreage are added to the PA.
We began receiving and selling our share of Doty Mountain production in July 2006. We are in an under-produced position for prior year’s production at the Doty Mountain Unit and began receiving make up gas on August 1, 2007. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for additional discussion of production imbalances.
Anadarko notified us that it plans to drill an additional 55 wells in 2008 for the Doty Mountain Unit. Once these wells are drilled, it will change Double Eagle’s working interest from the current 20.55% to an estimated 12.0%.
During 2007, Double Eagle recognized a total of 156 MMcf of gas (net), or an average of 428 Mcf per day. In December 2007, the Unit averaged 573 Mcf per day.
Sun Dog Unit
The Sun Dog Unit is adjacent to and east of the Catalina Unit. Anadarko operates the 23,468 acre unit in which Double Eagle owns 3,886 gross and 2,045 net acres of working interest. Anadarko initially drilled 10 wells in which we originally had no economic interest. The 10 wells have been producing since July 2002. In 2005, Anadarko drilled two additional producers on acreage in which we had an interest. The PA was then established to include these two wells and the 10 Anadarko producers. As of December 31, 2007 we owned a 4.545% working interest in the 1,766 acre PA established for the first coal bed natural gas production in the unit. Our working interest in the PA will change as more wells and acreage are added.
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Anadarko is in the process of drilling and completing 52 additional wells, which it intends to have completed by March of 2008. Once the wells are drilled, Double Eagle will have a working interest of approximately 8.4% in the Unit. Anadarko has notified us that it intends to drill an additional 68 wells in the Sun Dog Unit in 2008, bringing Double Eagle’s working interest to an estimated 7.9%.
We are in an under-produced position for prior and current year’s production at the Sun Dog Unit and began receiving our share of current production and make up gas on August 1, 2007. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for additional discussion of production imbalances.
During 2007, Double Eagle recognized a total of 67 MMcf of gas (net), or an average of 182 Mcf per day from the Sun Dog Unit. In December 2007, the Unit averaged 214 Mcf per day.
Other Units
We also have small interests in the Brown Cow, Jolly Roger and Red Rim Units that are all operated by Anadarko. As of December 31, 2007, no significant gas sales had occurred from these units.
The Pinedale Anticline in the Green River Basin of Wyoming
The Pinedale Anticline is in southwestern Wyoming, 10 miles south of the town of Pinedale. Questar operates 2,400 acres in the Mesa Unit in which we hold a net acreage position of 130 acres. The Mesa Field on the Pinedale Anticline includes 85 non-operated wells producing approximately 26% of our total production for 2007. In 2007, the three Participating Areas of the Mesa Unit produced a total of 26.8 Bcf of natural gas and 850 MBbls of oil. Our net production from the Mesa Unit in 2007 was 754 MMcf of natural gas and 6,097 Bbls of oil. We participated in the drilling of 18 new wells during 2007. The operator has informed us of its intention to hook up these 18 wells drilled in 2007 at a rate of three wells in April and five wells per month in each of May, June and July of 2008. We believe the operator will drill 16 additional wells in 2008.
In the Mesa “A” Participating Area, where we have an overriding royalty interest, there were 31 producing wells that produced a total of 99 MMcf of natural gas and 1,185 Bbls of oil in 2007 to our interest. Our overriding royalty interest is .312%, with a net acre position of at least 1.875 net acres under a gross of 600 acres in the “A” Participating Area.
In the Mesa “B” Participating Area, where we have an 8% average working interest in the shallow producing formations and a 12.5% average working interest in the deep producing formations, there were 39 producing wells that produced 450 MMcf of natural gas and 3,863 Bbls of oil in 2007 to our interest. We have a net acre position of 64 net acres under a gross of 800 acres in the shallower formations in the “B” Participating Area and 100 net acres under a gross of 800 acres in the deep producing formations.
In the Mesa “C” Participating Area, where we have a carried working interest after payout of 6.4%, 15 wells produced 205 MMcf and 1,049 Bbls of oil in 2007 to our interest. We have 65.27 net acres under a gross of 1,000 acres in the “C” Participating Area. Payout is on a block basis and will occur whenever profits exceed costs within the participating area. Therefore, we will move in and out of payout as additional wells are drilled. As of December 31, 2007, we are not in a paid out status.
At year end, we had working interests or overriding royalty interests in 4,840 acres in and around this developing natural gas field. An expansion of the Kern River Pipeline, which was completed in May 2003, connects this field to a large gas market in southern California. It is anticipated that this property will continue to produce significant revenues for us in the foreseeable future.
The Wind River Basin in central Wyoming
Located in central Wyoming, the Wind River Basin is home to Wyoming’s first oil production, which began in 1884. Since that time, numerous fields have been discovered in the Basin, including two very large natural gas accumulations, the Madden Anticline and the Cave Gulch/Waltman Fields. We have interests in 50,826 gross acres, constituting 2,357 net acres, of leases in this Basin.
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Madden Anticline
The Madden Anticline is located in central Wyoming, 65 miles west of the town of Casper. The anticline is 20 miles long and six miles wide laying in the deepest part of the Wind River Basin.
There are two large natural gas fields, Madden and Long Butte that are being drilled and developed on the anticline. The Madden and Long Butte Units were merged in 2004, but the Long Butte Unit Mesaverde and Cody Participating Areas have remained separate and are operated by Moncrief Oil International, Inc. (“Moncrief”). In 2005, the deep Paleozoic formations, or “Sour Gas” zones, of the Madden Field and Long Butte Field were combined, and they produced 133 Bcf of natural gas in 2007, making the field’s cumulative production over 1.6 trillion cubic feet from six formations at depths of 3,000 to 25,000 feet. The Madden Unit is operated by Conoco/Phillips. We own an approximate 16.67 % working interest in 734.25 acres on the anticline that potentially could be included in the Madden Sour Gas Participating Area. With the current approved PA, 504.74 gross acres (84.14 net acres) is included in the 24,088 acre participating area. The unit’s primary operator, Conoco/Phillips (formerly Burlington Resources “BR”) plans to continue to drill additional wells in the unit.
Through unitization, we acquired an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the Lost Cabin Gas Processing Plant in late 2006, at a cost of approximately $2.5 million. The Madden Sour Gas Participating Area produced 10 Mcf net to our interest of gas in December 2007 from seven wells. These are long-lived wells with large producing rates and reserves. We have a 0.349% working interest in the deep participating area.
The Company has not been paid any of the proceeds generated by the sale of gas produced from the Madden Deep Unit over the period beginning with the effective date of the Unit through June 30, 2007. Double Eagle began receiving payments for its share of the sales on July 1, 2007. The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Burlington Resources (“BR”) and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the gas produced from the Madden Deep Unit over at least the period from February 1, 2002 through June 30, 2007. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis.
We also own interests, which are restricted in depth and size, in over 12,000 additional acres on the Madden Anticline. Additionally, we operate and produce from one lower Fort Union well and one upper Fort Union well outside of the unit. We will continue to produce these two wells and evaluate the potential for offsets.
South Sand Draw
The South Sand Draw Field is located in the southern portion of the Wind River Basin approximately 36 miles southeast of Riverton, Wyoming. We currently have 1,495 acres under lease, in which our working interest is 75%. Additional drillable prospects exist on the east side of our leasehold and may be drilled in the future.
The Moxa Arch and other areas in southwest Wyoming
We are continuing our participation in further development drilling on the Moxa Arch and other areas within southwest Wyoming (197 non-operated wells). Within these areas, we participated in the drilling of 71 development wells with working interests ranging from 0.11% to 16.27% in 2007.
Exploration Projects
Accounting for Suspended Well Costs
FASB Staff Position FAS 19-1 (FSP 19-1), Accounting for Suspended Well Costs, was effective for the first reporting period beginning after April 4, 2005. FSP 19-1 concludes that, for companies using the successful efforts method of accounting, exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the well. FSP 19-1 specifies that the costs of drilling an exploratory well shall not be carried as an asset for a period greater than one year from completion of drilling (or abandonment of a project), unless it can be shown that sufficient progress (as defined) has been made in assessing the economic and operational viability of a
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project. Since adopting FSP 19-1, the Company continually evaluates all existing capitalized exploratory well costs.
Atlantic Rim Exploratory Tests
In addition to development of our existing Atlantic Rim properties, we also previously engaged in exploratory/development efforts at the Cow Creek Unit Deep #2 (a Madison test near our coal bed natural gas production at Cow Creek) and the PH State 16-1 well in the South Fillmore prospect just north of Cow Creek. Both projects are currently being assessed as to future operational viability.
The Cow Creek Unit Deep #2 well is treated as two wells for accounting purposes. The costs incurred to drill to the Mesaverde formation, a proved area known to be productive, are treated as developmental costs, while the costs to drill beyond the Mesaverde formation are treated as exploratory costs. FASB Staff Position FAS 19-1 (“FSP 19-1”), as discussed in further detail below, requires management to assess continued capitalization of exploratory projects capitalized for a period greater than one year to determine whether or not it is appropriate to continue capitalization of the costs. Due to the passage of time, and as required by FSP 19-1, the Company expensed $4,395 of capitalized costs related to the exploratory portion of the Cow Creek Unit Deep #2 well in the quarter ended September 30, 2007.
The PH State 16-1 (South Fillmore) well was completed during the third quarter of 2006. In July 2007, GMT Exploration Company LLC drilled the SJ Fee 11-9 well, in which the Company has a 50% working interest before payout and a 30% working interest after payout, one mile northwest of the PH State 16-1 well. The SJ Fee 11-9 well has been completed in the Mesaverde Sand interval and commercial gas sales are expected to begin early in 2008. The PH State 16-1 well was completed in a similar Mesaverde Sand and Coal formation. The Company is currently evaluating the project to determine if the well can be recompleted as a producer from the sand formation and has plans to continue developing the area, including potentially drilling or participating in the drilling of additional wells. However, due to the passage of time and the uncertainty as to the future of this well, and as required by FSP 19-1, the Company expensed $2,759 of capitalized costs relating to the PH State 16-1 well during quarter ended December 31, 2007.
The Christmas Meadows Prospect in Utah
Christmas Meadows is a structural dome in the southwest corner of the prolific Green River Basin, in Summit County, Utah. The dome is overlain by the Wyoming Overthrust Belt and the North Flank Thrust of the Uinta Mountains. During the first quarter of 2007, drilling at the Table Top Unit #1 well reached the originally planned depth of 15,760 feet. The drilling did not find reservoir rocks with sufficient permeability and operations were suspended to assess alternative approaches to completing the project. The Table Top Unit, as originally formed, was dissolved, and, having met the governmental permitting obligation for the Unit test, the time-frame has been extended for drilling the newly formed Main Fork Unit until at least April 2009. The Company is in the process of evaluating potential alternatives, including drilling or farming out the drilling of the Table Top Unit #1 to drill deeper to the Nugget Sandstone around 18,000 feet. Based on the guidance included in FSP 19-1, management determined that it was necessary to expense the $5,773 of capitalized costs associated with the Table Top Unit #1 well.
Nevada
Double Eagle has leased 192,975 gross acres, 185,731 net acres, in the Huntington Valley in Elko and White Pine Counties, Nevada. This area was chosen because of excellent hydrocarbon source rock in both the Tertiary and Paleozoic rocks and high heat flow to generate natural gas, as well as certain natural gas shows incurred in limited previous drilling.
During August 2007, VF Neuhaus began drilling the Straight Flush #17-1 well in Huntington Valley, Nevada. Double Eagle had a 97.3% working interest in the well and further earned additional interests under six sections of land. No commercial deposits of oil and gas were identified and the well was plugged in October 2007. Costs incurred through December 31, 2007 of $1,983 were charged to expense as dry hole costs.
Eastern Washakie Midstream Pipeline LLC
The Company owns, through its wholly-owned subsidiary, Eastern Washakie Midstream Pipeline LLC, a 13-mile pipeline that connects the Catalina Unit with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. and provides us with access to the interstate gas markets from southern Wyoming, and the ability to move third party gas. The pipeline is expected to provide, but does not guarantee, reliable transportation for future development by the Company and third party operators in the Atlantic Rim of the Eastern Washakie Basin.
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Reserves
The reserve estimates at December 31, 2007, 2006 and 2005 presented below were reviewed by the independent petroleum engineering firm Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. For the periods presented, Netherland, Sewell & Associates, Inc. evaluated properties representing a minimum of 98% of our reserves, valued at the total estimated future net cash flows before income taxes, discounted at 10% (“PV-10”). The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by Double Eagle. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors. For more information regarding the inherent risks associated with estimating reserves, see Item 1A, “Risk Factors.”
Oil and gas reserve estimates:
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Proved developed oil reserves (Bbls) | | | 253,478 | | | | 254,346 | | | | 199,931 | |
| Proved undeveloped oil reserves (Bbls) | | | 159,334 | | | | 105,819 | | | | 128,821 | |
| | | | | | | | | | |
| Total proved oil reserves (Bbls) | | | 412,812 | | | | 360,165 | | | | 328,752 | |
| | | | | | | | | | | | | |
| Proved developed gas reserves (Mcf) | | | 44,782,553 | | | | 30,075,467 | | | | 23,032,277 | |
| Proved undeveloped gas reserves (Mcf) | | | 26,471,312 | | | | 18,421,252 | | | | 24,202,058 | |
| | | | | | | | | | |
| Total proved gas reserves (Mcf) | | | 71,253,865 | | | | 48,496,719 | | | | 47,234,335 | |
| | | | | | | | | | | | | |
| Total proved gas equivalents (Mcfe) (1) | | | 73,730,737 | | | | 50,657,709 | | | | 49,206,847 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Present value of estimated future net cash flows before income taxes, discounted at 10% (2) | | $ | 182,594 | | | $ | 67,639 | | | $ | 126,776 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Reconciliation of non-GAAP financial measure: | | | | | | | | | | | | |
| PV-10 | | $ | 182,594 | | | $ | 67,639 | | | $ | 126,776 | |
| | | | | | | | | | |
| Less: Undiscounted income taxes | | | (96,370 | ) | | | (42,578 | ) | | | (74,738 | ) |
| Plus: 10% discount factor | | | 44,075 | | | | 24,972 | | | | 39,255 | |
| | | | | | | | | | |
| Discounted income taxes | | | (52,295 | ) | | | (17,606 | ) | | | (35,483 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 130,299 | | | $ | 50,033 | | | $ | 91,293 | |
| | | | | | | | | | |
| | |
| (1) | | Oil is converted to Mcf of gas equivalent at one barrel per six Mcf. |
| |
| (2) | | The present value of estimated future net cash flows as of each date shown was calculated using oil and gas prices being received by each respective property as of that date. The average prices utilized for December 31, 2007, 2006, and 2005, respectively, were $6.04 per MMBtu and $92.50 per barrel of oil; $4.46 per MMBtu and $57.75 per barrel of oil; and $7.72 per MMBtu and $57.75 per barrel of oil. |
The table above also shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved oil and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. Reference should also be made to the Supplemental Oil and Gas Information included in Item 15, Note 8 to the Notes to the Consolidated Financial Statements for additional information.
9
Production
The following table sets forth oil and gas production from our net interests in producing properties for the years ended December 31, 2007, 2006 and 2005. Average production costs in the table do not include pipeline operations costs of $.21/Mcfe which are included in the Consolidated Statement of Operations in the line item Production Costs.
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, |
| | | 2007 | | 2006 | | 2005 |
Quantities: | | | | | | | | | | | | |
| Oil (Bbls) | | | 13,963 | | | | 12,729 | | | | 15,470 | |
| Gas (MMcf) | | | 2,928 | | | | 3,141 | | | | 2,976 | |
| | | | | | | | | | | | | |
Average sales price: | | | | | | | | | | | | |
| Oil ($/Bbl) | | $ | 63.17 | | | $ | 57.90 | | | $ | 49.26 | |
| Gas($/Mcf) | | $ | 5.18 | | | $ | 5.57 | | | $ | 6.62 | |
| | | | | | | | | | | | | |
| Average Production Cost ($/Mcfe) | | $ | 1.89 | | | $ | 1.11 | | | $ | 1.24 | |
| | | | | | | | | | | | | |
| Average Production Tax ($/Mcfe) | | $ | 0.64 | | | $ | 0.69 | | | $ | 0.82 | |
Delivery Contracts
We have entered into fixed delivery contracts with a third-party marketing company for our production at the Atlantic Rim and the Pinedale Anticline, which reduces our overall exposure to downward commodity price fluctuations. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts may limit the risk of fluctuating cash flows due to changing commodity prices.
FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities,was effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which has subsequently been amended by SFAS No. 138 and SFAS No. 149, these fixed delivery contracts qualify for the scope exception under “normal purchases and normal sales,” so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not settle net. During both the first quarter of 2007 and beginning in September 2007, production in the Catalina Unit (original 14 Cow Creek wells) fell below contractual volumes and Double Eagle purchased gas on the spot market in order to satisfy the fixed delivery contracts. The Company has determined that this qualifies as net settlement, and accordingly, the Catalina Unit contracts no longer qualify as “normal purchases and normal sales” under SFAS No. 133. In accordance with the provisions of SFAS No. 133, and effective November 1, 2007, the Catalina Unit fixed delivery contracts are accounted for as cash flow hedges with the change in the market value being recognized as either an asset or liability in the Consolidated Balance Sheets and are measured at fair value. Changes in the fair value are recorded each period in other comprehensive income or current earnings, depending on the nature of the transaction. See Item 15, Note 5 to the Notes to the Consolidated Financial Statements for additional discussion of hedge accounting. Our remaining Atlantic Rim fixed delivery contracts, for production from the Doty Mountain and Sun Dog Units, as well as our Pinedale Anticline contracts, continue to be accounted for under the “normal purchases and normal sales” exception as it continues to be probable that these contracts will not settle net and will result in physical delivery for the duration of the contracts.
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As of December 31, 2007, we had sales delivery contracts in effect for approximately 64% of our current daily production (volume and daily production are expressed in Mcf):
| | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | |
| | | Contractual | | Daily | | | | | | Fixed |
| Property | | Volume | | Production | | Term | | Price/Mcf |
| Catalina | | | 517,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | |
| | | | 547,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | |
| | | | 1,094,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | |
| | | | 670,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | |
| Atlantic Rim | | | 578,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | |
| Pinedale Anticline | | | 547,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Company Total | | | 3,953,000 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
We also have a transportation agreement for all production volumes through our pipeline, for which we receive a third party fee per Mcf of gas transported.
In accordance with the Company’s on-going risk management and to limit the credit risk associated with the above sales delivery contracts, subsequent to year-end, the Company purchased NYMEX futures contracts for 3,000 Mcf per day, for the period November 1, 2008 through March 31, 2009. The price of the futures contract is $9.53. These contracts will limit the Company’s exposure to price increases above our fixed sales delivery contract prices during the winter months when prices historically rise.
Productive Wells
The following table categorizes certain information concerning the productive wells in which we owned an interest as of December 31, 2007. For purposes of this table, wells producing both oil and gas are shown in both columns. We operate 64 wells in the state of Wyoming. We do not operate producing wells in any other state.
| | | | | | | | | | | | | | | | | |
| | | Oil | | Gas |
| State | | Gross | | Net | | Gross | | Net |
| Wyoming | | | 86 | | | | 5.9940 | | | | 828 | | | | 68.7538 | |
| Other | | | 27 | | | | 0.3934 | | | | 5 | | | | 0.0855 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 113 | | | | 6.3874 | | | | 833 | | | | 68.8393 | |
| | | | | | | | | | | | | | | | | |
Drilling Activity
We drilled or participated in the drilling of wells as set forth in the following table for the periods indicated. In certain of the wells in which we participate, we have an overriding royalty interest and no working interest.
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| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, |
| | | 2007 | | 2006 | | 2005 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Exploratory | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Gas | | | 1 | | | | 0.50 | | | | 2 | | | | 1.26 | | | | 25 | | | | 0.62 | |
| Dry Holes | | | 1 | | | | 0.98 | | | | 1 | | | | 0.33 | | | | — | | | | — | |
| Water Injection | | | — | | | | — | | | | — | | | | — | | | | 3 | | | | 2.02 | |
| Other | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2 | | | | 1.48 | | | | 3 | | | | 1.59 | | | | 28 | | | | 2.64 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Development | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Gas | | | 223 | | | | 35.06 | | | | 87 | | | | 7.32 | | | | 75 | | | | 1.13 | |
| Dry Holes | | | — | | | | — | | | | 1 | | | | 0.21 | | | | — | | | | — | |
| Water Injection | | | 9 | | | | 2.72 | | | | 4 | | | | 0.82 | | | | — | | | | — | |
| Other | | | 1 | | | | 0.08 | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 233 | | | | 37.86 | | | | 92 | | | | 8.35 | | | | 75 | | | | 1.13 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 235 | | | | 39.34 | | | | 95 | | | | 9.94 | | | | 103 | | | | 3.77 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
All our drilling activities are conducted on a contract basis with independent drilling contractors.
Finding and Development Costs
For the year ended December 31, 2007, we had gross additions to our proved reserves by 45.2 Bcfe, as compared to our 2007 annual production of 3.0 MMcfe. During the same period, we expended $44.9 million in finding and development costs, defined as development and exploration costs incurred by the Company during 2007. This activity resulted in a one year finding and development cost in 2007 of $0.99 per Mcfe. “Finding and development costs per Mcfe” is determined by dividing our annual development costs incurred and exploration costs incurred on projects completed during the year by gross proved reserve additions, including both developed and undeveloped reserves added during the current year (gross amounts, not net of production). During 2007, the Company recorded impairment charges relating to our existing exploratory projects totaling $14,910. The effect of these impairment charges on the calculation of finding and development costs was $0.33 per Mcfe. Excluding the effect of these charges, finding and development costs were $0.66 per Mcfe. We use this measure as one indicator of the overall effectiveness of exploration and development activities. In determining the finding and development costs per Mcfe for the years ended December 31, 2007, 2006, and 2005, total proved reserve additions consisted of (expressed in Mcfe):
| | | | | | | | | | | | | |
| | | As of December 31, |
| | | 2007 | | 2006 | | 2005 |
| Proved developed (MMcfe) | | | 21,888 | | | | 11,863 | | | | 9,051 | |
| Proved undeveloped (MMcfe) | | | 23,317 | | | | (1,468 | ) | | | 6,622 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Total proved reserves added | | | 45,205 | | | | 10,395 | | | | 15,673 | |
| | | | | | | | | | | | | |
Proved reserves were added in each of 2007, 2006 and 2005 through both gross-incremental additions associated with our higher density spacing of prospective drilling locations on our properties, as well as through our development drilling activities.
Our finding and development cost per Mcfe measure has certain limitations. Consistent with industry practice, our finding and development costs have historically fluctuated on a year-to-year basis based on a number of factors including the extent and timing of new discoveries and property acquisitions. Due to the timing of proved reserve additions and timing of the related costs incurred to find and develop our reserves, our finding and development costs per Mcfe measure often includes quantities of reserves for which a majority of the costs of development have not yet been incurred. Conversely, the measure also often includes costs to develop proved reserves that had been added in earlier years. Finding and development
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costs, as measured annually, may not be indicative of our ability to economically replace oil and natural gas reserves because the recognition of costs may not necessarily coincide with the addition of proved reserves. Our finding and development costs per Mcfe may also be calculated differently than the comparable measure for other oil and gas companies.
Acreage
The following tables set forth the gross and net acres of developed and undeveloped oil and gas leases in which Double Eagle had working interests and royalty interests as of December 31, 2007. Undeveloped acreage includes leasehold interests that may have been classified as containing proved undeveloped reserves.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Developed Acres (1) | | Undeveloped Acres (2) | | Total Acres |
| State | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wyoming | | | 114,461 | | | | 7,893 | | | | 111,770 | | | | 47,374 | | | | 226,231 | | | | 55,267 | |
| Nevada | | | — | | | | — | | | | 192,975 | | | | 185,731 | | | | 192,975 | | | | 185,731 | |
| Other | | | 2,906 | | | | 66 | | | | 51,612 | | | | 22,681 | | | | 54,518 | | | | 22,747 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 117,367 | | | | 7,959 | | | | 356,357 | | | | 255,786 | | | | 473,724 | | | | 263,745 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Acreage by Royalty Interest:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Developed Acres (1) | | Undeveloped Acres (2) | | Total Acres |
| State | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wyoming | | | 10,464 | | | | 162 | | | | 28,234 | | | | 1,552 | | | | 38,698 | | | | 1,714 | |
| Other | | | 3,089 | | | | 63 | | | | 5,633 | | | | 483 | | | | 8,722 | | | | 546 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 13,553 | | | | 225 | | | | 33,867 | | | | 2,035 | | | | 47,420 | | | | 2,260 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of the Company’s properties that include multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above. |
| |
| (2) | | Undeveloped acreage is lease acreage 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 such acreage contains proved reserves. |
Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date, in which event the lease will remain in effect until the cessation of production.
The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:
| | | | | | | | | |
| | | Expiring Acreage |
| Fiscal Year | | Gross | | Net |
| 2008 | | | 1,315 | | | | 628 | |
| 2009 | | | 20,837 | | | | 7,895 | |
| 2010 and thereafter | | | 498,992 | | | | 257,482 | |
| | | | | | | | | |
| Total | | | 521,144 | | | | 266,005 | |
| | | | | | | | | |
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Other Significant Developments Since December 31, 2006
Effective January 1, 2008, the Company promoted Kurtis Hooley to Chief Financial Officer to replace Lonnie Brock, who left the Company to pursue other professional interests. Mr. Hooley has three years experience with the Company and 17 years of operational and management experience. Effective December 31, 2007, Stephen Hollis, our Chief Executive Officer, Chairman and President, who has been with the Company for 19 years, resigned from those positions. Mr. Hollis is continuing to serve as a Board member and as an employee in an advisory capacity to the Board. In January 2008, the Company announced the promotion of Robert Reiner to Vice President, Operations. Mr. Reiner has served as the Company’s Senior Engineer since 2004. Prior to joining the Company, Mr. Reiner served in numerous operational and engineering capacities within the industry.
On January 23, 2007, pursuant to the universal shelf registration statement on Form S-3 with the Securities and Exchange Commission, declared effective on December 15, 2006, completed a follow-on public offering of 500,000 shares of Common Stock at a price to the public of $21.55 per share. Proceeds from the offering were approximately $10 million, including the underwriter’s exercise of its over-allotment option, after deducting the underwriting discounts and commissions and offering expenses. The net proceeds from this offering were used to pay down the outstanding indebtedness on our revolving line of credit.
On July 5, 2007, pursuant to the Company’s universal shelf registration statement on Form S-3, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock (“Series A Preferred Stock”) at a price to the public of $25.00 per share. Net proceeds from the offering were approximately $38 million, after deducting underwriter discounts and offering expenses. A portion of the net proceeds from this offering was used to pay off the outstanding indebtedness on the Company’s revolving line of credit of approximately $17 million. The remaining proceeds initially were invested in short term investment accounts and subsequently were used to fund the drilling of the additional 33 wells in the Catalina Unit during the second half of 2007.
We declared and paid cash dividends of $879 ($.5461 per share) and $931 ($.5782 per share) on the Series A Preferred Stock for the quarter ended September 30, 2007 and December 31, 2007 respectively. We will pay dividends of the Series A Preferred Stock in the amount of $2.3125 per share each year, payable quarterly.
On August 21, 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (“Rights Plan”). Under the Rights Plan, the Company issued a dividend of one Preferred Share Purchase Right for each outstanding share of common stock held by stockholders of record on September 4, 2007. The Rights Plan is intended to safeguard against abusive takeover tactics that limit the ability of all shareholders to realize the long-term value of their investment in Double Eagle. The Rights Plan was not adopted in response to any specific takeover effort, and will not prevent a takeover, but should encourage anyone seeking to acquire Double Eagle to negotiate with the Board prior to attempting a takeover. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for additional discussion the Rights Plan adopted by the Company’s Board of Directors.
Marketing and Major Customers
The principal products produced by us are natural gas and crude oil. These products are marketed and sold primarily to purchasers that have access to nearby pipeline facilities. Typically, oil is sold at the wellhead at field-posted prices and natural gas is sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, quality); and (ii) at spot prices. As of December 31, 2007, there were 3,953,000 Mcf of future production volumes under contract at prices ranging from $5.47 to $6.41 per Mcf.
The marketing of most of our products is performed by a third party marketing company, Summit Energy, LLC. During the years ended December 31, 2007, 2006 and 2005, sales to Summit Energy accounted for 67%, 75% and 68%, respectively, of our total oil and gas production revenue. There were no other companies that purchased more than 10% of our oil and gas production. Although a substantial portion of our production is purchased by one customer, we do not believe the loss of this customer would have a material adverse effect on our business as other customers would be accessible to us.
Title to Properties
Substantially all of our working interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of drilling operations on properties. We have obtained title opinions or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of the value of our
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properties is subject to a mortgage under our credit facility, customary royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. We also perform a title investigation before acquiring undeveloped leasehold interests.
Seasonality
Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations.
We have entered into various fixed delivery contracts for a portion of our production, which reduces our overall exposure to seasonal demand and resulting commodity price fluctuations. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. As of December 31, 2007, we had sales delivery contracts in effect for approximately 64% of our current daily production.
Competition
The oil and gas industry is extremely competitive, particularly in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position also depends on our geological, geophysical and engineering expertise, and our financial resources. We believe that the location of our leasehold acreage, our exploration, drilling and production expertise and the experience and knowledge of our management and industry partners enable us to compete effectively in our current operating areas. Currently, access to incremental drilling equipment in certain regions is difficult, but is not, at this time, anticipated to have any material negative impact on our ability to deploy our capital drilling budget for 2008.
Government Regulations
Our business is subject to various types of regulation at the federal and state and local levels. Matters subject to regulation include the issuance of drilling permits, the methods used to drill and case wells, reports concerning operations, the spacing of wells, the unitization of properties, taxation issues and environmental protection. These regulations may change from time-to-time.
Our operations also are subject to various federal and state limits on allowable rates of production by well or proration unit. These regulations may affect the amount of natural gas and oil available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.
Federal legislation and regulatory controls have historically affected the manner in which our production is transported. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, including all sales of our production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act. Our sales of oil and natural gas are not currently regulated and are made at market prices.
We participate in a substantial percentage of our wells on a non-operated basis, and may be accordingly limited in our ability to control some risks associated with these natural gas and oil operations. We believe that operations where we own interests, whether operated or not, comply in all material respects with the applicable laws and regulations and that the existence and enforcement of these laws and regulations have no more restrictive an effect on our operations than on other similar companies in the energy industry.
Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such
15
proposals may become effective or the overall effect any laws or regulations resulting from these proposals and proceedings may have on our operations.
No material portion of our business is currently subject to re-negotiation of profits or termination of contracts or subcontracts at the election of the federal government.
Environmental Laws and Regulations
Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected. At this time, we have no plans to make any material capital expenditures for environmental control facilities.
The National Environmental Policy Act (“NEPA”) requires a thorough review of the environmental impacts of “major federal actions” and a determination of whether proposed actions on federal land would result in “significant impact”. For oil and gas operations on federal lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability. The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also know as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. Our operations may also be subject to the Endangered Species Act, the National Historic Preservation Act and a variety of other federal, state and local review, mitigation, permitting, reporting, and registration requirements relating to protection of the environment. We believe that we, as operators, and the outside operators with which we do business are in substantial compliance with current applicable federal, state and local environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us. Nevertheless, changes in environmental laws have the potential to adversely affect operations.
Cautionary Information about Forward-Looking Statements
This Annual Report on Form 10-K includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in this Form 10-K in Part I, “Item 1A. Risk Factors” and the following:
| | • | | Our ability to continue to develop our coal bed methane projects in the Atlantic Rim; |
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| | • | | Our ability to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices; |
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| | • | | Incorrect estimates of required capital expenditures; |
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| | • | | Increases in the cost of drilling, completion and gas collection or other costs of production and operations; |
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| | • | | Our ability to increase our natural gas and oil reserves; |
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| | • | | The amount and timing of capital deployment in new investment opportunities; |
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| | • | | The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment; |
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| | • | | Our future capital requirements and availability of capital resources to fund capital expenditures; |
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| | • | | Our ability to successfully integrate and profitably operate any future acquisitions; |
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| | • | | The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge; |
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| | • | | Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs; |
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| | • | | Our ability to remedy any deficiencies that may be identified in the review of our internal controls; |
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| | • | | The Credit worthiness of third-parties which we enter into business agreements with; |
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| | • | | General economic and political conditions, including tax rates or policies and inflation rates; |
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| | • | | Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment; |
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| | • | | Weather and other natural phenomena; |
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| | • | | Industry and market changes, including the impact of consolidations and changes in competition; |
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| | • | | The effect of accounting policies issued periodically by accounting standard-setting bodies; |
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| | • | | The actions of third party co-owners of interests in properties in which we also own an interest; |
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| | • | | The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events; and |
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| | • | | The outcome of any future litigation or similar disputes and the impact on any such outcome or related settlements. |
We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.
Employees and Office Space
As of December 31, 2007, we had 15 full-time employees. None of our employees is subject to a collective bargaining agreement, and we consider our relations with our employees to be excellent. We own 6,765 square feet of office space in Casper, Wyoming, which serves as the corporate and operations headquarters. We lease 3,932 square feet of office space in Denver, Colorado, for our administrative offices.
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended, are available on our website athttp://www.dble.us/, as soon as reasonably practicable after we electronically file such reports with, or furnish those reports to, the Securities and Exchange Commission. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and amendments to reports are available free of charge by writing to:
Double Eagle Petroleum Co.
John Campbell, Investor Relations
1675 Broadway, Suite 2200
Denver, CO 80202
We maintain a code of ethics applicable to our Board of Directors, principal executive officer, and principal financial officer, as well as all of our other employees. A copy of our Code of Business Conduct and Ethics and our Whistleblower Procedures may be found on our website athttp://www.dble.us/, under the Corporate Governance section. These documents are also available in print to any shareholder who requests them. Requests for these documents may be submitted to the above address.
Information on our website is not incorporated by reference into thisForm 10-K and should not be considered a part of this document.
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Glossary
The terms defined in this section are used throughout this Annual Report on Form 10-K.
3-D seismic or 3-D data.Seismic data that are acquired and processed to yield a three-dimensional picture of the subsurface.
Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf.Billion cubic feet, used in reference to natural gas.
Bcfe.Billion cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Boe.Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Darcy.A standard unit of measure of permeability of a porous medium.
Dip meter.A wireline well log that measures the orientation of each rock layer in a well.
Development well.A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Estimated net proved reserves.The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Exploratory well.A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond its productive horizon.
Farmout. An assignment of interest in a drilling location and related acreage conditioned upon the drilling of a well on that location.
Field.An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
Gross acre.An acre in which a working interest is owned.
Gross well.A well in which a working interest is owned.
MBbl.One thousand barrels of oil or other liquid hydrocarbons.
Mcf.One thousand cubic feet.
Mcfe. One thousand cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Millidarcy.One thousandth of a darcy and is a commonly used unit for reservoir rocks. See definition of darcy above.
MMcf.One million cubic feet.
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MMcfe.One million cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBtu.One million British Thermal Units. A British Thermal Unit is the amount of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Net acres or net wells.The sum of our fractional working interests owned in gross acres or gross wells.
Permeability.The ability, or measurement of a rock’s ability, to transmit fluids, typically measured in darcies or millidarcies. Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.
Productive well.A well that is producing oil or gas or that is capable of production.
Proved developed reserves.Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves.The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
PV-10 value.The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.
Recompletion.The completion for production from an existing wellbore in another formation other than that in which the well has previously been completed.
Royalty.The share paid to the owner of mineral rights expressed as a percentage of gross income from oil and gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
Royalty interest.An interest in an oil and gas property entitling the owner to shares of oil and gas production free of costs of exploration, development and production.
Undeveloped acreage.Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated net proved reserves.
Velocity.The rate at which a wave travels through a medium. Its usage in geophysics is as a property of a medium-i.e. distance divided by travel time. Velocity can be determined from laboratory measurements, acoustic logs, vertical seismic profiles or from velocity analysis of seismic data. Velocity can vary vertically, laterally and azimuthally in anisotropic media such as rocks, and tends to increase with depth in the Earth because compaction reduces porosity.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production.
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ITEM 1A. RISK FACTORS
Investing in our securities involves risk. In evaluating the Company, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this annual report. Each of these risk factors could materially adversely affect our business, operating results or financial condition, as well as adversely affect the value of an investment in our common or preferred stock. In addition, the ''Forward-Looking Statements’’ located in this Form 10-K, and the forward-looking statements included or incorporated by reference herein describe additional uncertainties associated with our business.
We may be unable to further develop our coal bed methane projects in the Atlantic Rim, which would have a significant adverse effect on our current growth opportunities.
The largest portion of our anticipated growth and planned capital expenditures are expected to be from properties located in the Atlantic Rim that are covered by the Atlantic Rim EIS. In May 2007, the final Record of Decision for the Atlantic Rim EIS was issued, which allowed us, and other operators in the area, to pursue additionalcoal bed methanedrilling in the Atlantic Rim. That decision was appealed and stays were requested in an attempt to postpone or cancel the commencement of additional drilling in the Atlantic Rim EIS area. In September 2007, the request was denied and in November 2007, United States District Judge Richard J. Leon issued his Order and Memorandum Opinion denying a preliminary injunction to stop the Company’s development efforts in the Atlantic Rim EIS area. It is unknown whether the plaintiffs will continue with the underlying lawsuit pursuant to which the injunction motion was filed, which could ultimately prevent future drilling in this area. We believe our interests in this area hold potential for significant new reserves that we may not be able to replace. If we are unable to pursue our drilling plans in the Atlantic Rim area, we may be required to expend significant financial resources and time to try to find other areas to replace the potential reserves in the Atlantic Rim area, and we can provide no assurances that we will be able to find a suitable replacement, if any. Moreover, we may encounter a number of difficulties when trying to replace the potential inventory of drilling sites currently covered by the Atlantic Rim EIS. See the Risk Factors titled “ — We may be unable to find additional reserves, which would adversely impact our revenues” and “-Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities” discussed herein.
We cannot predict the future price of oil and natural gas and an extended decline in prices could hurt our profitability, financial condition and ability to grow.
Our revenues, profitability and liquidity, future rate of growth and carrying value of our oil and gas properties are heavily dependent upon prevailing prices for natural gas and oil, which can be extremely volatile and in recent years have been depressed by excess total domestic and imported supplies. Prices also are affected by actions of federal, state and local agencies, the United States and foreign governments, international cartels, levels of consumer demand, weather conditions, and the price and availability of alternative fuels. In addition, sales of oil and natural gas are seasonal in nature, leading to substantial differences in cash flow at various times throughout the year. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas. Any substantial or extended decline in the price of oil and/or natural gas would have a material adverse effect on our financial condition and results of operations, including reduced cash flow and borrowing capacity. All of these factors are beyond our control.
We could be adversely impacted by a variety of changes in the oil and gas market which are beyond our control.
The marketability of our oil and gas production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions, changes in supply and changes in demand all could adversely affect our ability to produce and market oil and natural gas. If market factors were to change dramatically, the financial impact could be substantial because we would incur expenses without receiving revenues from the sale of production. The availability of markets is beyond our control.
We may be unable to find additional reserves, which would adversely impact our ability to sustain production levels.
Our future operations depend on whether we find, develop or acquire additional reserves that are economically recoverable. Our properties produce oil and gas at a declining rate. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves, production and revenues will decline over time.
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We may be unable to fund our planned capital expenditures.
We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowing under bank credit facilities, and the issuance of equity. Without adequate financing we may not be able to successfully execute our operating strategy. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include:
| | • | | general economic and financial market conditions; |
| |
| | • | | oil and natural gas prices; and |
| |
| | • | | our market value and operating performance. |
We may be unable to execute our operating strategy if we cannot obtain adequate capital. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program.
New government regulation and environmental risks could increase our cost of doing business.
The production and sale of oil and gas are subject to a variety of federal, state and local government regulations. These include:
| | • | | prevention of waste; |
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| | • | | discharge of materials into the environment; |
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| | • | | conservation of oil and natural gas, pollution, permits for drilling operations, drilling bonds, reports concerning operations; |
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| | • | | spacing of wells; and |
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| | • | | unitization and pooling of properties. |
Many jurisdictions have at various times imposed limitations on the production of oil and gas by restricting the rate of flow for oil and gas wells below their actual capacity to produce. Because current regulations covering our operations are subject to change at any time, and despite our belief that we are in substantial compliance with applicable environmental and other government laws and regulations, we may incur significant costs for compliance in the future.
The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.
The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of loss of investment that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
| | • | | unexpected drilling conditions; |
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| | • | | pressure or irregularities in formations; |
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| | • | | equipment failures or accidents; |
| |
| | • | | adverse changes in prices; |
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| | • | | weather conditions; |
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| | • | | shortages in experienced labor; and |
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| | • | | shortages or delays in the delivery of equipment. |
We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in commercial quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. We cannot predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to:
| | • | | unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks; |
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| | • | | shortages or delays in the availability of drilling rigs and the delivery of equipment; and |
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| | • | | loss of circulation of drilling fluids or other conditions. |
These factors may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or toxic substances.
Our industry experiences numerous operating hazards that could result in substantial losses.
The exploration, development and operation of oil and gas properties also involve a variety of operating risks including the risk of fire, explosions, blowouts, cratering, pipe failure, abnormally pressured formations, natural disasters, acts of terrorism or vandalism, and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. These industry related operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.
We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. Acts of terrorism and certain potential natural disasters may change our ability to obtain adequate insurance coverage. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.
Our prices may be impacted adversely by new taxes.
The federal, state and local governments in which we operate impose taxes on the oil and gas products we sell. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. In addition, many states have raised state taxes on energy sources and additional increases may occur. We cannot predict whether any of these measures would have an adverse impact on oil and natural gas prices.
Our reserves and future net revenues may differ significantly from our estimates.
The estimates of reserves and future net revenues are not exact and are based on many variable and uncertain factors; therefore, the estimates may vary substantially from the actual amounts depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. The actual amounts of production, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and gas reserves to be encountered may vary substantially from the estimated amounts. In addition, estimates of reserves are extremely sensitive to the market prices for oil and gas.
Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities.
We could be subject to significant liabilities related to acquisitions. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records
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may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that our future acquisition activity will not result in disappointing results.
In addition, there is strong competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing or regulatory approvals.
Acquisitions often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies are sometimes greater and their availability may be limited. As a result of increasing levels of exploration and production in response to strong prices of crude oil and natural gas, the demand for oilfield services has risen and the costs of these services has increased.
We do not control all of our operations and development projects.
Certain all of our business activities are conducted through operating agreements under which we own partial interests in oil and natural gas wells.
If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s:
| | • | | timing and amount of capital expenditures; |
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| | • | | expertise and financial resources; |
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| | • | | inclusion of other participants in drilling wells; and |
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| | • | | use of technology. |
Since we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.
Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.
We operate in the highly competitive areas of oil and natural gas exploration, development and production. We face intense competition from both major and other independent oil and natural gas companies in each of the following areas:
| | • | | seeking to acquire desirable producing properties or new leases for future exploration; |
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| | • | | seeking to acquire the equipment and expertise necessary to develop and operate our properties; and |
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| | • | | Retention and hiring of skilled employees. |
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Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment.
We depend on key personnel.
Our success depends to a significant extent upon the efforts and abilities of our senior management and key employees, particularly, Mr. Kurtis Hooley, Chief Financial Officer, Mr. D. Steven Degenfelder, Vice President-Land, and Mr. Robert Reiner, Vice President-Operations. The loss of the services of these individuals could have a material adverse effect upon our business and results of operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against BR and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter ended December 31, 2007.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Common Stock
Market Information.Our Common Stock is currently traded on the NASDAQ Global Select Market under the symbol “DBLE”. Prior to December 15, 2006, and since 1995, our Common Stock traded on the NASDAQ Capital Market under the symbol “DBLE.”
The range of high and low sales prices for our Common Stock for each quarterly period from January 1, 2006 through December 31, 2007, as reported by the NASDAQ Stock Market, is set forth below:
| | | | | | | | | |
| Quarter Ended | | High | | Low |
| December 31, 2007 | | $ | 18.25 | | | $ | 13.13 | |
| September 30, 2007 | | | 18.41 | | | | 13.77 | |
| June 30, 2007 | | | 21.10 | | | | 16.81 | |
| March 31, 2007 | | | 24.86 | | | | 17.59 | |
| | | | | | | | | |
| December 31, 2006 | | $ | 29.50 | | | $ | 18.05 | |
| September 30, 2006 | | | 20.52 | | | | 15.89 | |
| June 30, 2006 | | | 19.40 | | | | 14.04 | |
| March 31, 2006 | | | 20.68 | | | | 15.00 | |
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On March 3, 2008, the closing sales price for the Common Stock as reported by the NASDAQ Global Select Market was $16.85 per share.
Holders. On March 1, 2008, the number of holders of record of our common stock was 1,110.
Dividends. We have not paid or declared any cash dividends on our common stock in the past and do not intend to pay or declare any cash dividends in the foreseeable future. We currently intend to retain future earnings for the future operation and development of our business including exploration, development and acquisition activities. Any future dividends would be subordinate to the full cumulative dividends on all shares of our Series A Preferred Stock.
Equity Compensation Plans.The following table provides information as of December 31, 2007 with respect to shares of common stock that may be issued under our existing equity compensation plans. We have five equity compensation plans—the 1996 Stock Option Plan, the 2000 Stock Option Plan, the 2002 Stock Option Plan, the 2003 Stock Option and Compensation Plan and the 2007 Stock Incentive Plan.
| | | | | | | | | | | | | |
| | | (a) | | | (b) | | | (c) | |
| | | | | | | | | | | Number of | |
| | | | | | | | | | | securities remaining | |
| | | | | | | | | | | available for future | |
| | | Number of | | | Weighted- | | | issuance under | |
| | | securities to be | | | average | | | equity | |
| | | issued upon | | | exercise price | | | compensation | |
| | | exercise of | | | of | | | plans (excluding | |
| | | outstanding | | | outstanding | | | securities reflected | |
| Plan category | | options | | | options | | | in column (a)) | |
| Equity Compensation plans approved by security holders | | | 263,500 | | | $ | 17.71 | | | | 772,614 | (1) |
| | | | | | | | | | |
| | |
| (1) | | Represents no shares available for issuance under the 1996 Stock Option Plan, no shares available for issuance under the 2000 Stock Option Plan, 130,971 shares available for issuance under the 2002 Stock Option Plan, 141,643 shares available for issuance under the 2003 Stock Option and Compensation Plan and 500,000 shares available for issuance under the 2007 Stock Incentive Plan. |
Recent Sales of Unregistered Securities.Since the filing of our quarterly report on Form 10-Q for the third quarter of 2007, and as reported in Form 8-K filed with the Securities and Exchange Commission on January 17, 2008, restricted stock awards have been made under the 2007 Stock Incentive Plan totaling 2,090 shares of the Company’s Common Stock and grants of stock options to purchase an aggregate of 55,000 shares have been made under the Company’s 2002 Stock Option Plan. These options are exercisable at $14.36 per share, 20% of the options vest on each of the first, second, third, fourth and fifth anniversary of the grant and the options expire on July 15, 2013. Additionally, restricted stock awards totaling 1,132 shares of the Company’s Common Stock, under the 2007 Stock Incentive Plan, were made on January 29, 2008. The shares vest on each of the first, second and third anniversary of the grant.
The shares of common stock and options described above were granted based on exemptions from registration under the Securities Act of 1933, as amended (the “Securities Act”), and applicable state laws pursuant to Section 4(2) of the Securities Act and Rule 506 of Regulation D. These issuances qualified for exemption from registration because (i) the Company did not engage in any general solicitation or advertising to market the securities; (ii) all the Company’s reports filed under the Securities Exchange Act of 1934 were made available to the recipients; (iii) each recipient was provided the opportunity to ask questions and receive answers from the Company regarding the offering; (iv) the securities were issued to persons with knowledge and experience in financial and business matters so that he or she is capable of evaluating the merits and risks of an investment in the Company; and (v) the recipients received “restricted securities” that include a restrictive legend on the certificate.
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Performance Graph
Comparison of Five-Year Cumulative Total Return Among
Double Eagle Petroleum Co., the NASDAQ U.S. Index and the Peer Group Index
Total Return (Stock Price Plus Reinvested Dividends)
The total return assumes that dividends were reinvested quarterly and is based on a $100 investment on December 31, 2001. During the five year period ended December 31, 2007, Double Eagle’s common stock cumulative annual growth rate was 23.5%, compared to 14.6% for the NASDAQ U.S. Index and 29.6% for our Peer Group.
The Peer Group Index is comprised of the following companies, which are selected by Company management: Abraxas Petroleum Corp., American Oil & Gas, Aurora Oil & Gas Corp., Brigham Exploration Co., Contango Oil & Gas Company, Credo Petroleum Corp., Dune Energy Inc., Exploration Co. of Delaware Inc., FX Energy Inc., Gasco Energy Inc., GMX Resources Inc., Quest Resource Corp., and Teton Energy Corp.
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Series A Cumulative Preferred Stock
Market Information.Our Series A Cumulative Preferred Stock (“Series A Preferred Stock”) is currently traded on the NASDAQ Global Select Market under the symbol “DBLEP”. Our Series A Preferred Stock was issued and began trading on July 3, 2007.
The range of high and low sales prices for our Series A Preferred Stock for each quarterly periods beginning September 30, 2007 through December 31, 2007, as reported by the NASDAQ Stock Market, is set forth below:
| | | | | | | | | |
| Quarter Ended | | High | | Low |
| December 31, 2007 | | $ | 26.95 | | | $ | 24.50 | |
| September 30, 2007 | | | 28.25 | | | | 23.56 | |
On March 1, 2008, the closing sales price for the Series A Preferred Stock as reported by the NASDAQ Global Select Market was $25.05 per share.
Holders. All shares of the Series A Preferred Stock are held at the Depository Trust Company
Dividends. Holders of Series A Preferred Stock will be entitled to receive, when and as declared by the board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends on the Series A Preferred at a rate of 9.25% per annum of the $25.00 liquidation preference (equal to $2.3125 per annum per share).
Redemption Provisions.The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change of Ownership or Control. Except pursuant to the special redemption upon a Change of Ownership or Control, we may not redeem the Series A Preferred Stock prior to June 30, 2012. On and after June 30, 2012, we may redeem the Series A Preferred Stock for cash at our option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” we will be required to redeem the Series A Preferred Stock within 90 days after the date on which the Change of Ownership or Control occurred for cash, at the following price per share, plus accrued and unpaid dividends.
| | | |
| Redemption Date on or | | |
| Before | | Redemption Price |
| June 30, 2008 | | $26.00 |
| June 30, 2009 | | $25.75 |
| June 30, 2010 | �� | $25.50 |
| June 30, 2011 | | $25.25 |
| June 30, 2012 or thereafter | | $25.00 |
Liquidation Preference.In the event of a liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of our common stock.
Voting Rights.Holders of the Series A Preferred Stock will generally have no voting rights. However, if cash dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or non-consecutive quarterly dividend periods, or if we fail to maintain a national market listing, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on our board of directors in addition to those directors then serving on our board until such time as the national market listing is obtained or the dividend arrearage is eliminated.
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ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2007 | | 2006 | | 2005 | | 2004 | | 2003 |
| | | (In thousands, except per share and volume data) |
Statement of Operations Information | | | | | | | | | | | | | | | | | | | | |
| Total operating revenues | | $ | 17,197 | | | $ | 19,032 | | | $ | 20,496 | | | $ | 13,267 | | | $ | 6,138 | |
| Income (loss) from operations | | $ | (17,909 | ) | | $ | 3,695 | | | $ | 5,985 | | | $ | 4,451 | | | $ | 1,136 | |
| Net income (loss) | | $ | (11,603 | ) | | $ | 2,109 | | | $ | 3,965 | | | $ | 4,028 | | | $ | 972 | |
| Net income (loss) attributable to common stock | | $ | (13,413 | ) | | $ | 2,109 | | | $ | 3,965 | | | $ | 4,028 | | | $ | 972 | |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | | | $ | 0.48 | | | $ | 0.14 | |
| Diluted | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | | | $ | 0.47 | | | $ | 0.14 | |
| | | | | | | | | | | | | | | | | | | | | |
Balance Sheet Information | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 84,597 | | | $ | 64,406 | | | $ | 44,211 | | | $ | 30,969 | | | $ | 23,955 | |
| Line of credit | | $ | 3,445 | | | $ | 13,221 | | | $ | 3,000 | | | $ | — | | | $ | — | |
| Total long-term liabilities | | $ | 5,895 | | | $ | 17,184 | | | $ | 5,732 | | | $ | 583 | | | $ | 359 | |
| Stockholders’ equity | | $ | 28,624 | | | $ | 33,042 | | | $ | 29,778 | | | $ | 24,927 | | | $ | 19,856 | |
| | | | | | | | | | | | | | | | | | | | | |
Cash Flow Information | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 5,166 | | | $ | 10,951 | | | $ | 10,319 | | | $ | 7,434 | | | $ | 3,239 | |
| Investing activities | | $ | (42,056 | ) | | $ | (22,241 | ) | | $ | (16,259 | ) | | $ | (7,377 | ) | | $ | (8,769 | ) |
| Financing activities | | $ | 36,404 | | | $ | 10,470 | | | $ | 3,701 | | | $ | 692 | | | $ | 8,318 | |
| | | | | | | | | | | | | | | | | | | | | |
Total proved reserves | | | | | | | | | | | | | | | | | | | | |
| Oil (MBbl) | | | 413 | | | | 360 | | | | 329 | | | | 278 | | | | 209 | |
| Gas (MMcf) | | | 71,254 | | | | 48,497 | | | | 47,234 | | | | 34,935 | | | | 22,819 | |
| MMcfe | | | 73,731 | | | | 50,657 | | | | 49,207 | | | | 36,603 | | | | 24,073 | |
| | | | | | | | | | | | | | | | | | | | | |
Net production volumes | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | | 13,963 | | | | 12,729 | | | | 15,470 | | | | 16,886 | | | | 17,344 | |
| Gas (Mcf) | | | 2,928,335 | | | | 3,140,653 | | | | 2,976,094 | | | | 2,559,557 | | | | 1,320,850 | |
| Mcfe | | | 3,012,113 | | | | 3,217,027 | | | | 3,068,914 | | | | 2,660,873 | | | | 1,424,914 | |
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Amounts in thousands of dollars, except share, per share data, and amounts per unit of production)
The following discussion includes forward-looking statements. Such statements are described in the section entitled “Forward-Looking Statements” on page 16 of this Form 10-K.
BUSINESS OVERVIEW
We are an independent energy company engaged in the exploration, development, production and sales of natural gas and crude oil, primarily in the Rocky Mountain Basins of the western United States. Our principal properties are located in southwestern Wyoming. We have coal bed methane reserves and production in the Atlantic Rim Area of the Eastern Washakie Basin and tight gas reserves and production in the Pinedale Anticline. Our current exploration activities involve properties in southwestern Wyoming, Nevada and Utah.
As of December 31, 2007, we had estimated proved reserves of 71.3 Bcf of natural gas and 413 MBbl of oil, or a total of 73.7 Bcfe, with a PV-10 value of approximately $182.6 (see reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under the heading Reserves on page 9). As of December 31, 2007, we controlled approximately 255,786 net undeveloped acres, representing approximately 96% of our total net acreage position.
We intend to increase our reserves, production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas development and enhancement of field facilities on operated and non-operated properties in the Atlantic Rim; and (ii) continued participation in the development of the Mesa Field on the Pinedale Anticline. We also may pursue selective high potential, low to medium risk, exploration projects where we have accumulated detailed geological knowledge and strategic acquisitions that may expand or complement our existing operations.
We account for gas imbalances under the entitlement method, whereby a working interest owner records revenue based on its share of entitled production, which is not always the amount of production the owner receives from month to month. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while an under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position at December 31, 2006 resulted in an imbalance receivable of 253 MMcf, or $735, and an imbalance payable of 52 MMcf, or $233. We began recouping our under-taken production relating to the Sun Dog and Doty Mountain Units on August 1, 2007 and believe we will make up the entire balance (or a significant portion thereof) in 2008. An actual realized price above the amount initially recorded will be recorded as additional revenues at that time. The under-produced owner controls when the amounts are recouped, so we cannot predict when the payable will be liquidated.
Developments since December 31, 2006:
Fiscal year 2007 was a year spent investing in our future, both in terms of the development of our operated and non-operated properties in the Atlantic Rim and our continued participation in the development of the Pinedale Anticline.
We participated in an active oil and gas development program within our core areas in 2007, including the following:
| | • | | At the Atlantic Rim, we received the Final Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”) on May 21, 2007, which allows for the drilling of up to 1,800 coal-bed methane wells and 200 conventional oil and gas wells in the Atlantic Rim Area (for further information regarding the EIS, see continued discussion, within this section, below). During the fourth quarter of 2007, we drilled 33 wells in the Catalina Unit, of which six were completed and producing by December 31, 2007. We expect to have the remaining wells completed and producing by the end of the first quarter 2008. The new wells established production levels specified by the Unit Operating Agreement on December 21, 2007, which triggered the formation of the Catalina Unit PA, bringing Double Eagle’s working interest in the new wells and in the 14 existing producing wells in the Cow Creek Field to 73.84%. At the Doty Mountain Unit, in which Double Eagle has 20.55% working interest, we began receiving and selling our share of production in July 2006. We are in an under-produced position for prior year’s production and began taking our gas in-kind and receiving make-up gas on August 1, 2007. See Item 15, Note 1 in the Notes to the Consolidated Financial Statements for additional discussion of production imbalances. Also within the Atlantic Rim, we are participating in the drilling of 52 additional wells within the Sun Dog Unit. Double Eagle currently has a 4.55% working interest |
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| | | | in the Unit, which will change to an estimated 8.4% working interest once the new wells are drilled. It is expected that these wells will be drilled and completed by March 2008. We are currently in an under-produced position for prior and current years’ production (through July 31, 2007) at the Sun Dog Unit and began receiving our share of current production and make up gas on August 1, 2007. See Item 15, Note 1 in the Notes to the Consolidated Financial Statements for additional discussion of production imbalances. |
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| | • | | At the Pinedale Anticline, we participated in the drilling of 18 additional wells. These wells have been drilled and are expected to be completed at a rate of three wells in April and five wells per month in each of May, June and July of 2008. |
| |
| | • | | In the Wind River Basin, we began drilling the Waltman 34-24 well on December 1, 2007. This well is a 40 acre offset to the Chevron Waltman 96 well that has been producing since early 2007. Gas shows at commercially feasible levels have been seen. Management expects the well to be completed sometime during the second quarter of 2008. |
| |
| | • | | On the Moxa Arch, we participated in the drilling of 71 development wells in 2007, with working interests ranging from 0.11% to 16.27% in 2007. |
On May 21, 2007, the Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”), which allows for the drilling of up to 1,800 coal-bed methane wells and 200 conventional oil and gas wells in the Atlantic Rim area, was published in the Federal Register, allowing Double Eagle to begin its developmental drilling program of up to 268 wells in the Catalina Unit. During June 2007, we were informed by the U.S. Bureau of Land Management (“BLM”) that three separate coalitions of conservation groups appealed, or were in the process of appealing, the approval of the EIS, and requested a stay of Double Eagle’s and others’ activities pending the Internal Board of Land Appeals (“IBLA”) determination of the appeals. We agreed to delay our plans to drill until August 6, 2007. At that time we began construction in preparation for drilling and commenced drilling on August 15, 2007. On September 5, 2007, the IBLA issued an Order denying the request for a stay of Double Eagle’s and others’ activity in the Atlantic Rim pending the determination of the appeals previously filed. On November 30, 2007, United States District Judge Richard J. Leon issued his Order and Memorandum Opinion denying a requested preliminary injunction to stop work at the Company’s Atlantic Rim Coal Bed natural gas project in south central Wyoming and as a result, we have been able to continue with our development in the Atlantic Rim.
Through unitization, we acquired an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the Lost Cabin Gas Processing Plant in late 2006, at a cost of approximately $2.5 million. The Madden Sour Gas Participating Area produced 10 Mcf net to our interest of gas in December 2007 from seven wells. These are long-lived wells with large producing rates and reserves. We have a 0.349% working interest in the deep participating area.
The Company has not been paid any of the proceeds generated by the sale of gas produced from the Madden Deep Unit over the period beginning with the effective date of the Unit participating area (February 1, 2002) through June 30, 2007. Double Eagle began receiving payments for its share of the sales related to current production on July 1, 2007. The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against BR and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the gas produced from the Madden Deep Unit over at least the period from February 1, 2002 through June 30, 2007. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis.
In addition to development of our existing properties, we were involved with the following exploratory projects during 2007:
| | • | | We participated in the drilling of the Straight Flush 17-1 well in Huntington Valley, Nevada during the third quarter of 2007. Double Eagle had a 97.3% working interest in the well. No commercial deposits of oil and gas were identified and the well was plugged in October 2007. Costs incurred through December 31, 2007 of $1,983 were charged to dry hole costs. |
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| | • | | At Christmas Meadows, we started the drilling of the Table Top Unit #1 well on September 8, 2006 at 235 feet, at the base of the conductor pipe that was set in the summer of 2006. On February 26, 2007 the Table Top Unit #1 well at the Christmas Meadows Prospect reached a depth of 15,760 feet and it was plugged back to a depth of 11,393 feet. The Table Top Unit #1 well did not find reservoir rocks with sufficient permeability in the Cretaceous formation and operations were suspended to assess alternative approaches to completing the project. The Table Top Unit as originally formed was dissolved and having met the obligations for the Unit test well, the Main Fork Unit was formed and timing extended until at least April 2009. The Company is in the process of evaluating potential alternatives, including drilling or farming out the drilling of the Table Top Unit #1. FASB Staff Position FAS 19-1 (“FSP 19-1”) requires management to assess continued capitalization of exploratory projects capitalized for a period greater than one year to determine whether or not it is appropriate to continue capitalization of the costs. Based on the guidance included in FSP 19-1, $5,773 of capitalized costs associated with the Table Top Unit #1 were expensed. For further information regarding FSP 19-1, see continued discussion, within this section, below. |
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| | • | | We began drilling the Cow Creek Unit Deep #2 well (a combination exploratory and development well) on June 1, 2006, with an expected total depth of 12,360 feet. The well was drilled, in 2006, to a depth of 9,922 feet and casing was run to that point. Double Eagle has an 84% interest in this well. We are currently evaluating our options with this well which may include drilling the well deeper than its current depth or using it as a water injection well. The well is treated as two wells for accounting purposes. The costs incurred to drill to the Mesaverde formation, a proved area known to be productive, are treated as developmental costs, while the costs incurred to drill beyond the Mesaverde formation are treated as exploratory costs. We are currently evaluating the operational opportunities available for this well, however, due to the passage of time since this project was temporarily abandoned, and the current lack of firm plans regarding the future of this well, FSP 19-1 requires the exploratory portion of this well to be expensed, which resulted in $4,395 being expensed during the quarter ended September 30, 2007. The remaining capitalized costs represent the developmental portion of the well and these costs will remain capitalized. For further information regarding FSP 19-1, see continued discussion, within this section, below. |
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| | • | | The PH State 16-1 (South Fillmore) well was completed during the third quarter of 2006. The PH State 16-1 was completed in the Mesaverde Sand and Coal formations. In July 2007, GMT Exploration Company LLC drilled the SJ Fee 11-9 well, in which the Company has a 50% working interest before payout and a 30% working interest after payout, one mile northwest of the PH State 16-1 well. The SJ Fee 11-9 well has been completed in the Mesaverde Sand interval and commercial gas sales are expected to begin early in 2008. Due to the proximity of the PH State 16-1 well to the SJ Fee 11-9 well, which is expected to have commercially viable production, the Company is currently evaluating the project to determine if the PH State 16-1 well can be recompleted as a producer from the sand formation and if the Company will potentially drill or participate in the drilling of additional wells in this area. However, due to the passage of time, and as required by FSP 19-1, the Company expensed $2,759 of capitalized costs relating to the PH State 16-1 well during the quarter ended December 31, 2007. For further information regarding FSP 19-1, see continued discussion, within this section, below. |
FASB Staff Position FAS 19-1 (FSP 19-1), Accounting for Suspended Well Costs, was effective for the first reporting period beginning after April 4, 2005. FSP 19-1 concludes that, for companies using the successful efforts method of accounting, exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the well. FSP 19-1 specifies that the costs of drilling an exploratory well shall not be carried as an asset for a period greater than one year from completion of drilling (or abandonment of a project), unless it can be shown that sufficient progress (as defined) has been made in assessing the economic and operational viability of a project. Since adopting FSP 19-1, the Company continually evaluates all existing capitalized exploratory well costs.
On January 23, 2007, pursuant to our universal shelf registration statement on Form S-3, we completed a follow-on public offering of 500,000 shares of Common Stock at a price to the public of $21.55 per share. Proceeds from the offering were approximately $10 million, including the underwriter’s exercise of its over-allotment option, after deducting the underwriting discounts and commissions and offering expenses. The net proceeds from this offering were used to pay down the outstanding indebtedness on our revolving line of credit.
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On July 5, 2007, pursuant to the universal shelf registration statement on Form S-3 described above, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share. Net proceeds from the offering were approximately $38 million, after deducting underwriter discounts and offering expenses. A portion of the net proceeds from this offering was used to pay off the outstanding indebtedness on the Company’s revolving line of credit of approximately $17 million. The remaining proceeds were invested in short term investment accounts and were used to fund the drilling of the additional 33 wells in the Catalina Unit during the second half of 2007.
On August 21, 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (“Rights Plan”). Under the Rights Plan, the Company issued a dividend of one Preferred Share Purchase Right for each outstanding share of common stock held by stockholders of record on September 4, 2007. The Rights Plan is intended to safeguard against abusive takeover tactics that limit the ability of all shareholders to realize the long-term value of their investment in Double Eagle. The Rights Plan was not adopted in response to any specific takeover effort, and will not prevent a takeover, but should encourage anyone seeking to acquire Double Eagle to negotiate with the Board prior to attempting a takeover. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for additional discussion the Rights Plan adopted by the Company’s Board of Directors.
Our Industry:
The exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil is highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for stockholders. Generating reserve and production growth while containing costs represents an ongoing focus for management, and is made particularly important in our business by the natural production and reserve decline associated with oil and gas properties. In addition to developing new reserves, we compete to acquire additional reserves, which involve judgments regarding recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. During periods of historically high oil and gas prices, third party contractor and material cost increases are more prevalent due to increased competition for goods and services. Other challenges we face include attracting and retaining qualified personnel, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.
We have taken the following steps to mitigate the challenges we face:
| | • | | We attempt to reduce our overall exposure to commodity price fluctuations through the use of various fixed delivery contracts for some of our production. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts may limit the risk of fluctuating cash flows. As of December 31, 2007, we had sales delivery contracts in effect for approximately 64% of our current daily production. |
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| | • | | We have an inventory of attractive drilling locations, allowing us to grow reserves and replace and expand production organically without having to rely solely on acquisitions. Drilling opportunities in both the Atlantic Rim and the Pinedale Anticline are expected to last for several years. |
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| | • | | The Company completed public offerings (pursuant to our universal shelf registration statement on Form S-3 filed with the Securities and Exchange Commission, declared effective on December 15, 2006) of 500,000 shares of Common Stock and 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock on January 23, 2007 and July 5, 2007, respectively. The universal shelf on Form S-3 now permits, but does not obligate, Double Eagle to sell, in one or more public offerings, shares of newly issued common stock, shares of newly issued preferred stock, warrants, stock purchase contracts, stock purchase units or debt securities, or any combination of such securities, for proceeds in an aggregate amount of up to $200 million ($150 million remaining as of December 31, 2007). The terms of future offerings, if any, under the shelf registration will be determined at the time of the offering and will be stated in a prospectus supplement. |
Development Outlook for 2008:
We enter into 2008 with an anticipated exploration and development budget between $40-$60 million, as compared to $50 million for 2007 expenditures. We believe that we have the necessary capital, personnel and available drilling equipment to successfully execute this program. The drilling activity provided for in the 2008 capital budget is primarily allocated to the projects below.
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Atlantic Rim.We intend to continue our development of the Catalina Unit by drilling a minimum of 24 wells up to a maximum of 48 wells beginning in July 2008, when wildlife stipulations allow. The number and specific locations of the wells to be drilled is dependent upon the availability of financing, availability of drilling equipment and contractors and restrictions on drilling activities as set forth by applicable wildlife stipulations. Total gross capital expenditures are estimated at approximately $1.1 million per well, including infrastructure costs. Depending on the locations selected for drilling the additional wells, Double Eagle’s working interest in the Catalina Unit will change to a percentage that could vary from 68.34% to 51.23%. Within the Doty Mountain Unit, we have been notified by the operator, Anadarko Petroleum that it plans to drill an additional 55 wells in 2008. Once the wells are drilled it would change Double Eagle’s working interest in the Doty Mountain Unit to an estimated 12.0%. Anadarko Petroleum, the operator of the Sun Dog Unit, also has informed us of its plans to drill an additional 68 wells in the Sun Dog Unit in 2008, bringing Double Eagle’s working interest (once the wells are drilled) to an estimated 7.9%.
Pinedale Anticline.At the Pinedale Anticline, the operator has informed us of its intentions to hook up the 18 wells drilled in 2007 and completed in 2008 at a rate of three wells in April and five wells per month in each of May, June and July of 2008, with an additional 16 wells scheduled to be drilled in the summer of 2008.
Other.Management will evaluate, on an ongoing basis, the drilling/testing at our existing exploratory projects; Christmas Meadows, Cow Creek Unit Deep #2 and South Fillmore, as wells as additional development drilling projects during 2008.
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RESULTS OF OPERATIONS
The table below provides a year-to-year overview of selected reserve, production and financial information. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.
| | | | | | | | | | | | | | | | | | | | | |
| | | As of, and for the year ended, December 31, | | | Percent change between years | |
| | | 2007 | | | 2006 | | | 2005 | | | 2006 to 2007 | | | 2005 to 2006 | |
| Excluding Imbalance Activity: | | | | | | | | | | | | | | | | | | | | |
Net production volumes | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | | 13,963 | | | | 12,729 | | | | 15,470 | | | | 10 | % | | | -18 | % |
| Gas (Mcf) | | | 2,971,122 | | | | 2,894,894 | | | | 2,976,094 | | | | 3 | % | | | -3 | % |
| Mcfe | | | 3,054,900 | | | | 2,971,268 | | | | 3,068,914 | | | | 3 | % | | | -3 | % |
| | | | | | | | | | | | | | | | | | | | | |
Average daily production | | | | | | | | | | | | | | | | | | | | |
| Mcfe | | | 8,370 | | | | 8,140 | | | | 8,408 | | | | 3 | % | | | -3 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Including Imbalance Activity: | | | | | | | | | | | | | | | | | | | | |
Net production volumes | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | | 13,963 | | | | 12,729 | | | | 15,470 | | | | 10 | % | | | -18 | % |
| Gas (Mcf) | | | 2,928,335 | | | | 3,140,653 | | | | 2,976,094 | | | | -7 | % | | | 6 | % |
| Mcfe | | | 3,012,113 | | | | 3,217,027 | | | | 3,068,914 | | | | -6 | % | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | | |
Average daily production | | | | | | | | | | | | | | | | | | | | |
| Mcfe | | | 8,252 | | | | 8,814 | | | | 8,408 | | | | -6 | % | | | 5 | % |
| | | | | | | | | | | | | | | | | | | | | |
Average price per unit production | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | $ | 63.17 | | | $ | 57.90 | | | $ | 49.26 | | | | 9 | % | | | 18 | % |
| Gas (Mcf) | | $ | 5.18 | | | $ | 5.57 | | | $ | 6.62 | | | | -7 | % | | | -16 | % |
| Mcfe | | $ | 5.33 | | | $ | 5.67 | | | $ | 6.66 | | | | -6 | % | | | -15 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Including price risk management activities | | | | | | | | | | | | | | | | | | | | |
Oil and gas production revenues | | | | | | | | | | | | | | | | | | | | |
| Oil revenues | | $ | 882 | | | $ | 737 | | | $ | 762 | | | | 20 | % | | | -3 | % |
| Gas revenues | | | 15,162 | | | | 17,491 | | | | 19,689 | | | | -13 | % | | | -11 | % |
| | | | | | | | | | | | | | | | | | |
| Total | | $ | 16,044 | | | $ | 18,228 | | | $ | 20,451 | | | | -12 | % | | | -11 | % |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Oil and gas production costs | | | | | | | | | | | | | | | | | | | | |
| Production costs | | $ | 5,696 | | | $ | 3,560 | | | $ | 3,800 | | | | 60 | % | | | -6 | % |
| Production taxes | | | 1,933 | | | | 2,209 | | | | 2,523 | | | | -12 | % | | | -12 | % |
| | | | | | | | | | | | | | | | | | |
| Total | | $ | 7,629 | | | $ | 5,769 | | | $ | 6,323 | | | | 32 | % | | | -9 | % |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Data on a per Mcfe basis | | | | | | | | | | | | | | | | | | | | |
| Average price | | $ | 5.33 | | | $ | 5.67 | | | $ | 6.66 | | | | -6 | % | | | -15 | % |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Production costs, excluding pipeline | | | 1.89 | | | | 1.11 | | | | 1.24 | | | | 71 | % | | | -11 | % |
| Production taxes | | | 0.64 | | | | 0.69 | | | | 0.82 | | | | -7 | % | | | -16 | % |
| Depletion and amortization | | | 1.51 | | | | 1.29 | | | | 1.17 | | | | 17 | % | | | 10 | % |
| | | | | | | | | | | | | | | | | | |
| Total operating costs | | | 4.04 | | | | 3.09 | | | | 3.23 | | | | 31 | % | | | -4 | % |
| | | | | | | | | | | | | | | | | | |
| Gross margin | | $ | 1.29 | | | $ | 2.58 | | | $ | 3.43 | | | | -50 | % | | | -25 | % |
| | | | | | | | | | | | | | | | | | |
| Gross margin percentage | | | 24 | % | | | 46 | % | | | 52 | % | | | | | | | | |
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Year ended December 31, 2007 compared to the year ended December 31, 2006
Oil and gas sales volume and price comparisons
During the year ended December 31, 2007, oil and gas sales (including the effect of price risk management activities) decreased 12% to $16,044, and total production decreased approximately 6%, when compared to the prior year. The decrease in oil and gas sales was driven by a decrease in total production and lower average gas prices. Unusually high prices in 2006, higher than normal fall and early winter temperatures across the country and several pipeline closures and shut-ins of storage facilities in 2007 were the primary contributing factors to the overall price decrease. The 6% decrease in total gas production as compared to the prior year is primarily attributable to decreased production in the Atlantic Rim and Pinedale Anticline, offset by increased production at the Madden Deep Unit.
During the year ended December 31, 2007, average daily production at the Atlantic Rim decreased 12% to 4,678 Mcfe as compared to 5,289 Mcfe during the same prior year period due to decreases in all three Atlantic Rim Units. During the year ended December 31, 2007, average daily production at the Catalina Unit decreased 8% to 4,068 Mcfe, as compared to 4,431 Mcfe during the same prior year period. The decrease in production at the Catalina Unit is due to operational issues caused by severe winter weather, which resulted in unscheduled workovers during the first half of 2007 and to electrical and compression problems experienced during the fourth quarter of 2007. We drilled 33 potential producing wells in the Catalina Unit in 2007 with six completed and in production by December 31, 2007. When these six wells reached the required production levels, the Catalina Unit was formed bringing our interest in the Unit to 73.84% effective December 21, 2007. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) as a percentage of the entire acreage of the PA. This PA and the associate working interest will change as more wells and acreage are added to the PA. We expect production levels to increase as the remaining wells are completed and connected to the sales line in the first quarter of 2008. Average daily production at the Doty Mountain and Sun Dog Units decreased 29% to 610 Mcfe, as compared to 858 Mcfe during the same prior year period. The decrease is due largely to the initial recording of gas imbalances during 2006. Currently, we are in an under-produced position for prior year’s production at the Doty Mountain Unit and began receiving make up gas on August 1, 2007. We are also in an under-produced position for prior and current year’s production at the Sun Dog Unit and began receiving our share of current production and make up gas on August 1, 2007.
During the year ended December 31, 2007, average daily production in the Pinedale Anticline decreased 17% to 2,166 Mcfe, as compared to 2,597 Mcfe in the prior year. The Mesa Units’ decrease is the result of shut-in production by the operator during portions of the third and fourth quarters of 2007 due to low natural gas prices, as well as normal production declines, offset somewhat by new wells that came on-line during the third quarter of 2007. In 2007, we participated in the drilling of 18 wells at the Pinedale Anticline. The operator at the Mesa Units has informed us that it intends to complete the 18 wells at a rate of three in April and five per month in each of May, June and July of 2008.
During the year ended December 31, 2007, average daily production at Madden Deep increased to 502 Mcfe as compared to 108 Mcfe in the prior year. We began recognizing production from Madden Deep during the fourth quarter of 2006.
Transportation revenue
During the year ended December 31, 2007, we recorded $910 in transportation revenue, as compared to $523 during the prior year. Transportation revenue is recognized for moving third party gas through our intrastate gas pipeline, which was constructed in late 2005 and connects the Cow Creek Field with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The increase in transportation revenue over the prior year is attributable to the fact that revenues for 2006 are for the period June to December 2006. With additional compression, the pipeline is expected to have a 100 MMcf per day capacity, which is expected to be sufficient to handle the development of the Catalina Unit.
Oil and gas production expenses, depreciation, depletion and amortization
During the year ended December 31, 2007, well production costs increased 60% to $5,696, as compared to $3,560 during the prior year, and production costs in dollars per Mcfe increased 71%, or $0.78, to $1.89, as compared to the same prior year period. The increase in production costs is largely attributed to an increase in transportation, lease operating and workover expenses in the Atlantic Rim and gas purchase expense of $230, which was incurred to purchase volumes to
35
fulfill the fixed delivery contracts at our Catalina Unit. Transportation expenses increased by $343 at the Doty Mountain and Sun Dog Units which began producing during the second half of 2005, while lease operating expenses and workover expenses increased by $305 and $659 respectively due largely to the severe winter weather and related operational issues encountered at the Catalina Unit and to a lesser extent the Doty Mountain Unit. In addition, the Company recorded $267 of bad debts related to our drilling activities during 2007. Refer to Item 15 Note 1 to the Notes to the Consolidated Financial Statements for further discussion of this matter.
During the year ended December 31, 2007, total depreciation, depletion and amortization expenses increased 3% to $5,068, as compared to $4,909 in the prior year, and depletion and amortization related to producing assets increased 9% to $4,550, as compared to $4,163 in the prior year. The increase is due primarily to increased capital expenditures at the Atlantic Rim and the Pinedale Anticline. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 17%, or $0.22, to $1.51, as compared to the prior year.
Dry hole and impairment
During 2007, it was determined that the exploratory costs related to the Cow Creek Unit Deep #2 ($4,395), the PH State 16-1 ($2,759), The Christmas Meadows Table Top Unit #1 ($5,773) and the Straight Flush 17-1 ($1,983) did not meet the requirements for continued capitalization as exploratory wells. The associated costs of these projects were expensed in the December 31, 2007 consolidated financial statements.
In addition the Company recognized non-cash charges related to the Mad #1 ($1,351), the State 1-36 ($693) and other properties ($97) and $91 on undeveloped leaseholds.
General and administrative
During the year ended December 31, 2007, general and administrative expenses increased 4% to $4,133 as compared to $3,959 in the prior year. The increase was due largely to an increase in professional fees, including legal fees ($105), audit and tax fees ($88), as well as an increase in salaries and employer contributions to the Company’s Simplified Employee Pension plan ($163) and to an increase in Director’s fees ($54). These increases were offset slightly by a decrease in employee stock option expense as a result of pre-vesting forfeitures of option grants of $99 and a decrease in consulting fees of $186 related largely to the early stages of the Company’s Sarbanes Oxley implementation. The remaining variances in general and administrative expenses over the prior year considered immaterial for further discussion.
Income taxes
During the year ended December 31, 2007, we recorded an income tax benefit of $6,143, as compared to an income tax expense of $1,399 during the prior year. Our income tax benefit reflects an effective book rate of 34.6% in 2007. The lower than expected effective book rate reflects the Company’s net loss for the period ended December 31, 2007 and the tax effect of the permanent difference caused by the stock option expense related to the adoption of SFAS 123(R) not being deductible for income tax purposes. We expect to continue to generate losses for federal income tax reporting purposes, and anticipate net income from operations, in accordance with U.S. generally accepted accounting principals, in future years. The Company’s historical income from operations and current year net loss has resulted in a deferred tax position required under generally accepted accounting principles. We do not anticipate any required payments for current tax liabilities in the near future. We have a net operating loss carry-forward (“NOL’s”) of $30.7 million at December 31, 2007. The Company has evaluated the need to provide a valuation allowance on the amount recorded as the net operating loss carry-forward. Based upon future operational projections and the timeframe in which the NOL’s expire, management believes that no valuation allowance is required as of December 31, 2007.
Year ended December 31, 2006 compared to the year ended December 31, 2005
Oil and gas sales volume and price comparisons
During the year ended December 31, 2006, oil and gas sales decreased 11% to $18,228, and total gas production increased approximately 6%, when compared to the prior year. The decrease in oil and gas sales was driven by lower gas prices, resulting primarily from the unusually high prices of 2005, due to the heavy hurricane season in the Gulf, and unusually high storage volumes late in 2006, due to higher than normal fall and early winter temperatures across the country. We should also note that our actual average price per Mcfe received for 2006 was $5.85 if we exclude the net gas imbalance activity. The increase in total gas production is primarily attributable to the recording of 245,759 Mcfe of net gas imbalances due us somewhat offset by lower production at Mesa and Cow Creek. Mesa production
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decreased 14.8% to a net average daily production of 2,556 Mcfe, as compared to 3,000 Mcfe per day in the prior year. While the Mesa decreases are the result of normal production declines, the operator at Mesa has informed us that it intends to continue new drilling projects in 2007 to better maintain or increase production levels. Seven wells began producing in the fourth quarter of 2006, and, currently, seven additional wells are awaiting hook-up at Mesa (three in Mesa Unit A, two in Mesa Unit B and two in Mesa Unit C). Average net daily production at Cow Creek decreased by 1.8% to 4,431 Mcfe, due primarily to workovers completed during the first and fourth quarters. The decreased production at Mesa and Cow Creek was partially offset by increased production at our other properties, which made up approximately 14.2% of our production (net of imbalance activity) during the year ended December 31, 2006. Average daily production volumes at our other properties increased by 34.4% to 1,156 Mcfe, due largely to the receipt of initial revenues from Doty Mountain production beginning in the third quarter of 2006 and the recording of the gas imbalances due us from past production at Doty Mountain and Sun Dog Units.
Transportation revenue
During the year ended December 31, 2006, we recorded $523 in transportation revenue for moving third party gas through our intrastate gas pipeline, which was constructed in late 2005 and connects the Cow Creek Field with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. With additional compression, the pipeline is expected to have a 100 MMcf per day capacity, which is enough to handle the development of the Catalina Unit.
Oil and gas production expenses, depreciation, depletion and amortization
During the year ended December 31, 2006, well production costs decreased 6% to $3,560, as compared to $3,800 during the prior year, and production costs in dollars per Mcfe decreased 10%, or $0.13, to $1.11, as compared to the same prior year period. The production cost per Mcfe decrease is largely attributed to receiving our first revenues from Doty Mountain production in 2006 and to significant Cow Creek workovers in early 2005, as well as the elimination of third party transportation costs at Cow Creek in 2006 due to implementation of our new pipeline. Production taxes remained relatively constant from year-to-year at slightly higher than 12% of revenues.
During the year ended December 31, 2006, total depreciation, depletion and amortization expenses increased 21% to $4,909, as compared to $4,069 in the prior year, and depletion and amortization related to producing assets increased 16% to $4,163, as compared to $3,583 in the prior year. The increase is due primarily to production beginning at Doty Mountain and Sun Dog Units in 2006, and an increase in capital expenditures at Mesa. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 10%, or $0.12, to $1.29, as compared to the prior year. The depreciation of the new pipeline, which totaled $213 for the year ended December 31, 2006, also contributed to the overall increase in total depreciation, depletion and amortization.
During the year ended December 31, 2006, the Rattlesnake prospect in Wyoming was drilled and determined to be a dry hole. A charge to income of $278 is included in the consolidated statement of operations.
General and administrative
During the year ended December 31, 2006, general and administrative expenses increased 31% to $3,959 as compared to $3,015 in the prior year. The increase was due largely to employee stock option expenses totaling $460, incurred pursuant to the adoption of SFAS 123(R) on January 1, 2006, and $357 for professional fees, related to establishing and implementing our Sarbanes Oxley compliance systems. For additional information regarding the adoption of SFAS 123(R), see "—Recently Adopted Accounting Pronouncement” and Item 15, Note 5 of the Notes to the Consolidated Financial Statements.
Income taxes
During the year ended December 31, 2006, we recorded an income tax expense of $1,399, as compared to $2,043 during the prior year. Our income tax expense reflects an effective book rate of 39.9% in 2006. The higher than expected effective book rate reflects the tax effect of the permanent difference caused by the stock option expense related to the adoption of SFAS 123(R) not being deductible for income tax purposes. Although we expect to continue to generate losses for federal income tax reporting purposes, our sustained net income from operations has resulted in a deferred tax position required under generally accepted accounting principles. We do not anticipate any required payments for current tax liabilities in the near future. We have a net operating loss carry-forward of $10.3 million at December 31, 2006.
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LIQUIDITY AND CAPITAL RESOURCES
Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurances that the historical sources of liquidity and capital resources will be available for future development projects, and we may be required to seek additional or alternative financing sources. Product prices and volumes, as well as the timely collection of receivables and the availability of oil field services and supplies such as concrete, pipe and compression equipment are all expected to have a significant influence on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon the success and timing of our exploration and production activities, new project development, efficient operation of our facilities and our ability to obtain financing at favorable terms.
We believe that the amounts available under our $50 million bank line of credit and the possibility of offerings of securities, together with the net cash provided by operating activities, will provide us with sufficient funds to develop new reserves, maintain our current facilities and complete our current capital expenditure program. Depending on the timing and amount of future projects, we may be required to seek additional sources of capital. While we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.
The table below provides a year-to-year overview of selected financial information that addresses our overall financial condition, liquidity, and cash flow activities. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.
| | | | | | | | | | | | | | | | | | | | | |
| | | As of and for the Years Ended December 31, | | Percent Change Between Years |
| | | 2007 | | 2006 | | 2005 | | 2006 to 2007 | | 2005 to 2006 |
| Financial information | | | | | | | | | | | | | | | | | | | | |
| Working capital | | $ | (7,012 | ) | | $ | (7,006 | ) | | $ | (2,804 | ) | | | 0 | % | | | 150 | % |
| Line of credit | | $ | 3,445 | | | $ | 13,221 | | | $ | 3,000 | | | | -74 | % | | | 341 | % |
| Stockholders’ equity | | $ | 28,624 | | | $ | 33,042 | | | $ | 29,778 | | | | -13 | % | | | 11 | % |
| Net income (loss) attributable to common stock | | $ | (13,413 | ) | | $ | 2,109 | | | $ | 3,965 | | | | -736 | % | | | -47 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | | | | -703 | % | | | -4 | % |
| Diluted | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | | | | -705 | % | | | -47 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities | | $ | 5,166 | | | $ | 10,951 | | | $ | 10,319 | | | | -53 | % | | | 6 | % |
| Net cash used in investing activities | | $ | (42,056 | ) | | $ | (22,241 | ) | | $ | (16,259 | ) | | | 89 | % | | | 37 | % |
| Net cash provided by financing activities | | $ | 36,404 | | | $ | 10,470 | | | $ | 3,701 | | | | 248 | % | | | 183 | % |
The decrease in net cash provided by operating activities is discussed in detail in the section Results of Operations in this MD&A above. The increases in both net cash used in investing activities and net cash provided by financing activities result from the exploration and development drilling activities and the Company’s Common and Series A Preferred Stock offerings as discussed in MD&A below.
Capital Requirements
Our primary capital expenditures by type for the three years ended December 31, 2007, 2006 and 2005 were:
| | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Property acquisition costs | | $ | 316 | | | $ | 100 | | | $ | 407 | |
| Exploration | | | 3,600 | | | | 11,304 | | | | 3,693 | |
| Development | | | 41,337 | | | | 10,046 | | | | 14,873 | |
| | | | | | | | | | |
| | | $ | 45,253 | | | $ | 21,450 | | | $ | 18,973 | |
| | | | | | | | | | |
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Our development and exploratory projects in 2007 focused our core projects in the Atlantic Rim and the Pinedale Anticline.
We received the Final Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”) on May 21, 2007, which allows for the drilling of up to 1,800 coal-bed methane wells and 200 conventional oil and gas wells in the Atlantic Rim Area. During the fourth quarter of 2007, we drilled 33 wells in the Catalina Unit, of which six were completed and hooked up by December 31, 2007. We expect to have the remaining wells completed and producing by the end of the first quarter 2008. Capital expenditures during the year were $20,675 as of December 31, 2007. Also within the Atlantic Rim, we are participating in the drilling and completion of 52 additional wells within the Sun Dog Unit. Double Eagle currently has a 4.55% working interest in the Unit, which will change to an estimated 8.4% working interest once the new wells are drilled. It is expected that these wells will be drilled and completed by March 2008. Capital expenditures during the year were $426 as of December 31, 2007. We also participated in the drilling of new development wells operated by Wexpro in the Pinedale Anticline, specifically in the Mesa B and Mesa C Units, at a cost of approximately $4,011.
Also, on December 31, 2007 we began drilling the Waltman 34-24 well in the Wind River Basin. This well is a 40 acre offset to the Chevron Waltman 96 well that has been producing since early 2007. Gas shows at commercially feasible levels have been seen. Management expects the well to be completed sometime during the second quarter of 2008.
During the third quarter 2007, we participated in the drilling of the Straight Flush 17-1 well in Huntington Valley, Nevada. The well was drilled, deemed to be a dry-hole and plugged and abandoned in October 2007. Costs incurred through December 31, 2007 of $1,983 were charged to dry hole expense.
Our development projects in 2006 included the Atlantic Rim, the Pinedale Anticline and on the Moxa Arch. Additionally, we purchased a 0.3493% interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the sour gas plant at the Madden Field in the Wind River Basin in Wyoming.
We commenced four exploratory drilling projects in 2006: (i) the Rattlesnake exploratory prospect in Wyoming; (ii) the South Fillmore exploratory prospect just north of Cow Creek; (iii) the Cow Creek Unit Deep #2 development prospect to deeper formations in our Cow Creek Field, and (iv) the Christmas Meadows exploratory prospect in northeast Utah. The Rattlesnake prospect was drilled and determined to be a dry hole during the third quarter 2006.
Our development projects in 2005 included the building of our intrastate gas pipeline, which connects the Cow Creek Field with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. Other development projects included the development of power generation and water processing facilities at Cow Creek, continued participation in the drilling of new development wells in the Pinedale Anticline and non-operated development coal bed natural gas projects in the Atlantic Rim.
For 2008, we have budgeted approximately $40-$60 million for ongoing development programs in the Atlantic Rim and Pinedale Anticline as compared to $50 million planned and $41.3 million actually expended for 2007. In addition to development of our reserves in our core areas, we believe in engaging in exploratory efforts that may lead to new core areas in the future. The 2008 budget does not include the impact of any potential future exploration projects, ongoing exploration or development activities at Christmas Meadows, Cow Creek Unit Deep #2 or South Fillmore, or possible acquisitions. We continually evaluate our opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued.
Contractual Obligations
The impact that our contractual obligations as of December 31, 2007 are expected to have on our liquidity and cash flow in future periods is:
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| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | One year | | | 2 - 3 | | | 4 - 5 | | | More than | |
| | | Total | | | or less | | | Years | | | Years | | | 5 Years | |
| Line of credit (a) | | $ | 3,445 | | | $ | — | | | $ | — | | | $ | 3,445 | | | $ | — | |
| Interest on line of credit (b) | | | 552 | | | | 214 | | | | 338 | | | | — | | | | — | |
| Operating leases | | | 65 | | | | 46 | | | | 19 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| Total contractual cash commitments | | $ | 4,062 | | | $ | 260 | | | $ | 357 | | | $ | 3,445 | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | |
| (a) | | The amount listed reflects the balance outstanding as of December 31, 2007. Any balance outstanding at July 31, 2010, is due at that time. |
| |
| (b) | | The interest rate assumed on the credit facility is 6.125% per annum, which was the rate in effect at December 31, 2007. |
Our Current Credit Facility
As part of our cash management program, effective August 1, 2006, the Company entered into a $50 million revolving line of credit collateralized by oil and gas producing properties, replacing the previously existing revolving line of credit. The borrowing base increased to $35 million from $25 million, pursuant to the debt modification agreement dated July 1, 2007, and all outstanding balances on the line of credit mature on July 31, 2010. The Company expects, but cannot guarantee, to increase its borrowing base as a result of the December 31, 2007 proved reserve estimates. As of December 31, 2007, the interest rate on the line of credit, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 6.125%, and the balance outstanding of $3.4 million was used to fund capital expenditures primarily on our Catalina Unit development.
We are subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0. As of December 31, 2007, we were in compliance with all the covenants. If our covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
Access to Capital Markets
On January 23, 2007, pursuant to our universal shelf registration statement on Form S-3 with the Securities and Exchange Commission, declared effective December 15, 2006, the Company completed a public offering of 500,000 shares of Common Stock at a price to the public of $21.55 per share. Net proceeds from the offering were approximately $10 million, after deducting underwriter fees and other offering expenses. The net proceeds from this offering were used to pay down the outstanding indebtedness on the Company’s revolving line of credit.
On July 5, 2007, pursuant to our universal shelf registration statement on Form S-3 with the Securities and Exchange Commission, declared effective December 15, 2006, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share. Net proceeds from the offering were approximately $38 million, after deducting underwriter discounts and offering expenses. A portion of the net proceeds from this offering was used to pay off the outstanding indebtedness on the Company’s revolving line of credit of approximately $17 million. The remaining proceeds were invested in short term investment accounts.
The universal shelf on Form S-3 permits Double Eagle, but does not assure its ability to offer or sell, in one or more public offerings, shares of newly issued common stock, shares of newly issued preferred stock, warrants, stock purchase contracts, stock purchase units or debt securities, or any combination of such securities, for proceeds in an aggregate amount of up to $200 million (approximately $150 million remaining as of December 31, 2007). The terms of any future offerings under the shelf registration will be determined at the time of the offering and will be stated in a prospectus supplement.
Off-Balance Sheet Arrangements
We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Form 10-K.
From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts include the forward sales contracts discussed
40
directly below under Contracted Volumes. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.
CONTRACTED VOLUMES
We have entered into fixed delivery contracts with a third-party marketing company for our production at the Atlantic Rim and the Pinedale Anticline, which reduces our overall exposure to downward commodity price fluctuations. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts may limit the risk of fluctuating cash flows due to changing commodity prices. As with most derivative instruments, our fixed price contracts contain provisions which may allow for either party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. Neither party in any of our fixed price contracts has required any form of security guarantee as of December 31, 2007.
FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities,was effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which has subsequently been amended by SFAS No. 138 and SFAS No. 149, these fixed delivery contracts qualify for the scope exception under “normal purchases and normal sales,” so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not settle net. During both the first quarter of 2007 and beginning in September 2007, production in the Catalina Unit (original 14 Cow Creek wells) fell below contractual volumes and Double Eagle purchased gas on the spot market in order to satisfy the fixed delivery contracts. The Company has determined that this qualifies as net settlement and accordingly, the Catalina Unit contracts no longer qualify as “normal purchases and normal sales” under SFAS No. 133. In accordance with the provisions of SFAS No. 133, and effective November 1, 2007, the Catalina Unit fixed delivery contracts are accounted for as cash flow hedges with the change in the market value being recognized as either an asset or liability in the Consolidated Balance Sheet and are measured at fair value. Changes in the fair value are recorded each period in other comprehensive income or current earnings, depending on the nature of the transaction. See Item 15, Note 5 to the Notes to the Consolidated Financial Statements for additional discussion of hedge accounting.
As of December 31, 2007, we had sales delivery contracts in effect for approximately 64% of our gross current daily production (volume and daily production are expressed in Mcf):
| | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | |
| | | Contractual | | Daily | | | | | | Fixed |
| Property | | Volume | | Production | | Term | | Price/Mcf |
| Catalina | | | 517,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | |
| | | | 547,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | |
| | | | 1,094,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | |
| | | | 670,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | |
| Atlantic Rim | | | 578,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | |
| Pinedale Anticline | | | 547,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | |
| | | | | | | | | | | | | | | | | |
| Company Total | | | 3,953,000 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
We also have a transportation agreement for all production volumes through our pipeline, for which we receive a third party fee per Mcf of gas transported.
In accordance with the Company’s on-going risk management and to limit the credit risk associated with the above sales delivery contracts, subsequent to year-end the Company purchased NYMEX futures contracts for 3,000 Mcf per day, for the period November 1, 2008 through March 31, 2009. The price of the futures contract is $9.53. These contracts will limit the Company’s exposure to price increases above our fixed sales delivery contract prices during the winter months when prices historically rise.
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CRITICAL ACCOUNTING ESTIMATES
This discussion and analysis of our financial condition and results of operations are based on the consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1, “Business Description and Summary of Significant Accounting Policies”, of the Notes to the Consolidated Financial Statements, included in Item 15 of this Annual Report on Form 10-K. In the following discussion, we have identified the accounting estimates which we consider as the most critical to aid in fully understanding and evaluating our reported financial results. Estimates regarding matters that are inherently uncertain require difficult, subjective or complex judgments on the part of our management. We analyze our estimates, including those related to oil and gas reserves, oil and gas properties, income taxes, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe reasonable under the circumstances. Actual results may differ from these estimates.
Successful Efforts Method of Accounting
We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses, and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled which have targeted geologic structures which are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs may require managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. During 2007, it was determined that the exploratory costs related to the Cow Creek Unit Deep #2 ($4,395), the PH State 16-1 ($2,759), The Christmas Meadows Table Top Unit #1 ($5,773) and the Straight Flush 17-1 ($1,983) did not meet the requirements for continued capitalization as exploratory wells. The associated costs of these projects were expensed in the December 31, 2007 consolidated financial statements. We will continue to access the operational viability of these projects.
Reserve Estimates
Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value
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of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Impairment of Long-Lived Assets
The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. For the twelve month
period ended December 31, 2007, the Company recognized non-cash charges of $2,141 on the impairment of properties included in Developed Properties and $91 on undeveloped leaseholds.
The Mad #1 well was completed in the second quarter 2006 at approximately 3,300 feet in the Deep Creek Sandstone in the lower Mesaverde and, accordingly, capitalized as a Developed Property. The well initially produced, during the first two months of production, approximately 15,500 Mcf/month, with production dropping off to an average of 676 Mcf/month for the remainder of 2006. The well has produced minimally during 2007. The Company intends to temporarily plug the well at its current depth to production test the Haystack Mountain Formation above the current zone. If it is determined that the well is not capable of commercial production, the well will be used as an injection well in the Catalina Unit. As a result, the Company has determined that $1,351 of capitalized costs (the difference between the current capitalized costs of the Mad #1 and the costs of a Catalina Unit water injection well) related to the Mad #1 was impaired, and expensed during the year ended December 31, 2007.
During 2007, work was performed on the State 1-36 well to enhance the recoverability of its reserves. These efforts were not as successful as originally contemplated. Additionally, the property was shut-in due to a dispute related to the transportation agreement for the natural gas produced at this well, and that is expected to continue for the foreseeable future. As a result, the Company has determined that $693 of capitalized costs (capitalized costs net of salvage value) related to the State 1-36 is impaired, and that amount has been expensed in the quarter ended September 30, 2007.
Asset Retirement Obligation
We recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates as well as determine what credit adjusted risk-free rate to use. The statement of operations impact of these estimates is reflected in our depreciation, depletion and amortization calculations and occurs over the remaining life of our oil and gas properties.
Derivative instruments
FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities,was effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which has subsequently been amended by SFAS No. 138 and SFAS No. 149, derivative instruments are measured at fair value with the change in the market value being recognized as either an asset or liability in the consolidated balance sheets. Changes in the fair value are recorded each period in other comprehensive income or current earnings, depending on the nature of the transaction.
The determination of which contracts meet the definition of a derivative as well as the fair value measurement of identified derivative instruments is subject to interpretation. We use our judgment to analyze which contracts, including the fixed capacity contracts, meet the definition of a derivative instrument and to determine the fair value of each instrument identified.
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Stock-based compensation
Share-Based Payment (“SFAS 123(R)”), requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options) made to employees and directors based on the estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Total share-based compensation expense for equity-classified awards, was $362 during the year ended December 31 2007. As of December 31, 2007, total estimated unrecognized compensation expense from unvested stock options was $819, which is expected to be recognized over a period of five years.
We use the Black-Scholes valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Double Eagle’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Double Eagle’s stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.
Recently issued accounting pronouncements
We continually review and modify our accounting policies as new rules are issued. The following accounting pronouncements were adopted during the year or have been recently issued, but have not yet been adopted by the Company.
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157 – Fair Value Measurements (“SFAS 157”). The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In December 2007, the FASB issued SFAS 157-b which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). The adoption of SFAS 157 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (“SFAS 159”). The statement permits companies to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of SFAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 will be effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 159 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
In November 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R) – Business Combinations (“SFAS 141(R)”). SFAS 141(R) changes the accounting for business combinations both at the acquisition date and in subsequent reporting periods. SFAS 141(R) requires the acquiring Company to measure almost all assets acquired and liabilities assumed in the acquisition at fair value as of the acquisition date. The standard is effective for fiscal years beginning on or after December 15, 2008 and should be applied prospectively with the exception of income taxes which should be applied retrospectively for all business combinations. Early adoption is prohibited. The adoption of SFAS 141(R) is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
In November 2007, the FASB issued Statement of Financial Accounting Standards No. 160 – Noncontrolling Interests in Consolidated Financial Statements an amendment to ARB NO. 51 (“SFAS 160”). SFAS 160 requires noncontrolling interests in a subsidiary to be initially measured at fair value and classified as a separate component of equity. The standard is effective for fiscal years beginning on or after December 15, 2008 and should be applied prospectively with the exception of the presentation and disclosure requirements which should be applied retrospectively if comparative financial statements are presented. Early adoption is prohibited. The adoption of SFAS 160 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risks
We pay interest on outstanding borrowings under our revolving credit facility at interest rates that fluctuate based upon changes in the prime lending rate. As the interest rate is variable and reflective of current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at December 31, 2007, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $34 before taxes.
Effective August 1, 2006, the Company entered into a $50 million revolving line of credit collateralized by oil and gas producing properties, replacing the previously existing revolving line of credit. The borrowing base increased to $35 million from $25 million, pursuant to the debt modification agreement dated July 1, 2007, and all outstanding balances on the line of credit mature on July 31, 2010. As of December 31, 2007, the interest rate on the line of credit, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 6.125%, and the outstanding balance was $3,445.
Commodity Price Risks
Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the year ended December 31, 2007, our income before income taxes would have changed by $411 for each $0.50 change per Mcf in natural gas prices and $12 for each $1.00 change per Bbl in crude oil prices.
Risk policy and control
We control the extent of our risk management activities through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing equity hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels.
The primary objective of our commodity price risk management policy is to preserve and enhance the value of the Company’s equity gas production. In order to accomplish this objective, we may enter into equity hedge agreements, within approved limits, in order to protect our equity production from fluctuations in commodity prices and the resulting impact on cash flow, net income and earnings per share.
We have entered into various fixed delivery contracts with a third-party marketing company for our production at the Atlantic Rim and the Pinedale Anticline, which reduces our overall exposure to commodity price fluctuations. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts may limit the risk of fluctuating cash flows due to changing commodity prices.
FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities,was effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which has subsequently been amended by SFAS No. 138 and SFAS No. 149, these fixed delivery contracts qualify for the scope exception under “normal purchases and normal sales,” so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not settle net. During both the first quarter of 2007 and beginning in September 2007, production in the Catalina Unit (original 14 Cow Creek wells) fell below contractual volumes and Double Eagle purchased gas on the spot market in order to satisfy the fixed delivery contracts. The Company has determined that this qualifies as net settlement and accordingly, the Catalina Unit contracts no longer qualify as “normal purchases and normal sales” under SFAS No. 133. In accordance with the provisions of SFAS No. 133, and effective November 1, 2007, the Catalina Unit fixed delivery contracts are accounted for as cash flow hedges with the change in the market value being recognized as either an asset or liability in the Consolidated Balance Sheet and are measured at fair value. Changes in the fair value are recorded each period in other comprehensive income or current earnings, depending on
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the nature of the transaction. Our remaining Atlantic Rim contracts, for production from the Doty Mountain and Sun Dog Units, as well as our Pinedale Anticline contracts continue to be accounted for under the “normal purchases and normal sales exception,” as it continues to be probable that these contracts will not settle net and will result in physical delivery for the duration of the contracts.
The use of these fixed delivery contracts may expose us to the risk of financial loss if the spot price of gas exceeds the weighted average price of our contracted volumes. As with most derivative instruments, our fixed price contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. Neither party in any of our fixed price contracts has required any form of security guarantee as of December 31, 2007.
Hedge positions
As of December 31, 2007, we have entered into fixed delivery contracts for approximately 64% of our current daily production. The Catalina Unit contracts, identified by management and accounted for as hedges as of November 1, 2007, represent 89% of our December 2007 gross daily production in the Unit. All of these contracts are designated and accounted for as cash flow hedges with the effective portion of gains and losses, related to the changes in the fair value, recorded in accumulated other comprehensive income, a component of Stockholder’s equity. Realized gains and losses are recognized in the Consolidated Statement of Operations in the accompanying financial statements as a separate component of revenue when the fixed delivery contract transaction occurs.
In order to qualify as cash flow hedges, the instruments must be designated as such and the changes in fair value must be highly correlated with the changes in price of our equity production. As the fixed delivery contract is in place for the sale of gas at the inlet from our production field, management has assumed 100% effectiveness for the Catalina Unit contracts designated as cash flow hedges. During the year we recognized $304 gain on price risk management activities for the settlement of the fixed delivery contracts for the Catalina Unit for the months of November and December.
Account balances related to our equity hedging transactions as of December 31, 2007 were $474 in current liabilities from price risk management activities, $1,001 in long term liabilities from price risk management activities and $1,475 after-tax unrealized losses in accumulated other comprehensive income. Based on the December 31, 2007 prices, management expects approximately $474 losses, included in accumulated other comprehensive income, to be reclassified to earnings during 2008.
Summary of derivative positions
A summary of the net change in our derivative positions from December 31, 2006 to December 31, 2007 is as follows(amounts in thousands):
| | | | | |
| Fair value of contracts outstanding at December 31, 2006 | | $ | — | |
| Decrease in value due to change in price | | | — | |
| Decrease in value due to new contracts entered into during the period | | | (1,779 | ) |
| Gains realized during the period from existing and new contracts | | | 304 | |
| Changes in fair value attributable to changes in valuation techniques | | | — | |
| | | | |
| Fair value of contracts outstanding at December 31, 2007 | | $ | (1,475 | ) |
| | | | |
A summary of our outstanding derivative positions as of December 31, 2007 is as follows(amounts in thousands):
| | | | | | | | | | | | | | | | | | | | | |
| Fair Value of Contracts at December 31, 2007 |
| Total Fair | | Maturing in | | Maturing in | | Maturing in | | Maturing |
| Value | | 2008 | | 2008-2009 | | 2010-2011 | | Thereafter |
| $(1,475) | | $ | (474 | ) | | $ | (1,001 | ) | | $ | — | | | $ | — | |
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is included in Item 15, “Exhibits, Financial Statements and Financial Statement Schedules.”
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our Principal Executive Officer and Chief Financial Officer and Principal Accounting Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this annual report on Form 10-K. Management identified a material weakness in our internal controls over financial reporting as of the end of the period, and as reported in the annual report on Form 10-K, December 31, 2006. Management has addressed the remediation of this material weakness and concluded that our disclosure controls and procedures were effective as of December 31, 2007.
Management’s Annual Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:
| | (i) | | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; |
| |
| | (ii) | | 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 |
| |
| | (iii) | | 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.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. As of December 31, 2007, the Company effectively remediated the material weakness identified in the annual report on Form 10-K for the year ended December 31, 2006.
As identified and reported in the annual report on Form 10-K for the year ended December 31, 2006, the Company did not perform timely and sufficient review to verify the information supplied by the Company’s independent reserve engineers in the Company’s December 31, 2006 reserve report. Thus, management’s oversight and review related to the reserve report was not effective. These deficiencies in internal control over financial reporting could have resulted in misstatements in the Company’s 2006 reserve related disclosures and depletion expense.
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During the first fiscal quarter of 2007, management took the following steps to address the material weakness identified in the annual report on Form 10-K filed for the year ended December 31, 2006:
| | • | | Redesign of the controls to include detailed steps and instruction on performance of controls and procedures; |
| |
| | • | | Ensure employees who are performing controls understand responsibilities and how to perform said responsibilities; |
| |
| | • | | Design and implement a detailed check list to be completed prior to approval of reserve report and inclusion in any Company reports or filings. |
For the Company’s reserve report issued as of December 31, 2007, management implemented, the aforementioned controls, to ensure the timely and sufficient review to verify the information supplied by the Company’s independent reserve engineers.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007 and, as a result of the implementation of the remediation steps, concluded that, as of December 31, 2007, the Company’s internal controls over financial reporting are effective.
The Company’s independent registered public accounting firm, Hein & Associates LLP, has issued a report on the Company’s internal control over financial reporting.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during our fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Double Eagle Petroleum Co.
We have audited Double Eagle Petroleum Co.’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Double Eagle Petroleum Co.’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 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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.
In our opinion, Double Eagle Petroleum Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Frameworkissued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Double Eagle Petroleum Co. and our report dated March 13, 2008, expressed an unqualified opinion.
/s/ HEIN & ASSOCIATES LLP
Denver, Colorado
March 13, 2008
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ITEM 9B. OTHER INFORMATION
None.
PART III
Pursuant to instruction G(3) to Form 10-K, the following Items 10,11,12,13 and 14 are incorporated by reference to the information provided in Double Eagle’s definitive proxy statement for the 2007 annual meeting of stockholders to be filed within 120 days from December 31, 2007.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the executive officers and directors of the Company, and persons who own more than 10% of a registered class of the Company’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Company, the filing requirements were not met by Robert F. Reiner due to his failure to timely file a Form 4 related to common stock grants in January 2008; however, such required report has since been filed with the SEC.
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICE
PART IV
ITEM 15. EXHIBITS , FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
All other schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.
(b)Exhibits.The following exhibits are filed with or incorporated by reference into this report on Form 10-K:
| | | |
| Exhibit No. | | Description |
| | | |
| 3.1(a) | | Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
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| | | |
| Exhibit No. | | Description |
| | | |
| 3.1(b) | | Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | |
| 3.1(c) | | Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | |
| 3.1(d) | | Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001). |
| | | |
| 3.1(e) | | Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007). |
| | | |
| 3.1(f) | | Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007). |
| | | |
| 3.1(g) | | Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007). |
| | | |
| 3.1(h) | | Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007). |
| | | |
| 3.2(a) | | Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001). |
| | | |
| 3.2(b) | | Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007). |
| | | |
| 3.2(c) | | Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007). |
| | | |
| 4.1(a) | | Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011). |
| | | |
| 4.1(b) | | Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007). |
| | | |
| 4.1(c) | | Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007). |
| | | |
| 4.1(d) | | Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007). |
| | | |
| 10.1(a) | | Debt Modification Agreement, effective August 1, 2006, including Commercial Loan Agreement dated January 3, 2000, between Double Eagle Petroleum Co. and American National Bank (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, and incorporated herein by reference). |
| | | |
| 10.1(b) | | Debt Modification Agreement, effective July 1, 2007, between Double Eagle Petroleum Co. and American National Bank (incorporated by reference from Exhibit 10.1 to the Company’s Current report on Form 8-K dated July 5, 2007). |
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| | | |
| Exhibit No. | | Description |
| | | |
| 10.1(c) | | Double Eagle Petroleum Co. 2007 Stock Incentive Plan, Form of Incentive Stock Option Agreement and Form of Non-Qualified Stock Option Agreement (incorporated by reference from Exhibit 10.1, 10.2 and 10.3 to the Company’s Current report on Form 8-K dated May 29, 2007). |
| | | |
| 14.1 | | Code of Business Conduct and Ethics (filed as Exhibit 99.2 to the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2004, and incorporated herein by reference). |
| | | |
| 21.1* | | Subsidiaries of registrant. |
| | | |
| 23.1* | | Consent of Hein & Associates LLP. |
| | | |
| 23.2* | | Consent of Netherland, Sewell & Associates. |
| | | |
| 31.1* | | Certification of Principal Executive Officer and Chief Financial Officer (Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | |
| 32* | | Certification Pursuant to 18 U.S.C. Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002. |
| | |
| * | | Filed with this Form 10-K. |
52
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act Of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOUBLE EAGLE PETROLEUM CO.
| | | | | |
| | | |
| Date: March 13, 2008 | /s/ Kurtis S. Hooley | |
| | Principal Executive Officer | |
| | | |
| |
Pursuant to the requirements of the Securities Exchange Act Of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | |
| | | |
| Date: March 13, 2008 | /s/ Kurtis S. Hooley | |
| | Principal Executive Officer | |
| | Chief Financial Officer
(Principal Accounting Officer) | |
| |
| | | |
| Date: March 13, 2008 | /s/ Richard Dole | |
| | Richard Dole, Chairman Elect | |
| | | |
| |
| | | |
| Date: March 13, 2008 | /s/ Sigmund Balaban | |
| | Sigmund Balaban, Director | |
| | | |
| |
| | | |
| Date: March 13, 2008 | /s/ Roy G. Cohee | |
| | Roy G. Cohee, Director | |
| | | |
| |
| | | |
| Date: March 13, 2008 | /s/ Stephen H. Hollis | |
| | Stephen H. Hollis, Director | |
| | | |
| |
53
REPORT OF INDEPENDENT REGISTERED PUBIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Double Eagle Petroleum Co.
We have audited the consolidated balance sheets of Double Eagle Petroleum Co. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Double Eagle Petroleum Co. and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Double Eagle Petroleum Co. and subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 13, 2008, expressed an unqualified opinion on the effectiveness of Double Eagle Petroleum Co.’s internal control over financial reporting.
As discussed in Note 3 to the accompanying consolidated financial statements, effective January 1, 2006 the Company adopted Statements of Financial Accounting Standards No. 123(R),Share Based Payment.
/s/ HEIN & ASSOCIATES LLP
Denver, Colorado
March 13, 2008
F-1
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of dollars except share and per share data)
| | | | | | | | | |
| | | December 31, | |
| | | 2007 | | | 2006 | |
| ASSETS | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 125 | | | $ | 611 | |
| Cash held in escrow | | | 719 | | | | 707 | |
| Accounts receivable, net | | | 3,664 | | | | 5,047 | |
| Other current assets | | | 586 | | | | 809 | |
| | | | | | | |
| Total current assets | | | 5,094 | | | | 7,174 | |
| | | | | | | |
| | | | | | | | | |
| Oil and gas properties and equipment, successful efforts method: | | | | | | | | |
| Developed properties | | | 61,394 | | | | 53,677 | |
| Wells in progress | | | 29,768 | | | | 13,839 | |
| Gas transportation pipeline | | | 5,465 | | | | 5,412 | |
| Undeveloped properties | | | 3,147 | | | | 3,313 | |
| Corporate and other assets | | | 1,585 | | | | 1,024 | |
| | | | | | | |
| | | | 101,359 | | | | 77,265 | |
| Less accumulated depreciation, depletion and amortization | | | (24,785 | ) | | | (20,079 | ) |
| | | | | | | |
| Net properties and equipment | | | 76,574 | | | | 57,186 | |
| | | | | | | |
| Deferred tax asset | | | 2,873 | | | | — | |
| Other assets | | | 56 | | | | 46 | |
| | | | | | | |
| TOTAL ASSETS | | $ | 84,597 | | | $ | 64,406 | |
| | | | | | | |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 8,584 | | | $ | 7,964 | |
| Accrued expenses | | | 2,079 | | | | 5,125 | |
| Liabilities from price risk management | | | 474 | | | | — | |
| Accrued production taxes | | | 969 | | | | 1,091 | |
| | | | | | | |
| Total current liabilities | | | 12,106 | | | | 14,180 | |
| | | | | | | | | |
| Line of credit | | | 3,445 | | | | 13,221 | |
| Asset retirement obligation | | | 1,449 | | | | 694 | |
| Liabilities from price risk management | | | 1,001 | | | | — | |
| Deferred tax liability | | | — | | | | 3,269 | |
| | | | | | | |
| Total liabilities | | | 18,001 | | | | 31,364 | |
| | | | | | | |
| | | | | | | | | |
| Commitments and contingencies (Note 4 and 5) | | | | | | | | |
| | | | | | | | | |
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 and 0 shares issued and outstanding as of December 31, 2007 and 2006, respectively
(liquidation preference of $25.00 per share) | | | 37,972 | | | | — | |
| | | | | | | |
| | | | | | | | | |
| Stockholders’ equity: | | | | | | | | |
| Common stock, $0.10 par value; 50,000,000 shares authorized; 9,148,105 and 8,641,104 shares issued and outstanding as of December 31, 2007 and 2006, respectively | | | 915 | | | | 864 | |
| Additional paid-in capital | | | 33,670 | | | | 23,251 | |
| Retained earnings (deficit) | | | (4,486 | ) | | | 8,927 | |
| Accumulated other comprehensive income | | | (1,475 | ) | | | — | |
| | | | | | | |
| Total stockholders’ equity | | | 28,624 | | | | 33,042 | |
| | | | | | | |
| | | | | | | | | |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | | $ | 84,597 | | | $ | 64,406 | |
| | | | | | | |
The accompanying notes are an integral part of the consolidated financial statements.
F-2
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands of dollars except share and per share data)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Revenues | | | | | | | | | | | | |
| Oil and gas sales | | $ | 15,740 | | | $ | 18,228 | | | $ | 20,451 | |
| Transportation revenue | | | 910 | | | | 523 | | | | — | |
| Price risk management activities | | | 304 | | | | — | | | | — | |
| Other income | | | 243 | | | | 281 | | | | 45 | |
| | | | | | | | | | |
| Total revenues | | | 17,197 | | | | 19,032 | | | | 20,496 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Costs and expenses | | | | | | | | | | | | |
| Production costs | | | 6,341 | | | | 3,730 | | | | 3,800 | |
| Production taxes | | | 1,933 | | | | 2,209 | | | | 2,523 | |
| Exploration expenses including dry hole costs | | | 15,399 | | | | 530 | | | | 747 | |
| Impairment of equipment and properties | | | 2,232 | | | | — | | | | 357 | |
| General and administrative | | | 4,133 | | | | 3,959 | | | | 3,015 | |
| Depreciation, depletion and amortization | | | 5,068 | | | | 4,909 | | | | 4,069 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total costs and expenses | | | 35,106 | | | | 15,337 | | | | 14,511 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (loss) from operations | | | (17,909 | ) | | | 3,695 | | | | 5,985 | |
| | | | | | | | | | | | | |
| Interest (expense) income, net | | | 163 | | | | (187 | ) | | | 23 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (loss) before income taxes | | | (17,746 | ) | | | 3,508 | | | | 6,008 | |
| | | | | | | | | | | | | |
| Provision for deferred income taxes | | | 6,143 | | | | (1,399 | ) | | | (2,043 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (11,603 | ) | | $ | 2,109 | | | $ | 3,965 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Preferred stock dividends | | | (1,810 | ) | | | — | | | | — | |
| | | | | | | | | | |
| Net income (loss) attributable to common stock | | $ | (13,413 | ) | | $ | 2,109 | | | $ | 3,965 | |
| | | | | | | | | | |
| Net income (loss) per common share: | | | | | | | | | | | | |
| Basic | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | |
| | | | | | | | | | |
| Diluted | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Weighted average shares outstanding: | | | | | | | | | | | | |
| Basic | | | 9,114,622 | | | | 8,632,567 | | | | 8,564,228 | |
| | | | | | | | | | |
| Diluted | | | 9,114,622 | | | | 8,655,587 | | | | 8,628,476 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the consolidated financial statements.
F-3
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of dollars)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Cash flows from operating activities: | | | | | | | | | | | | |
| Net income (loss) | | $ | (11,603 | ) | | $ | 2,109 | | | $ | 3,965 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | |
| Depreciation, depletion, amortization and accretion of asset retirement obligation | | | 5,062 | | | | 4,909 | | | | 4,088 | |
| Abandonment of non-producing properties and leases | | | 14,941 | | | | 20 | | | | 106 | |
| Bad Debt Expense | | | 559 | | | | — | | | | — | |
| Impairment of equipment and properties | | | 2,234 | | | | — | | | | 357 | |
| Provision for deferred taxes | | | (6,143 | ) | | | 1,399 | | | | 2,043 | |
| Directors fees paid in stock | | | 90 | | | | 97 | | | | 160 | |
| Non-cash employee stock option expense | | | 362 | | | | 460 | | | | 26 | |
| Gain on sale of working interest in non-producing property | | | (98 | ) | | | — | | | | — | |
| Other | | | — | | | | — | | | | 7 | |
| Changes in current assets and liabilities: | | | | | | | | | | | | |
| Increase in deposit held in escrow | | | (12 | ) | | | (707 | ) | | | — | |
| Decrease (Increase) in accounts receivable | | | 824 | | | | (799 | ) | | | (2,076 | ) |
| Decrease (Increase) in other current assets | | | 223 | | | | (591 | ) | | | 111 | |
| Increase (Decrease) in accounts payable | | | (1,890 | ) | | | 4,118 | | | | (938 | ) |
| Increase (Decrease) in accrued expenses | | | 739 | | | | 502 | | | | 1,785 | |
| Increase (Decrease) in accrued production taxes | | | (122 | ) | | | (566 | ) | | | 685 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET CASH PROVIDED BY OPERATING ACTIVITIES | | | 5,166 | | | | 10,951 | | | | 10,319 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | |
| Additions of producing properties and equipment | | | (42,307 | ) | | | (21,861 | ) | | | (16,248 | ) |
| Additions of corporate and non-producing properties | | | 7 | | | | (390 | ) | | | (567 | ) |
| Proceeds from sales of properties and assets | | | 244 | | | | — | | | | 571 | |
| (Additions) reductions of other assets | | | — | | | | 10 | | | | (15 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET CASH USED IN INVESTING ACTIVITIES | | | (42,056 | ) | | | (22,241 | ) | | | (16,259 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Net proceeds from sale of common stock | | | 9,990 | | | | — | | | | — | |
| Net proceeds from sale of preferred stock | | | 37,972 | | | | — | | | | — | |
| Dividends paid on preferred stock | | | (1,810 | ) | | | — | | | | — | |
| Net payments on line of credit | | | (9,776 | ) | | | 10,221 | | | | 3,000 | |
| Exercise of options | | | 28 | | | | 353 | | | | 701 | |
| Settlement of options | | | — | | | | (104 | ) | | | — | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET CASH PROVIDED BY FINANCING ACTIVITIES | | | 36,404 | | | | 10,470 | | | | 3,701 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Change in cash and cash equivalents | | | (486 | ) | | | (820 | ) | | | (2,239 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 611 | | | | 1,431 | | | | 3,670 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 125 | | | $ | 611 | | | $ | 1,431 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Supplemental disclosure of cash and non-cash transactions: | | | | | | | | | | | | |
| Cash paid for interest | | $ | 426 | | | $ | 490 | | | $ | 57 | |
| Interest capitalized | | $ | 279 | | | $ | 293 | | | $ | 43 | |
| Additions to developed properties included in current liabilities | | $ | 4,908 | | | $ | 6,183 | | | $ | 4,758 | |
| Additions to developed properties for retirement obligations | | $ | 757 | | | $ | 171 | | | $ | 87 | |
The accompanying notes are an integral part of the consolidated financial statements.
F-4
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(Amounts in thousands of dollars except share data)
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Accumulated | | | | |
| | | Shares of | | | | | | | | | | | | | | | Other | | | Total | |
| | | Common Stock | | | | | | | Additional Paid- | | | Retained | | | Comprehensive | | | Stockholders’ | |
| | | Outstanding | | | Common Stock | | | In Capital | | | Earnings | | | Income | | | Equity | |
| Balance at January 1, 2005 | | | 8,488,404 | | | $ | 849 | | | $ | 21,225 | | | $ | 2,853 | | | $ | — | | | $ | 24,927 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | — | | | | — | | | | — | | | | 3,965 | | | | — | | | | 3,965 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock options exercised and shares issued for compensation | | | 102,200 | | | | 10 | | | | 876 | | | | — | | | | — | | | | 886 | |
| | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | 8,590,604 | | | $ | 859 | | | $ | 22,101 | | | $ | 6,818 | | | $ | — | | | $ | 29,778 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | — | | | | — | | | | — | | | | 2,109 | | | | | | | | 2,109 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock options exercised | | | 44,500 | | | | 4 | | | | 349 | | | | — | | | | — | | | | 353 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Shares issued and expense recognized for stock-based compensation | | | 6,000 | | | | 1 | | | | 801 | | | | — | | | | — | | | | 802 | |
| | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 8,641,104 | | | $ | 864 | | | $ | 23,251 | | | $ | 8,927 | | | $ | — | | | $ | 33,042 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | | — | | | | — | | | | — | | | | (11,603 | ) | | | — | | | | (11,603 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in derivative instrument fair value | | | — | | | | — | | | | — | | | | — | | | | (1,475 | ) | | | (1,475 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | (13,078 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock options exercised | | | 2,000 | | | | — | | | | 27 | | | | — | | | | — | | | | 27 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Compensation expense from common stock options | | | — | | | | — | | | | 362 | | | | — | | | | — | | | | 362 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Directors fees paid in stock | | | 5,001 | | | | 1 | | | | 90 | | | | — | | | | — | | | | 91 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Sale of common stock | | | 500,000 | | | | 50 | | | | 9,940 | | | | — | | | | — | | | | 9,990 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividends declared & paid on preferred stock | | | — | | | | — | | | | — | | | | (1,810 | ) | | | — | | | | (1,810 | ) |
| | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007 | | | 9,148,105 | | | $ | 915 | | | $ | 33,670 | | | $ | (4,486 | ) | | $ | (1,475 | ) | | $ | 28,624 | |
| | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of the consolidated financial statements.
F-5
DOUBLE EAGLE PETROLEUM CO.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
| 1. | | Business Description and Summary of Significant Accounting Policies |
Description of Operations and Basis of Presentation
Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) is an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in the Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972, and reincorporated in the State of Maryland in February 2001.
During the second quarter of 2006, the Company transferred assets held related to its 13-mile intrastate gas pipeline (the “Pipeline”) to Eastern Washakie Midstream LLC, a wholly owned subsidiary of Double Eagle, which was formed on February 10, 2006. The Pipeline, which was constructed in late 2005, became operational in January 2006, and connects the Cow Creek Field to the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. Beginning in the second quarter of 2006, Double Eagle presented consolidated financial statements to reflect the consolidation of the two entities for reporting purposes (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation for all periods presented in this Form 10-K.
The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.
Certain reclassifications have been made to amounts reported in previous years to conform to the 2007 presentation. Such reclassifications had no effect on net income.
Cash and Cash Equivalents
Cash and cash equivalents includes all cash balances and any highly liquid investments with an original maturity of 90 days or less.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability. The Company recorded an allowance for uncollectible receivables of $559, $0 and $0 for the periods ending December 31, 2007, 2006 and 2005, respectively.
Use of Estimates in the Preparation of Financial Statements
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 oil and gas reserves, assets and liabilities and disclosure on contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to credit risk consist of our accounts receivable and our fixed delivery contracts. Substantially all of the Company’s receivables are within the oil and gas industry, including those from the Company’s third party marketing company. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.
Due to pending litigation against Conoco Phillips (formerly Burlington Resources) related to the Company’s receivables recorded for its share of production from the Madden Deep Participating Area for the period November 2006 to June 2007 and to collection issues identified relating primarily to exploration projects, the Company recorded an allowance for doubtful accounts on a specific identification basis of $292 for the year ended December 31, 2007 (Note 5).
F-6
Revenue Recognition and Gas Balancing
The Company recognizes oil and gas revenues for its ownership percentage of total production under the entitlement method, whereby a working interest owner records revenue based on its share of entitled production. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while the under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position with various third party operators at December 31, 2007 resulted in an imbalance receivable of 253 MMcf, or $735, and an imbalance payable of 52 MMcf, or $233.
Oil and Gas Producing Activities
Double Eagle uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, all property acquisition costs and costs of exploration and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are expensed as incurred. The Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on current prices and costs.
Depreciation, depletion and amortization (“DD&A”) of capitalized costs for producing oil and gas properties is provided on a field-by-field basis using the units-of-production method, based on proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds for equipment salvage.
Depreciation, depletion and amortization of oil and gas properties for the years ended December 31, 2007, 2006 and 2005, was $4,550, $4,163, and $3,583, respectively.
Double Eagle invests in unevaluated oil and gas properties for the purpose of exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.
The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2007, 2006 and 2005 and amounts include costs capitalized and subsequently expensed in the same period(amounts in thousands).
| | | | | | | | | | | | | |
| | | 2007 | | | 2006 | | | 2005 | |
| Beginning balance at January 1, | | $ | 11,541 | | | $ | 2,972 | | | $ | — | |
| | | | | | | | | | | | | |
| Additions to capitalized exploratory well costs pending the determination of proved reserves | | | 5,727 | | | | 11,203 | | | | 2,972 | |
| Reclassifications to wells, facilities and equipment based on the determination of proved reserves | | | (1,666 | ) | | | (2,356 | ) | | | — | |
| Capitalized exploratory well costs charged to expense | | | (14,910 | ) | | | (278 | ) | | | — | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Ending balance at December 31, | | $ | 692 | | | $ | 11,541 | | | $ | 2,972 | |
| | | | | | | | | | |
F-7
The following table provides an aging of capitalized exploratory well costs, at December 31, 2007, based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
| | | | | |
| Capitalized exploratory well costs that have been capitalized for a period of one year or less | | $ | 692 | |
| Capitalized exploratory well costs that have been capitalized for a period greater than one year | | | — | |
| | | | |
| | | | | |
| Balance at December 31, 2007 | | $ | 692 | |
| | | | |
| | | | | |
| Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | | | 0 | |
| | | | |
Under the provisions of the Financial Accounting Standards Board (“FASB”) Staff Position 19-1 (“FAS 19-1”), a company under the successful efforts method of accounting may continue to capitalize exploratory well costs if there are sufficient quantities of reserves to justify completion of the well or if the company is making significant progress towards assessing the quantities of reserves. The Company had three significant exploratory projects in progress as of December 31, 2006. The Company did not make significant progress in assessing the reserves of these wells and has not made firm plans (as defined by FAS 19-1) which would justify continued capitalization of these wells at December 31, 2007. As a result, the Company expensed $14,910 of capitalized exploratory well costs during the year ended December 31, 2007.
Asset Retirement Obligations
Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company’s asset retirement obligations relate primarily to the retirement of oil and gas properties and related production facilities, lines and other equipment used in the field operations. The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.
For the years ended December 31, 2007, 2006 and 2005, an expense of $25, $15 and $20, respectively, was recorded as accretion expense on the liability and included in depletion, depreciation and amortization. During 2007, 2006 and 2005, the Company recorded an additional $739, $170 and $86, respectively, in oil and gas properties and asset retirement obligation liability to reflect the present value of plugging liability on new wells.
A reconciliation of the Company’s asset retirement obligation liability:
| | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2007 | | | 2006 | |
| Beginning asset retirement obligation | | $ | 694 | | | $ | 513 | |
| | | | | | | | | |
| Liabilities incurred | | | 655 | | | | 87 | |
| Liabilities settled | | | (9 | ) | | | (4 | ) |
| Accretion expense | | | 25 | | | | 15 | |
| Revision to estimated cash flows | | | 84 | | | | 83 | |
| | | | | | | |
| | | | | | | | | |
| Ending asset retirement obligation | | $ | 1,449 | | | $ | 694 | |
| | | | | | | |
Impairment of Long-Lived Assets
The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other
F-8
groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. The Company recognized a non-cash charge on producing properties during the years ending December 31, 2007, 2006 and 2005 of $2,141, $0, and $357, respectively, and a non-cash charge on undeveloped leaseholds during the years ending December 31, 2007, 2006 and 2005 of $91, $0, $0, respectively..
The Company’s pipeline is recorded at cost, which totaled $5,465 as of December 31, 2007. Depreciation is recorded using the straight-line method over a 25 year estimated useful life. The useful life may be limited to the useful life of current and future recoverable reserves serviced by the pipeline.
Corporate and Other Assets
Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of 10 to 30 years for office facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense for the years ended December 31, 2007, 2006 and 2005 was $160, $107 and $100, respectively.
Major Customers
Sales to one major unaffiliated customer for years ended December 31, 2007, 2006 and 2005, were $11,530, $13,649, and $14,000, respectively. The Company believes that it is not dependent upon this customer due to the nature of its product. No other single customer accounted for 10% or more of revenues in 2007, 2006 or 2005.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development, production and sale of natural gas and crude oil, and all of the Company’s operations are conducted in the Continental United Sates. Consequently, the Company currently reports as a single industry segment. The activities of our gas transportation subsidiary are immaterial to the financial statements taken as a whole and therefore are not viewed by management as a discrete reporting segment.
Employee Benefit Plan
The Company maintains a Simplified Employee Pension Plan covering substantially all employees meeting minimum eligibility requirements. Employer contributions are determined solely at management’s discretion. Employer contributions for years ended 2007, 2006 and 2005 were $118, $87, and $63, respectively.
Income Taxes
Deferred income taxes are provided on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deduction in future periods when the reported amount of the asset or liability is recovered or settled, respectively.
Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. Fully diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of outstanding stock options by including the effect of outstanding vested and unvested options in the average number of common shares outstanding during the period.
F-9
Calculation of basic and fully diluted weighted average shares outstanding and EPS for the periods indicated:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Net income (loss) | | $ | (11,603 | ) | | $ | 2,109 | | | $ | 3,965 | |
| Preferred stock dividends | | | (1,810 | ) | | | — | | | | — | |
| | | | | | | | | | |
| Income (loss) attributable to common stock | | $ | (13,413 | ) | | $ | 2,109 | | | $ | 3,965 | |
| | | | | | | | | | |
| Weighted average shares: | | | | | | | | | | | | |
| Weighted average shares — basic | | | 9,114,622 | | | | 8,632,567 | | | | 8,564,228 | |
| Dilutive effect of stock options outstanding at the end of period | | | — | | | | 23,020 | | | | 64,248 | |
| | | | | | | | | | |
| Weighted average shares — fully diluted | | | 9,114,622 | | | | 8,655,587 | | | | 8,628,476 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings (loss) per share: | | | | | | | | | | | | |
| Basic | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | |
| | | | | | | | | | |
| Diluted | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | |
| | | | | | | | | | |
The following options that could be potentially dilutive in future periods were not included in the computation of diluted net income (loss) per share because the effect would have been anti-dilutive for the periods indicated:
| | | | | | | | | | | | | |
| | | For the years ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Options to purchase common stock | | | 6,643 | | | | 18,621 | | | | — | |
| | | | | | | | | | |
Stock Based Compensation
Effective January 1, 2006, Double Eagle adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) – Share-Based Payment (“SFAS 123(R)”), which requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options) made to employees and directors based on estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. The Company adopted SFAS 123(R) using the modified prospective transition method. Under this transition method, compensation cost recognized during the year ended December 31, 2007 includes the cost for options which were granted prior to January 1, 2006, as determined under the provisions of SFAS 123(R).
Prior to the adoption of the provisions of SFAS 123(R), Double Eagle accounted for the Plans under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”), and related interpretations and disclosure requirements established by SFAS 123 – Accounting for Stock-Based Compensation, as amended by SFAS No. 148 – Accounting for Stock-Based Compensation – Transition and Disclosure. The following table illustrates the effect on net income and earnings per share as if the fair-value recognition provisions of SFAS 123(R) were applied to all of the Company’s share-based compensation awards for the prior periods indicated:
F-10
| | | | | |
| | | For the year ended | |
| | | December 31, | |
| | | 2005 | |
| Net income, as reported | | $ | 3,965 | |
| | | | | |
| Add: Share-based employee compensation expense included in reported net income | | | 26 | |
| | | | | |
| Deduct: Total share-based employee compensation expense determined under the fair value based method for all awards | | | (686 | ) |
| | | | |
| | | | | |
| Pro forma net income | | $ | 3,305 | |
| | | | |
| Basic Earnings Per Share: | | | | |
| As reported | | $ | 0.46 | |
| Pro forma | | $ | 0.39 | |
| | | | | |
| Diluted Earnings Per Share: | | | | |
| As reported | | $ | 0.46 | |
| Pro forma | | $ | 0.38 | |
For additional information regarding our stock-based compensation plans, refer to Note 5.
Shareholder Rights Plan
On August 21, 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (“Rights Plan”). Under the Rights Plan, the Company issued a dividend of one Preferred Share Purchase Right for each outstanding share of common stock held by stockholders of record on September 4, 2007. The Rights Plan is intended to safeguard against abusive takeover tactics that limit the ability of all shareholders to realize the long-term value of their investment in Double Eagle. The Rights Plan was not adopted in response to any specific takeover effort, and will not prevent a takeover, but should encourage anyone seeking to acquire Double Eagle to negotiate with the Board prior to attempting a takeover.
Each right initially entitles stockholders to purchase a fractional share of the Company’s Series B Junior Participating Preferred Stock at an exercise price of $45. However, the rights are not immediately exercisable and will become exercisable only upon the occurrence of certain events. If a person or group acquires, or announces a tender or exchange offer that would result in the acquisition of 20% or more of the Company’s common stock while the Rights Plan remains in place, then, unless the rights are redeemed by the Company for $.01 per right, the rights will become exercisable by all rights holders, except the acquiring person or group, for shares of the Company’s common stock having a value of twice the right’s then-current exercise price.
There are 75,000 shares of the Company’s Series B Junior Participating Preferred Stock, par value $.10, authorized with no shares outstanding at December 31, 2007.
Fair Value of Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable and accounts payable are carried at a cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate. The Company marks-to-market, certain fixed price contracts accounted for as cash flow hedges with the effective portion of gains and losses, related to the changes in the fair value, recorded in accumulated other comprehensive income, a component of Stockholder’s equity. Reference is made to Note 5 of the Notes to the Consolidated Financial Statements.
F-11
Other comprehensive income
Comprehensive income (loss) consists of net loss and changes to the Company’s derivative instruments including realized and unrealized gains and losses as well as changes in fair value.
Accumulated other comprehensive income is reported as a separate component of Stockholders’ equity and is made up of the change in the fair market value of cash flow hedges. The Company’s accumulated losses on cash flow hedges at December 31, 2007 totaled $1,475 and is separately reported on the Consolidated Statements of Changes in Stockholders’ equity.
New accounting pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157 — Fair Value Measurements (“SFAS 157”). The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In December 2007, the FASB issued SFAS 157-b which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). Management is evaluating the impact of the adoption of SFAS 157 on our financial statements and has not yet determined the full effect on the Company’s financial position, results of operations or cash flows.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115 (“SFAS 159”). The statement permits companies to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of SFAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 will be effective for fiscal years beginning after November 15, 2007. Management is evaluating the impact of the adoption of SFAS 159 on our financial statements and has not yet determined the full effect on the Company’s financial position, results of operations or cash flows.
In November 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R) — Business Combinations (“SFAS 141(R)”). SFAS 141(R) changes the accounting for business combinations both at the acquisition date and in subsequent reporting periods. SFAS 141(R) requires the acquiring Company to measure almost all assets acquired and liabilities assumed in the acquisition at fair value as of the acquisition date. The standard is effective for fiscal years beginning on or after December 15, 2008 and should be applied prospectively with the exception of income taxes which should be applied retrospectively for all business combinations. Early adoption is prohibited. The adoption of SFAS 141(R) is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
In November 2007, the FASB issued Statement of Financial Accounting Standards No. 160 — Noncontrolling Interests in Consolidated Financial Statements an amendment to ARB NO. 51 (“SFAS 160”) SFAS 160 requires noncontrolling interests in a subsidiary to be initially measured at fair value and classified as a separate component of equity. The standard is effective for fiscal years beginning on or after December 15, 2008 and should be applied prospectively with the exception of the presentation and disclosure requirements which should be applied retrospectively if comparative financial statements are presented. Early adoption is prohibited. The adoption of SFAS 160 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
Subsequent Event
In accordance with the Company’s on-going risk management and to limit the credit risk associated with the above sales delivery contracts, subsequent to year-end the Company purchased NYMEX futures contracts for 3,000 Mcf per day, for the period November 1, 2008 through March 31, 2009. The price of the futures contract is $9.53. These contracts will limit the Company’s exposure to price increases above our fixed sales delivery contract prices during the winter months when prices historically rise.
As part of our cash management program, effective August 1, 2006, the Company entered into a $50 million revolving line of credit collateralized by oil and gas producing properties, replacing the previously existing revolving line of credit. The borrowing base increased to $35 million from $25 million, pursuant to the debt modification agreement dated July 1, 2007, and all outstanding balances on the line of credit mature on July 31, 2010. As of December 31, 2007, the interest rate on the line of credit, calculated in
F-12
accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 6.125%, and the balance outstanding of $3.4 million was used to fund capital expenditures primarily on our Catalina Unit expansion.
We are subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0. As of December 31, 2007, we were in compliance with all the covenants. If our covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
For the years ended December 31, 2007, 2006, and 2005, interest expense totaled $433, $480 and $14, respectively. We capitalized interest costs of $279, $293 and $43 for the years ended December 31, 2007, 2006, and 2005, respectively.
The provision for income taxes consists of:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Current taxes | | $ | — | | | $ | — | | | $ | — | |
| Deferred taxes | | | (6,143 | ) | | | 1,399 | | | | 2,043 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total income tax expense | | $ | (6,143 | ) | | $ | 1,399 | | | $ | 2,043 | |
| | | | | | | | | | |
The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2007 and 2006 were:
| | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | |
| Deferred tax assets: | | | | | | | | |
| Net operating loss carry-forward | | $ | 10,885 | | | $ | 3,671 | |
| Accrued compensation | | | — | | | | 68 | |
| Allowance for doubtful accounts | | | 198 | | | | 153 | |
| Asset retirement obligation | | | 272 | | | | 247 | |
| | | | | | | |
| | | | 11,355 | | | | 4,139 | |
| | | | | | | |
| | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | |
| Net gas imbalance receivable | | | (192 | ) | | | (265 | ) |
| Net basis difference in oil and gas properties | | | (8,275 | ) | | | (7,143 | ) |
| | | | | | | |
| Net deferred tax asset (liability) | | $ | 2,888 | | | $ | (3,269 | ) |
| | | | | | | |
At December 31, 2007, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $30.7 million, which will begin expiring in 2021.
F-13
Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:
| | | | | | | | | |
| | | For the year ended December 31, |
| | | 2007 | | 2006 |
| Expected federal tax rate | | | 35.00 | % | | | 35.00 | % |
| Effect of non-deductibility of SFAS 123(R) Incentive Stock Option Expense and other permanent differences | | | -0.74 | % | | | 4.37 | % |
| State tax rate and other | | | 0.36 | % | | | 0.52 | % |
| | | | | | | | | |
| Effective tax rate | | | 34.62 | % | | | 39.89 | % |
| | | | | | | | | |
The Company adopted the provisions of FASB Interpretation NO. 48 — Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN 48”) on January 1, 2007. The adoption of FIN 48 did not have a material effect on the Company’s financial position, results of operations or cash flows. The Company has not recorded any liabilities as of December 31, 2007 related to the adoption of FIN 48. Subsequent to adoption, there have been no changes to the Company’s assessment of uncertain tax positions.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2007, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2003 and for state and local tax authorities for years before 2002. The Company’s tax years of 2003 and forward are subject to examination by the federal and state taxing authorities.
| 4. | | Commitments and Contingencies |
Gas Sales Commitments
The Company has committed to sell a total of 3,953,000 Mcf under six third-party gas sales contracts. Should the Company be unable to deliver the gas commitment, it would be required to purchase such amounts on the open market to fulfill the terms of these contracts. Certain provisions of the contracts, including quantities, terms and prices, are:
| | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | |
| | | Contractual | | Daily | | | | | | Fixed |
| Property | | Volume | | Production | | Term | | Price/Mcf |
| Catalina | | | 517,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | |
| | | | 547,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | |
| | | | 1,094,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | |
| | | | 670,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | |
| Atlantic Rim | | | 578,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | |
| Pinedale Anticline | | | 547,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | |
| | | | | | | | | | | | | | | | | |
| Company Total | | | 3,953,000 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
F-14
Lease Commitments
In October 2004, the Company entered into a 42 month operating lease agreement for approximately 3,900 square feet of office space in Denver, Colorado. Rent expense for the Denver office was approximately $62, $58, and $61 in 2007, 2006 and 2005, respectively. The Company also maintains operating leases on various pieces of office equipment in both the Casper and Denver offices. The total annual minimum lease payments for the next five years and thereafter are:
| | | | | |
| Year ending | | Lease | |
| December 31, | | commitments | |
| 2008 | | $ | 36 | |
| 2009 | | | 10 | |
| 2010 | | | 10 | |
| 2011 | | | 9 | |
| 2012 | | | 9 | |
| Thereafter | | | — | |
| | | | |
| Total | | $ | 74 | |
| | | | |
Contingencies
Through unitization, we acquired an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the Lost Cabin Gas Processing Plant in late 2006, at a cost of approximately $2.5 million. The Madden Sour Gas Participating Area produced 10 Mcf net to our interest of gas in December 2007 from seven wells. These are long-lived wells with large producing rates and reserves. We have a 0.349% working interest in the deep participating area.
The Company has not been paid any of the proceeds generated by the sale of gas produced from the Madden Deep Unit over the period beginning the effective date of the Unit through June 30, 2007. Double Eagle began receiving payments for its share of the sales on July 1, 2007. The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Burlington Resources and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts of $292, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006.
| 5. | | Commodity Risk Management |
Risk policy and control
We control the extent of our risk management activities through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing equity hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels.
The primary objective of our commodity price risk management policy is to preserve and enhance the value of the Company’s equity gas production. In order to accomplish this objective, we may enter into equity hedge agreements, within approved limits, in order to protect our equity production from fluctuations in commodity prices and the resulting impact on cash flow, net income and earnings per share.
We have entered into various fixed delivery contracts with a third-party marketing company for our production at the Atlantic Rim and the Pinedale Anticline, which reduces our overall exposure to commodity price fluctuations. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts may limit the risk of fluctuating cash flows due to changing commodity prices.
F-15
FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities,was effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which has subsequently been amended by SFAS No. 138 and SFAS No. 149, these fixed delivery contracts qualify for the scope exception under “normal purchases and normal sales,” so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not net settle. During the year, production in the Catalina Unit (original 14 Cow Creek wells) fell below contractual volumes and Double Eagle purchased gas on the spot market in order to satisfy the fixed delivery contracts. The Company has determined that this qualifies as net settlement and accordingly, the Catalina Unit contracts no longer qualify as “normal purchases and normal sales” under SFAS No. 133. In accordance with the provisions of SFAS No. 133, and effective November 1, 2007, the Catalina Unit fixed delivery contracts are accounted for as cash flow hedges with the change in the market value being recognized as either an asset or liability in the Consolidated Balance Sheet and changes in the fair value recorded each period in other comprehensive income or current earnings. Our remaining Atlantic Rim contracts, for production from the Doty Mountain and Sun Dog Units, as well as our Pinedale Anticline contracts continue to be accounted for under the “normal purchases and normal sales exception,” as it continues to be probable that these contracts will not settle net and will result in physical delivery for the duration of the contracts.
The use of these fixed delivery contracts may expose us to the risk of financial loss if the spot price of gas exceeds the weighted average price of our contracted volumes. As with most derivative instruments, our fixed price contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but are not limited to, a letter of credit, security interest or a performance bond. Neither party in any of our fixed price contracts has required any form of security guarantee as of December 31, 2007. However, we are protected against decreases in the spot price of gas.
Hedge positions
As of December 31, 2007, we have entered into fixed delivery contracts for approximately 64% of our current daily production. The Catalina Unit contracts, identified by management and accounted for as hedges as of November 1, 2007, represent 89% of our December 2007 gross daily production in the Unit. All of these contracts are designated and accounted for as cash flow hedges with the effective portion of gains and losses, related to the changes in the fair value, recorded in accumulated other comprehensive income, a component of Stockholder’s equity. Realized gains and losses are recognized in the Consolidated Statements of Operations as a separate component of revenue when the fixed delivery contract transaction occurs.
In order to qualify as cash flow hedges, the instruments must be designated as such and the changes in fair value must be highly correlated with the changes in price of our equity production. As the fixed delivery contract is in place for the sale of gas at the inlet from our production field, management has assumed 100% effectiveness for the Catalina Unit contracts designated as cash flow hedges. During the year we recognized $304 gain on price risk management activities for the settlement of the fixed delivery contracts for the Catalina Unit for the months of November and December.
Account balances related to our equity hedging transactions as of December 31, 2007 were $474 in current liabilities from price risk management activities, $1,001 in long-term liabilities from price risk management activities and $1,475 unrealized losses in accumulated other comprehensive income. Based on the December 31, 2007 prices, management expects approximately $474 losses, included in accumulated other comprehensive income, to be reclassified to earnings during 2008.
| 6. | | Series A Cumulative Preferred Stock |
On June 12, 2007, the shareholders of the Company amended the Company’s Articles of Incorporation to allow for the issuance of 10,000,000 shares of preferred stock.
On July 5, 2007, the Company completed a public offering of 1,610,0000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share.
Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the board of directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change of Ownership or Control. Except pursuant to the special redemption upon a Change of Ownership or Control, we may not redeem the Series A Preferred Stock prior to June 30, 2012. On and after June 30, 2012, we may redeem the Series A Preferred Stock for cash at our option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the accompanying Consolidated Balance Sheets due to the following redemption provision. Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” we will be required to redeem the Series A Preferred Stock within 90 days after the date on which the Change of Ownership or Control occurred for cash, at the following price per share, plus accrued and unpaid dividends.
In the event of a liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of our common stock.
| | | | | |
| Redemption Date on or Before | | Redemption Price |
| June 30, 2008 | | $ | 26.00 | |
| June 30, 2009 | | $ | 25.75 | |
| June 30, 2010 | | $ | 25.50 | |
| June 30, 2011 | | $ | 25.25 | |
| June 30, 2012 or thereafter | | $ | 25.00 | |
Holders of the Series A Preferred Stock will generally have no voting rights. However, if cash dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or non-consecutive quarterly dividend periods, or if we fail to maintain a national market listing, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on our board of directors in addition to those directors then serving on our board until such time as the national market listing is obtained or the dividend arrearage is eliminated.
Double Eagle has outstanding stock options issued to employees under four stock option plans, approved by the Company’s stockholders (collectively “the Plans”). The options have been granted with an exercise price equal to the market price of Double Eagle’s stock on the date of grant, vest annually over various periods from two to five years of continuous service, and expire over various periods up to ten years from the date of grant.
On May 22, 2007, at the 2007 Annual Meeting of the Company, the Company’s stockholders approved the 2007 Stock Incentive Plan (“2007 Plan”). Awards under the 2007 Plan may be made to the Company’s employees, directors, consultants and other persons designated by the Compensation Committee of the Board of Directors, including awards to the Company’s named executive officers. As of December 31, 2007, the Company had not issued any awards under this plan.
Effective January 1, 2006, Double Eagle adopted the provisions of SFAS 123(R), which requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options) made to employees and directors based on
F-16
estimated fair value. The Company previously accounted for the Plans under APB 25, and related interpretations and disclosure requirements established by SFAS 123 — Accounting for Stock-Based Compensation, as amended by SFAS No. 148 — Accounting for Stock-Based Compensation — Transition and Disclosure. In March 2006, the SEC issued SAB 107, relating to SFAS 123(R). Double Eagle considered the guidance of SAB 107 in our adoption of SFAS 123 (R).
Under APB 25, no compensation expense was recorded for Double Eagle’s stock options issued under the qualified Plans. The pro forma effects on net income and earnings per share for qualified stock options were disclosed in a footnote to the financial statements. Under APB 25, compensation expense for non-qualified stock options with stock appreciation rights features was recorded utilizing the market price of Double Eagle’s stock at each period-end to determine the vested intrinsic value of the stock appreciation rights.
Under SFAS 123(R), compensation expense for equity-classified awards, such as Double Eagle’s stock options issued under the Plans, is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method.
The Company adopted SFAS 123(R) using the modified prospective transition method. Under this transition method, compensation cost recognized in 2006 includes the cost for options which were granted prior to January 1, 2006, as determined under the provisions of SFAS 123(R). There was no cumulative effect of the impact of adoption of SFAS 123(R) on liability-classified awards to the consolidated financial statements. During the years ended December 31, 2007 and 2006, total share-based compensation expense for equity-classified awards, was $362 and $460, respectively, and is reflected in “General and administrative” expense in the Consolidated Statement of Operations. As of December 31, 2007, total estimated unrecognized compensation expense from unvested stock options was $819, which is expected to be recognized over a period of five years.
The Company uses the Black-Scholes valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Double Eagle’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Double Eagle’s stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Assumptions used in estimating fair value of share-based awards for the periods indicated:
| | | | | | | | | | | | | |
| | | For the year ended December 31, |
| | | 2007 | | 2006 | | 2005 |
| Weighted-average volatility | | | 42 | % | | | 40% - 44 | % | | | 42 | % |
| Expected dividends | | | 0.00 | % | | | 0.00 | % | | | 0.00 | % |
| Expected term (in years) | | | 4.25 | | | | 2 - 4 | | | | 5 | |
| Risk-free rate | | | 4.58 | % | | | 4.68% - 5.10 | % | | | 3.50 | % |
| Expected forfeiture rate | | | 7.00 | % | | | 5% - 10 | % | | | 0.00 | % |
F-17
Summary of option activity during the years ended December 31, 2007, 2006 and 2005:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Weighted- | | | | |
| | | | | | | | | | | Average | | | | |
| | | | | | | Weighted- | | | Remaining | | | | |
| | | | | | | Average Exercise | | | Contractual Term | | | Aggregate | |
| Options: | | Shares | | | Price | | | (in years) | | | Intrinsic Value | |
| Outstanding at January 1, 2007 | | | 325,500 | | | $ | 17.64 | | | | 3.8 | | | | | |
| Granted | | | 15,000 | | | $ | 17.86 | | | | | | | | | |
| Exercised | | | (2,000 | ) | | $ | 13.56 | | | | | | | | | |
| Cancelled/expired | | | (75,000 | ) | | $ | 17.55 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Outstanding at December 31, 2007 | | | 263,500 | | | $ | 17.71 | | | | 3.4 | | | $ | 4,668 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exerciseable at December 31, 2007 | | | 133,700 | | | $ | 16.87 | | | | 2.6 | | | $ | 2,255 | |
| | | | | | | | | | | | | �� |
| | | | | | | | | | | | | | | | | |
| Outstanding at January 1, 2006 | | | 354,243 | | | $ | 15.38 | | | | 3.5 | | | | | |
| Granted | | | 112,500 | | | $ | 19.53 | | | | | | | | | |
| Exercised | | | (44,500 | ) | | $ | 7.92 | | | | | | | | | |
| Cancelled/expired | | | (96,743 | ) | | $ | 16.39 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Outstanding at December 31, 2006 | | | 325,500 | | | $ | 17.64 | | | | 3.8 | | | $ | 2,248 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exerciseable at December 31, 2006 | | | 101,700 | | | $ | 16.46 | | | | 2.8 | | | $ | 823 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Outstanding at January 1, 2005 | | | 275,843 | | | $ | 14.32 | | | | 2.5 | | | | | |
| Granted | | | 249,500 | | | $ | 18.43 | | | | | | | | | |
| Exercised | | | (93,600 | ) | | $ | 7.52 | | | | | | | | | |
| Cancelled/expired | | | (77,500 | ) | | $ | 17.00 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Outstanding at December 31, 2005 | | | 354,243 | | | $ | 15.38 | | | | 3.5 | | | $ | 1,807 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exerciseable at December 31, 2005 | | | 202,743 | | | $ | 13.48 | | | | 2.2 | | | $ | 919 | |
| | | | | | | | | | | | | |
The weighted average grant date fair value price per share of options granted during the three years ended December 31, 2007, 2006, and 2005 was $17.86, $19.53, and $18.43, respectively. During the year ended December 31, 2007, (i) the total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised was $150; and (ii) the fair value of options vested was $2,255. As of December 31, 2007, shares available for grant under the Plans were 772,614.
F-18
Stock options outstanding and currently exercisable at December 31, 2007 are:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | Options | | | | | | Options Exerciseable |
| | | | | | | Outstanding | | | | | | | | |
| | | | | | | Weighted | | | | | | | | |
| | | | | | | Average | | Weighted | | | | | | Weighted |
| | | Number of | | Remaining | | Average | | Number of | | Average |
| Range of Exercise | | Options | | Contractual Life | | Exercise Price | | Options | | Exercise Price |
| Prices per Share | | Outstanding | | (in years) | | per Share | | Exerciseable | | per Share |
| $14.00 - $ 16.60 | | | 105,000 | | | | 3.7 | | | $ | 14.44 | | | | 71,000 | | | $ | 14.65 | |
| | | | | | | | | | | | | | | | | | | | | |
| $17.86 - $ 19.55 | | | 107,500 | | | | 2.8 | | | $ | 18.74 | | | | 51,700 | | | $ | 18.79 | |
| | | | | | | | | | | | | | | | | | | | | |
| $20.21 - $ 23.61 | | | 51,000 | | | | 4.2 | | | $ | 22.30 | | | | 11,000 | | | $ | 22.14 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 263,500 | | | | 3.4 | | | $ | 17.71 | | | | 133,700 | | | $ | 16.87 | |
| | | | | | | | | | | | | | | | | | | | | |
| 8. | | Supplemental Information on Oil and Gas Producing Activities |
Capitalized Costs Relating to Oil and Gas Producing Activities
The aggregate amount of capitalized costs relating to crude oil and natural gas producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization at December 31, 2007, 2006 and 2005 are:
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Developed properties | | $ | 61,394 | | | $ | 53,677 | | | $ | 41,146 | |
| Undeveloped properties | | | 3,147 | | | | 3,313 | | | | 3,213 | |
| | | | | | | | | | |
| | | | 64,541 | | | | 56,990 | | | | 44,359 | |
| | | | | | | | | | | | | |
| Accumulated depletion and amortization | | | (22,218 | ) | | | (19,442 | ) | | | (14,854 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Net capitalized costs | | $ | 42,323 | | | $ | 37,548 | | | $ | 29,505 | |
| | | | | | | | | | |
Costs incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities
Costs incurred in property acquisitions, exploration, and development activities for the years ended December 31, 2007, 2006 and 2005 were:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Property acquisitions — unproved | | $ | 316 | | | $ | 100 | | | $ | 407 | |
| Exploration | | | 3,600 | | | | 11,304 | | | | 3,693 | |
| Development | | | 41,337 | | | | 10,046 | | | | 14,873 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total | | $ | 45,253 | | | $ | 21,450 | | | $ | 18,973 | |
| | | | | | | | | | |
F-19
Results of Operations from Oil and Gas Producing Activities
The results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2007, 2006 and 2005 were:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Operating revenues | | $ | 16,044 | | | $ | 18,228 | | | $ | 20,451 | |
| Costs and expenses: | | | | | | | | | | | | |
| Production | | | 8,274 | | | | 5,769 | | | | 6,323 | |
| Exploration | | | 15,399 | | | | 530 | | | | 747 | |
| Depletion, amortization and impairment | | | 6,691 | | | | 4,163 | | | | 3,939 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total costs and expenses | | | 30,364 | | | | 10,462 | | | | 11,009 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (loss) before income taxes | | $ | (14,320 | ) | | $ | 7,766 | | | $ | 9,442 | |
| | | | | | | | | | |
Oil and Gas Reserves (Unaudited)
The reserves at December 31, 2007, 2006 and 2005 presented below were reviewed by Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. The reserve estimates are developed using geological and engineering data and interests and burden information developed by the Company. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors.
Estimated net quantities of proved developed reserves of oil and gas for the years ended December 31, 2007, 2006, and 2005 are:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the year ended December 31, |
| | | 2007 | | 2006 | | 2005 |
| | | Oil | | Gas | | Oil | | Gas | | Oil | | Gas |
| | | (Bbl) | | (Mcf) | | (Bbl) | | (Mcf) | | (Bbl) | | (Mcf) |
| Beginning of year | | | 360,165 | | | | 48,496,719 | | | | 328,752 | | | | 47,234,335 | | | | 278,055 | | | | 34,934,746 | |
| Revisions of estimates | | | (112,093 | ) | | | (18,449,972 | ) | | | 41,546 | | | | (5,976,392 | ) | | | 7,451 | | | | (198,036 | ) |
| Extensions and discoveries | | | 178,208 | | | | 44,135,456 | | | | 2,596 | | | | 10,379,429 | | | | 58,716 | | | | 15,473,719 | |
| Sales of reserves in place | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Production | | | (13,468 | ) | | | (2,928,338 | ) | | | (12,729 | ) | | | (3,140,653 | ) | | | (15,470 | ) | | | (2,976,094 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| End of year | | | 412,812 | | | | 71,253,865 | | | | 360,165 | | | | 48,496,719 | | | | 328,752 | | | | 47,234,335 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves | | | 253,478 | | | | 44,782,553 | | | | 254,346 | | | | 30,075,467 | | | | 199,931 | | | | 23,032,277 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Percentage of proved developed reserves | | | 61 | % | | | 63 | % | | | 71 | % | | | 62 | % | | | 61 | % | | | 49 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
As of December 31, 2007, 69% of the proved developed gas reserves and 99% of the proved developed oil reserves were in producing status.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
The following information has been developed utilizing procedures prescribed by SFAS 69 “Disclosures about Oil and Gas Producing Activities” and based on natural gas and crude oil reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
F-20
The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in these calculations; (3) selection of a 10% discount rate, as required by SFAS 69, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and gas prices to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future development and production costs based upon year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory rates to future pretax net cash flows and the utilization of net operating loss carry-forwards.
Management does not rely solely upon the following information to make investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable, as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
Information with respect to the Company’s Standardized Measure:
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| Future cash inflows | | $ | 462,655 | | | $ | 246,270 | | | $ | 400,671 | |
| Future production costs | | | (102,515 | ) | | | (65,650 | ) | | | (112,025 | ) |
| Future development costs | | | (23,651 | ) | | | (17,049 | ) | | | (19,168 | ) |
| Future income taxes | | | (96,370 | ) | | | (42,578 | ) | | | (74,738 | ) |
| | | | | | | | | | |
| Future net cash flows | | | 240,119 | | | | 120,993 | | | | 194,740 | |
| 10% annual discount | | | (109,820 | ) | | | (70,960 | ) | | | (103,447 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 130,299 | | | $ | 50,033 | | | $ | 91,293 | |
| | | | | | | | | | |
Principal changes in the Standardized Measure for the years ended December 31, 2007, 2006 and 2005:
| | | | | | | | | | | | | |
| | | 2007 | | | 2006 | | | 2005 | |
| Standard measure, as of January 1, | | $ | 50,033 | | | $ | 91,293 | | | $ | 51,530 | |
| |
| Sales of oil and gas produced, net of production costs | | | (8,416 | ) | | | (12,460 | ) | | | (14,128 | ) |
| Extensions and discoveries | | | 118,002 | | | | 14,724 | | | | 43,610 | |
| Net change in prices and production costs related to future production | | | 41,821 | | | | (44,698 | ) | | | 34,004 | |
| Development costs incurred during the year | | | 9,924 | | | | 3,147 | | | | 1,290 | |
| Changes in estimated future development costs | | | (24,107 | ) | | | (10,632 | ) | | | (9,816 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| Revisions of quantity estimates | | | (50,750 | ) | | | (7,749 | ) | | | (384 | ) |
| Accretion of discount | | | 6,764 | | | | 14,315 | | | | 6,386 | |
| Net change in income taxes | | | (18,064 | ) | | | 13,299 | | | | (22,186 | ) |
| Changes in timing and other | | | 5,092 | | | | (11,206 | ) | | | 987 | |
| | | | | | | | | | |
| Aggregate Change | | | 80,266 | | | | (41,260 | ) | | | 39,763 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Standardized measure, as of December 31, | | $ | 130,299 | | | $ | 50,033 | | | $ | 91,293 | |
| | | | | | | | | | |
F-21
9.Quarterly Financial Data (Unaudited)
Summary of the unaudited financial data for each quarter for the years ended December 31, 2007 and 2006 (in thousands except per share data):
| | | | | | | | | | | | | | | | | |
| | | Fourth | | | | | | Second | | |
| | | Quarter | | Third Quarter | | Quarter | | First Quarter |
Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 4,232 | | | $ | 3,779 | | | $ | 3,417 | | | $ | 4,616 | |
| Income (loss) from operations | | $ | (10,277 | ) | | $ | (7,197 | ) | | $ | (995 | ) | | $ | 560 | |
| Net income (loss) | | $ | (6,539 | ) | | $ | (4,792 | ) | | $ | (507 | ) | | $ | 235 | |
| Net income (loss) attributable to common stock | | $ | (7,470 | ) | | $ | (5,671 | ) | | $ | (507 | ) | | $ | 235 | |
| Basic net income (loss) per common share | | $ | (0.82 | ) | | $ | (0.62 | ) | | $ | (0.06 | ) | | $ | 0.03 | |
| Fully diluted net income (loss) per common share | | $ | (0.82 | ) | | $ | (0.62 | ) | | $ | (0.06 | ) | | $ | 0.03 | |
Year ended December 31, 2006 | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 5,420 | | | $ | 4,163 | | | $ | 4,052 | | | $ | 4,593 | |
| Income from operations | | $ | 1,409 | | | $ | 526 | | | $ | 449 | | | $ | 1,311 | |
| Net income | | $ | 666 | | | $ | 341 | | | $ | 264 | | | $ | 838 | |
| Net income (loss) attributable to common stock | | $ | 666 | | | $ | 341 | | | $ | 264 | | | $ | 838 | |
| Basic net income per common share | | $ | 0.07 | | | $ | 0.04 | | | $ | 0.03 | | | $ | 0.10 | |
| Fully diluted net income per common share | | $ | 0.07 | | | $ | 0.04 | | | $ | 0.03 | | | $ | 0.10 | |
Net income (loss) for the third and fourth quarters were negatively effected by write-offs of explanatory costs and impairments of $7,182 and $9,869, respectively.
F-22
EXHIBIT INDEX
| | | |
| Exhibit No. | | Description |
| |
| 3.1(a) | | Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | |
| 3.1(b) | | Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | |
| 3.1(c) | | Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | |
| 3.1(d) | | Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001). |
| | | |
| 3.1(e) | | Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007). |
| | | |
| 3.1(f) | | Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007). |
| | | |
| 3.1(g) | | Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007). |
| | | |
| 3.1(h) | | Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007). |
| | | |
| 3.2(a) | | Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001). |
| | | |
| 3.2(b) | | Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007). |
| | | |
| 3.2(c) | | Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007). |
| | | |
| 4.1(a) | | Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011). |
| | | |
| 4.1(b) | | Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007). |
| | | |
| 4.1(c) | | Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007). |
| | | |
| 4.1(d) | | Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007). |
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| 10.1(a) | | Debt Modification Agreement, effective August 1, 2006, including Commercial Loan Agreement dated January 3, 2000, between Double Eagle Petroleum Co. and American National Bank (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, and incorporated herein by reference). |
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| 10.1(b) | | Debt Modification Agreement, effective July 1, 2007, between Double Eagle Petroleum Co. and American National Bank (incorporated by reference from Exhibit 10.1 to the Company’s Current report on Form 8-K dated July 5, 2007). |
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| Exhibit No. | | Description |
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| 10.1(c) | | Double Eagle Petroleum Co. 2007 Stock Incentive Plan, Form of Incentive Stock Option Agreement and Form of Non-Qualified Stock Option Agreement (incorporated by reference from Exhibit 10.1, 10.2 and 10.3 to the Company’s Current report on Form 8-K dated May 29, 2007). |
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| 14.1 | | Code of Business Conduct and Ethics (filed as Exhibit 99.2 to the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2004, and incorporated herein by reference). |
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| 21.1* | | Subsidiaries of registrant. |
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| 23.1* | | Consent of Hein & Associates LLP. |
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| 23.2* | | Consent of Netherland, Sewell & Associates. |
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| 31.1* | | Certification of Principal Executive Officer and Chief Financial Officer (Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| 32* | | Certification Pursuant to 18 U.S.C. Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002. |
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| * | | Filed with this Form 10-K. |
