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, 2008 |
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| o | | TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File No. 1-33571
DOUBLE EAGLE PETROLEUM CO.
(Name of registrant as specified in its charter)
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| Maryland | | 83-0214692 |
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| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
1675 Broadway, Suite 2200, Denver, CO 80202
(Address of principal executive offices) (Zip Code)
(303) 794-8445
(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
$.10 Par Value Series A Cumulative Preferred Stock | | NASDAQ Global Select Market
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.
Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 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. o
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):
| Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o
(Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting common stock held by non-affiliates of the registrant at the close of business on June 30, 2008, was $167,043,404.
The number of shares of the registrant’s common stock outstanding as of March 1, 2009 was 9,193,542 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement relating to its 2009 annual meeting of stockholders to be filed within 120 days after December 31, 2008, 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 Annual Report on Form 10-K for the year ended December 31, 2008 (the “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. Dollar amounts set forth herein are in thousands unless otherwise noted.
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, again under the symbol “DBLEP” on the NASDAQ Global Select Market on September 30, 2007. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, and the telephone number there is (303) 794-8445. Our operations office is located at 777 Overland Trail, Casper, Wyoming 82601, and the telephone number there is (307) 237-9330. Our website is www.dble.us.
Overview and Strategy
Our objective is to increase long-term stockholder value by implementing our corporate strategy of economically growing our reserves and production through the development of our existing core properties, partnering on selective exploration projects, and pursuing strategic acquisitions that expand or complement our existing operations.
Our operations currently are focused on our two core development properties located in southwestern Wyoming. 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 prospects involve properties in southwestern Wyoming and other Rocky Mountain States.
As of December 31, 2008, we had estimated proved reserves of 86.3 Bcf of natural gas and 420 MBbl of oil, or a total of 88.9 Bcfe. This represents a net increase in reserve quantities of 21% from the prior year, after adjustments for extensions and discoveries, current year production and revision of estimates. The increase in estimated proved reserves as compared to the prior year was due primarily to extensions and discoveries related to the new wells drilled in the 2008 drilling program. This increase was partially offset by revisions to reserve estimates related to existing wells and the effect of a decrease in natural gas prices at December 31, 2008 versus December 31, 2007. The average price used in the calculation of year-end reserves decreased by $1.70 per MMBtu from the December 31, 2007 price of $6.27 MMBtu. The decrease in price shortened the economic life of certain existing wells and negatively impacted our year-end reserve estimate. The reserve estimate at December 31, 2008 includes additions of 26.6 Bcfe, or 36%, of prior year reserves. The reserve additions are due primarily to our drilling program in the Atlantic Rim, including 23 new production wells in our Catalina Unit, and further development on the Pinedale Anticline. The proved oil and gas reserves, at December 31, 2008, have a PV-10 value of approximately $155.8 million, a decrease of 15% from the prior year due primarily to lower year-end pricing, offset slightly by reserve extensions and discoveries. (See reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 9). Of these reserves, 73% were proved developed and 97% were natural gas.
During 2008, we invested $65.0 million in capital expenditures related to the development of our existing properties, up from a total of $41.3 million spent in 2007. The expenditure is due primarily to the Company’s continued development of its production wells and infrastructure at the Catalina Unit project, drilling in the non-operated units of the Atlantic Rim, and continued participation on the Pinedale Anticline. Our estimated capital budget for 2009 is approximately $10-$20 million for ongoing non-operated development programs in the Pinedale Anticline (spending is largely dependent on timing and locations selected for drilling) and well production enhancement projects in the Atlantic Rim. The Company does not currently have plans to drill new production wells in the Catalina Unit in 2009. As part of our
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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 2009 capital budget is based on drilling programs which are low to medium risk development projects that provide a foundation for steady growth. Due to the tightening of the credit markets and the low forecasted natural gas price, we expect that a significant portion of available capital will be committed to non-operated projects that management believes are in the Company’s best interests to continue to participate in. The 2009 project budget estimate of $10-$20 million does not include the impact of any potential future exploration projects 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 areas of expertise, it may be pursued.
We expect to fund our 2009 capital expenditures with cash provided by operating activities and funds made available through our newly renegotiated $75 million credit facility. See the additional discussion of these events below in “Other Significant Developments since December 31, 2007”. 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/or provide further development, exploitation and exploration opportunities. In addition to potential acquisitions, we also may decide to divest of certain non-core assets or enter into strategic partnerships or joint ventures related to our assets that are not currently considered in our expected 2009 capital expenditures.
Operations
As of December 31, 2008, we owned interests in a total of 1,125 producing wells and had an acreage position of 525,493 gross acres (265,879 net), of which 387,933 gross acres (256,463 net) are undeveloped, in what we believe are natural gas prone basins of the Rocky Mountains. Two developing areas, the Atlantic Rim coal bed natural gas play and the Pinedale Anticline, accounted for 86% of our proved developed reserves as of December 31, 2008, and over 91% of our 2008 production.
As of December 31, 2008, our estimated acreage holdings by basin are:
| | | | | | | | | |
| Basin | | Gross Acres | | Net Acres |
| Washakie Basin | | | 122,581 | | | | 42,210 | |
| Huntington Basin | | | 192,975 | | | | 185,731 | |
| Greater Green River Basin | | | 38,530 | | | | 3,264 | |
| Powder River Basin | | | 32,993 | | | | 2,956 | |
| Wind River Basin | | | 50,227 | | | | 2,243 | |
| Other | | | 88,187 | | | | 29,475 | |
| | | | | | | | | |
| Total | | | 525,493 | | | | 265,879 | |
| | | | | | | | | |
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. 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 us to begin our 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. On November 30, 2007, the United States District Court issued an 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. In June 2008 and January 2009, two of the appeals by conservation groups were denied. Currently, there is one appeal from conservation groups still pending.
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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 primarily 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 2008, we recognized net sales volumes from the coal bed natural gas projects in the Atlantic Rim of 4.5 Bcfe, which represented 67% of our total 2008 natural gas equivalent sales volume. These wells have been very economic, and we intend to continue to focus our efforts on these wells in the future. Anadarko Petroleum Corporation (“Anadarko”), the operator of the Doty Mountain and Sun Dog Units, has indicated to us that it intends to focus its Atlantic Rim capital expenditures on the enhancement of current wells, which may include additional fracture stimulation. In the past, Anadarko has not performed fracture stimulation on its operated wells in the Atlantic Rim. In late 2008, Anadarko began a test pilot program to stimulate various wells in the Doty Mountain Unit. We are awaiting the final results of this pilot test.
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 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. In 2007, 33 producing wells were drilled and cased, bringing our working interest to 73.84%.
As part of our 2008 drilling program, we drilled 24 potential producing wells, 23 of which were completed, and six injections wells. One of the 24 potential producing wells was determined to be non-productive and was plugged and abandoned in the fourth quarter of 2008. This well encountered a major structural fault, resulting in the absence of the mesaverde coals at that location. While the well was plugged and abandoned, knowing the location of the fault will assist the Company in locating future well positions to avoid another dry hole. Wells beyond this fault are believed to be productive. Five of the new wells were hooked up to the sales line as of December 31, 2008. With the drilling of the 24 new wells in 2008, our working interest in the Catalina Unit changed to 68.35%. As we continue to expand the Catalina Unit, our working interest will continue to change. Upon full development of the Unit, we anticipate our working interest will be approximately 51.23%.
Production in the Catalina Unit resulted in net sales volumes to us of 4.0 Bcf in 2008 (compared to 1.5 Bcf in 2007 and 1.6 Bcf in 2006), which represented 59% of our total sales volumes for 2008.
Coal-bed methane gas wells involve removing gas trapped within the coal itself, through removal of water. Often, the wells are completely saturated with water. As water is removed, gas is able to flow to the wellhead. In 2008, we were granted a permit by the BLM to treat water removed from the wells, for release on the surface. We engaged EMIT Technologies Inc (“EMIT”) to construct a pilot waste water treatment facility within the Catalina Unit. The Company pays EMIT a fee per barrel of water processed. The EMIT plant has capacity to treat and release up to 10,000 barrels of water per day. We are currently the only company in the Atlantic Rim area to receive such a permit. The remaining water is reinjected back into the ground through injection wells.
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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. Anadarko operates this 24,817 acre unit in which we own 3,280 gross and 3,280 net acres of leasehold working interest. As of December 31, 2008, we owned an 18.00% interest in the unit. This PA and the associated working interest, including ours, will change as more wells and acreage are added to the PA. The Doty Mountain unit was established in 2005 and Anadarko operates 49 producing wells within this unit. The operator also drilled an additional 18 producing wells during 2008, which are expected to come on-line for production in the first and second quarter of 2009. During 2008, Double Eagle recognized a total net production from the Doty Mountain Unit of 194 MMcf, or an average of 529 Mcf (net) 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 we own 3,886 gross and 2,045 net acres of working interest. The Sun Dog Unit was established in 2005 and as of December 31, 2008, we owned a 9.75% working interest in the unit. In 2008, Anadarko completed and brought on 64 new wells in the unit. The operator also drilled an additional 45 wells as part of its 2008 drilling program, which are expected to come on-line for production in the first and second quarter of 2009. Upon completion of these wells, our working interest will change to approximately 8.4%. Our working interest in the PA will continue to change as more wells and acreage are added. During 2008, Double Eagle recognized a total net production from the Sun Dog Unit of 297 MMcf, or an average daily net production of 811 Mcf per day. In December 2008, the Unit averaged 1,441 Mcf per day, net.
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, 2008, 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 110 acres. The Mesa Field on the Pinedale Anticline includes 108 non-operated wells producing approximately 24% of our total production for 2008. Our net production from the Mesa Unit in 2008 was 1.5 Bcf of natural gas and 14,674 Bbls of oil.
In the Mesa “A” PA, where we have a 0.312% overriding royalty interest, there were 22 producing wells that produced a total of 192 MMcf of natural gas and 1,945 Bbls of oil in 2008 to our interest. Our net acre position of at least 1.875 net acres under a gross of 600 acres in the “A” Participating Area. The operator drilled two new wells in this unit during 2008.
In the Mesa “B” PA, 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 57 producing wells that produced 891 MMcf of natural gas and 6,597 Bbls of oil in 2008 to our interest. We have a net acreage 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 2007, the operator began drilling 18 new wells, which were hooked up for production in the second and third quarters of 2008. We also participated in the drilling of 24 additional wells in 2008. Four of the 24 wells were completed and began producing in the third quarter of 2008. The remaining 20 wells are expected to be completed in 2009 at a rate of four new wells in May, four in August, four in September, two in October, and six in November. We believe the operator will drill an additional four wells in the Mesa “B” PA in 2009.
In the Mesa “C” PA, where we have a working interest of 6.4%, 29 wells produced 464 MMcf and 6,132 Bbls of oil in 2008, net to our interest. We have 65.27 net acres under a gross of 1,000 acres in the “C” Participating Area.
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.
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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 50,227 gross acres, constituting 2,243 net acres, of leases in this Basin.
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 Inc. (“Moncrief”). In 2005, the deep Paleozoic formations, or “Sour Gas” zones, of the Madden Field and Long Butte Field were combined. 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 PA. With the current approved PA, 504.74 gross acres (84.14 net acres) are 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 a .349% working interest in the Madden Sour Gas PA 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 149 Mcf net to our interest of gas in 2008 from seven wells. These are long-lived wells with large producing rates and reserves.
We have 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 4th PA revision through June 30, 2007. We began receiving payments for our share of the sales on July 1, 2007. Along with other plaintiffs, we filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests in the Madden Deep Unit. We, and the other plaintiffs in the case, are asserting that, under the gas balancing agreement, we are entitled to receive either monetary damages or our respective shares of the gas produced from the Madden Deep Unit over at least the period from February 1, 2002, through June 30, 2007. We have recognized the sales and have recorded a related account receivable of $292, net of allowance, for uncollectible amounts for the period November 1, 2006 through June 30, 2007. Subsequent to June 20, 2007, we have recognized the sales, and have been paid the proceeds due to us. 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 ongoing 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 Waltman
The South Waltman acreage is located approximately 15 miles southeast of the Madden Anticline and three miles south of the Cave Gulch field in the Wind River Basin. The field was discovered by Chevron in 1959. We purchased interest in this leasehold in 1996. Double Eagle operates this property and owns an average working interest of 46%. In December of 2007, we drilled the Waltman 34-24 well to a total depth of 9,202 feet. Numerous gas zones were found between the depth of 4,350 feet and 8,960 feet. However, due to unfavorable hole conditions, we were only able to run casing to 6,639 feet. The well was completed at a depth of 4,349-4,374, and we intend to produce the upper gas zones by the second quarter of 2009. In August of 2008, we began drilling the Waltman 24-24 well to its total depth of 9,397 feet. Casing has been set on the well, and we are in process of completion. We expect to complete the well at a depth of between 8,500 and 9,100 feet, and to begin producing in both the upper and lower gas zones in the second quarter of 2009. We have the option on offsetting acreage to drill up to 8 additional wells in the future.
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.
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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 (367 non-operated wells). Within these areas, we participated in the drilling of 47 development wells with working interests ranging from 0.14% to 6.02% in 2008. In 2009, natural gas prices will dictate further participation in drilling proposals in this area.
Eastern Washakie Midstream Pipeline LLC
The Company owns, through its wholly-owned subsidiary, Eastern Washakie Midstream Pipeline LLC, a 13-mile pipeline and gathering assets, which connect the Catalina Unit with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. The pipeline provides us with access to the interstate gas markets, and the ability to move third party gas. We have an agreement in place for transportation and gathering of all volumes that move through our pipeline, for which we receive a third party fee per Mcf of gas transported. The pipeline has a transportation capacity of approximately 100 MMcf per day. At December 31, 2008, approximately 30 MMcf per day was being transported through the pipeline. 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.
Exploration Projects
During 2008, we did not pursue any significant exploration projects. Existing projects we are involved with are detailed below.
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 August 2009. The Company is currently in discussion with a third party regarding a possible farmout of the drilling of the Table Top Unit #1 to drill deeper to the Nugget Sandstone formation at 18,000 feet, or the Madison formation at 22,000-24,000 feet.
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.
The Cow Creek Unit Deep #2 well reached a total depth of approximately 9,800 feet in 2006 and has been temporarily plugged. The Company continues to assess the future potential of this well.
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. Although the PH State 16-1 well was completed in a similar Mesaverde Sand and Coal formation, the well was plugged and abandoned in 2008.
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.
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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. In 2008, the Company concluded that it does not plan to renew any of the Nevada leases upon their expiration, and therefore, the related capitalized undeveloped leasehold cost of $741 was written off as of December 31, 2008.
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 project. Since adopting FSP 19-1, the Company continually evaluates all existing capitalized exploratory well costs.
In accordance with FSP 19-1, in 2007, we expensed $5,773 related to the Christmas Meadows Prospect, $4,395 related to Cow Creek Unit Deep #2, and $2,759 related to PH State 16-1 in 2007.
Reserves
The reserve estimates at December 31, 2008, 2007 and 2006 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.”
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| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| |
| Proved developed oil reserves (Bbls) | | | 295,698 | | | | 253,478 | | | | 254,346 | |
| Proved undeveloped oil reserves (Bbls) | | | 124,491 | | | | 159,334 | | | | 105,819 | |
| | | | | | | | | | |
| Total proved oil reserves (Bbls) | | | 420,189 | | | | 412,812 | | | | 360,165 | |
| | | | | | | | | | | | | |
| Proved developed gas reserves (Mcf) | | | 63,007,126 | | | | 44,782,553 | | | | 30,075,467 | |
| Proved undeveloped gas reserves (Mcf) | | | 23,323,694 | | | | 26,471,312 | | | | 18,421,252 | |
| | | | | | | | | | |
| Total proved gas reserves (Mcf) | | | 86,330,820 | | | | 71,253,865 | | | | 48,496,719 | |
| | | | | | | | | | | | | |
| Total proved gas equivalents (Mcfe) (1) | | | 88,851,954 | | | | 73,730,737 | | | | 50,657,709 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Present value of estimated future net cash flows before income taxes, discounted at 10% (2) | | $ | 155,766 | | | $ | 182,594 | | | $ | 67,639 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Reconciliation of non-GAAP financial measure: | | | | | | | | | | | | |
| PV-10 | | $ | 155,766 | | | $ | 182,594 | | | $ | 67,639 | |
| | | | | | | | | | |
| Less: Undiscounted income taxes | | | (58,313 | ) | | | (96,370 | ) | | | (42,578 | ) |
| Plus: 10% discount factor | | | 24,602 | | | | 44,075 | | | | 24,972 | |
| | | | | | | | | | |
| Discounted income taxes | | | (33,711 | ) | | | (52,295 | ) | | | (17,606 | ) |
| | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 122,055 | | | $ | 130,299 | | | $ | 50,033 | |
| | | | | | | | | | |
| | |
| (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, 2008, 2007, and 2006, respectively, were $4.51 per MMBtu and $38.67 per barrel of oil; $5.99 per MMBtu and $86.67 per barrel of oil; and $4.70 per MMBtu and $51.29 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.
Production
The following table sets forth oil and gas production from our net interests in producing properties for the years ended December 31, 2008, 2007 and 2006.
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| | | | | | | | | | | | | |
| | | For the Year Ended December 31, |
| | | 2008 | | 2007 | | 2006 |
| Quantities: | | | | | | | | | | | | |
| Oil (Bbls) | | | 25,668 | | | | 13,963 | | | | 12,729 | |
| Gas (MMcf) | | | 6,560 | | | | 2,928 | | | | 3,141 | |
| | | | | | | | | | | | | |
| Average sales price | | | | | | | | | | | | |
| Oil ($/Bbl) | | $ | 77.24 | | | $ | 63.17 | | | $ | 57.90 | |
| Gas ($/Mcf) | | $ | 6.08 | | | $ | 5.18 | | | $ | 5.57 | |
| | | | | | | | | | | | | |
| Average Production Cost ($/Mcfe) | | $ | 1.13 | | | $ | 1.89 | | | $ | 1.11 | |
| Average Production Tax ($/Mcfe) | | $ | 0.70 | | | $ | 0.64 | | | $ | 0.69 | |
Delivery Contracts
We have entered into fixed delivery contracts with a third-party marketing company for portions of our production at the Atlantic Rim and the Pinedale Anticline, in order to mitigate the risk associated with downward commodity price fluctuations. The duration and size of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. As of December 31, 2008, we had fixed delivery contracts in place for 34% of our daily net production. We were able to satisfy all delivery contract volumes in 2008. However, in the months of January, September, October and November 2007, we experienced volume shortfalls due to weather and operational difficulties and were not able to deliver the contracted quantities, and we were required to purchase such amounts on the open market to fulfill the terms of these contracts.
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The following fixed delivery contracts were in place as of December 31, 2008:
FORWARD SALES CONTRACTS
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | |
| | | Contractual | | Daily | | | | | | | | | | Price |
| Property | | Volume | | Production | | Term | | Price | | Index (1) |
| |
| Catalina | | | 151,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | | | CIG |
| | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | | | CIG |
| | | | 362,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | | | CIG |
| | | | 304,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | | | CIG |
| | | | 270,000 | | | | 3,000 | | | | 11/08-03/09 | | | $8.85 floor/ | | CIG |
| | | | | | | | | | | | | | | $13.05 ceiling | | | | |
| Atlantic Rim | | | 212,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | | | CIG |
| Pinedale Anticline | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | | | CIG |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Company Total | | | 1,661,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
See Item 15, Note 5 to the Notes to the Consolidated Financial Statements for discussion regarding the accounting treatment of forward sales contracts.
In order to limit the credit risk associated with our sales delivery contracts, we purchased a NYMEX futures contract 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 our exposure to price increases above our fixed sales delivery contract prices during the winter months when prices have historically been higher.
Other Economic Hedges
In addition to the fixed delivery contracts noted in the preceding subsection, we have entered into various economic hedges to further mitigate the risk associated with commodity price fluctuations. The economic hedges are financial instruments only, and do not require us to physically deliver natural gas. As of December 31, 2008 we had economic hedges in place for 27% of our daily net production.
The following economic hedges were in place as of December 31, 2008:
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | |
| | | Contractual | | Daily | | | | | | | | | | Price |
| Type of Contract | | Volume | | Production | | Term | | Price | | Index (1) |
| |
| Costless Collar | | | 270,000 | | | | 3,000 | | | | 11/08-3/09 | | | $6.50 floor/$13.50 ceiling | | CIG |
| Option | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $10.50 floor | | NYMEX |
| Fixed Price Swap | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $2.27 CIG basis hedge | | NYMEX |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/09-12/09 | | | $ | 7.34 | | | CIG |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/11-12/11 | | | $ | 7.07 | | | CIG |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | | 7,010,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
See Item 15, Note 5 to the Notes to the Consolidated Financial Statements for discussion regarding the accounting treatment of the financial derivative contracts.
In January 2009, we entered into an additional fixed price swap contract for 12,000 Mcf per day with a CIG price of $4.30 for calendar 2010. Also in January 2009, we monetized the $10.50 NYMEX floor for proceeds of $1,351.
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Productive Wells
The following table categorizes certain information concerning the productive wells in which we owned an interest as of December 31, 2008. For purposes of this table, wells producing both oil and gas are shown in both columns. We operate 102 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 | | | | 1,006 | | | | 96.3472 | |
| Other | | | 28 | | | | 0.4394 | | | | 5 | | | | 0.0855 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 114 | | | | 6.4334 | | | | 1,011 | | | | 96.4327 | |
| | | | | | | | | | | | | | | | | |
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.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, |
| | | 2008 | | 2007 | | 2006 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Exploratory | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Gas | | | — | | | | — | | | | 1 | | | | 0.50 | | | | 2 | | | | 1.26 | |
| Dry Holes | | | — | | | | — | | | | 1 | | | | 0.98 | | | | 1 | | | | 0.33 | |
| Water Injection | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Other | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | — | | | | — | | | | 2 | | | | 1.48 | | | | 3 | | | | 1.59 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Development | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil | | | 1 | | | | 0.05 | | | | — | | | | — | | | | — | | | | — | |
| Gas | | | 178 | | | | 27.59 | | | | 223 | | | | 35.06 | | | | 87 | | | | 7.32 | |
| Dry Holes | | | 1 | | | | 0.69 | | | | — | | | | — | | | | 1 | | | | 0.21 | |
| Water Injection | | | 14 | | | | 5.42 | | | | 9 | | | | 2.72 | | | | 4 | | | | 0.82 | |
| Other | | | 5 | | | | 2.67 | | | | 1 | | | | 0.08 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 199 | | | | 36.42 | | | | 233 | | | | 37.86 | | | | 92 | | | | 8.35 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 199 | | | | 36.42 | | | | 235 | | | | 39.34 | | | | 95 | | | | 9.94 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
All our drilling activities are conducted on a contract basis with independent drilling contractors.
Finding and Development Costs
For the year ended December 31, 2008, we had additions to our proved reserves of 26.6 Bcfe, as compared to our 2008 annual production of 6.7 MMcfe. During the same period, we expended $39.2 million in finding and development costs, defined as costs incurred by the Company in 2008 related to successful exploratory wells and successful and dry development wells. This activity resulted in a one-year finding and development cost in 2008 of $1.47 per Mcfe. “Finding and development costs per Mcfe” is determined by dividing our annual exploratory and development costs, as defined, by proved reserve additions, including both developed and undeveloped reserves added during the current year (gross amounts, not net of production). We use this measure as one indicator of the overall effectiveness of exploration and development activities.
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In determining the finding and development costs per Mcfe for the years ended December 31, 2008, 2007, and 2006, total proved reserve additions consisted of (expressed in Mcfe):
| | | | | | | | | | | | | |
| | | As of December 31 | |
| | | 2008 | | | 2007 | | | 2006 | |
| Proved Developed (MMcfe) | | | 17,196 | | | | 21,888 | | | | 11,863 | |
| Proved Undeveloped (MMcfe) | | | 9,441 | | | | 23,317 | | | | (1,468 | ) |
| | | | | | | | | | |
| Total Proved Reserves Added | | | 26,637 | | | | 45,205 | | | | 10,395 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| One year finding and development costs per Mcfe | | $ | 1.47 | | | $ | 0.99 | | | $ | 1.54 | |
Proved reserves were added in each of 2008, 2007 and 2006 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 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, 2008. 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 | | | 121,101 | | | | 9,125 | | | | 109,950 | | | | 46,021 | | | | 231,051 | | | | 55,146 | |
| Nevada | | | — | | | | — | | | | 192,975 | | | | 185,731 | | | | 192,975 | | | | 185,731 | |
| Other | | | 2,906 | | | | 66 | | | | 51,612 | | | | 22,681 | | | | 54,518 | | | | 22,747 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 124,007 | | | | 9,191 | | | | 354,537 | | | | 254,433 | | | | 478,544 | | | | 263,624 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Acreage by Royalty Interest:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Developed Acres (1) | | Undeveloped Acres (2) | | Total Acres |
| State | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wyoming | | | 10,464 | | | | 162 | | | | 27,763 | | | | 1,547 | | | | 38,227 | | | | 1,709 | |
| Other | | | 3,089 | | | | 63 | | | | 5,633 | | | | 483 | | | | 8,722 | | | | 546 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 13,553 | | | | 225 | | | | 33,396 | | | | 2,030 | | | | 46,949 | | | | 2,255 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (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. |
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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 |
| 2009 | | | 26,392 | | | | 9,056 | |
| 2010 | | | 30,085 | | | | 12,275 | |
| 2011 and thereafter | | | 469,016 | | | | 244,548 | |
| | | | | | | | | |
| Total | | | 525,493 | | | | 265,879 | |
| | | | | | | | | |
Other Significant Developments since December 31, 2007
In September 2008, the Board of Directors appointed Richard Dole as our Chief Executive Officer and President. Mr. Dole continues to serve as our Chairman of the Board, a position he has held since January 2008. Mr. Dole has been a director since 2005. Mr. Dole has over 40 years of experience in the energy and finance business. Effective January 1, 2008, the Company promoted Kurtis Hooley to Chief Financial Officer and Senior Vice President. Mr. Hooley joined the Company in 2005 and has 17 years of operational and management experience. In January 2008, the Company announced the promotion of Steven Degenfelder to Senior Vice President of Exploration and New Ventures. Mr. Degenfelder has been with the Company since 1998 and has 20 years of industry experience. Also 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. In April 2008, the Company announced the appointment of Aubrey Harper to Vice President, Midstream Assets. Mr. Harper has over 30 years experience in the installation, development, commercialization and operations of pipeline, gathering, transmission and distribution systems.
Effective February 26, 2009, the Company renegotiated its $50 million revolving line of credit into a $75 million credit facility collateralized by its oil and gas producing properties and other assets, and the borrowing base increased to $45 million from $35 million. Under the modified agreement, $5 million of the $45 million borrowing base represents a term loan, which if drawn upon, becomes due July 31, 2009 and the remaining $40 million of available borrowing base will be a revolving line of credit. Any remaining outstanding balances on the line of credit mature on July 31, 2010. Under the credit facility, we are subject to both financial and non-financial covenants. The financial covenants include maintaining a current ratio of 1.0:1.0, as well as ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”), to interest, plus dividends of 1.5 to 1.0. The interest rate on the new credit facility will vary based on prevailing market rates with the minimum floor rate of 4.5%. The Company paid approximately $100 in one-time financing fees and related expenses in renegotiating this new facility.
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, 2008, there were 1,661,000 Mcf of future production volumes under fixed delivery contracts at CIG floor prices ranging from $5.47 to $8.85 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, 2008, 2007 and 2006, we sold 80%, 67%, and 75%, respectively, of our total oil and gas sales volumes to Summit Energy, LLC. 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.
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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 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 warmer summer months but decrease during the spring and fall months (“shoulder months”). Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter and summer requirements during the shoulder months, which can lessen seasonal demand fluctuations.
We have entered into various fixed delivery contracts and other economic hedges for a portion of our production, which reduces our overall exposure to seasonal demand and resulting commodity price fluctuations. The duration and size of our various derivative contracts depends on our view of market conditions, available contract prices and our operating strategy. As of December 31, 2008, we had sales delivery contracts and other derivative instruments in effect for approximately 61% of our daily net 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. Historically, access to incremental drilling equipment in certain regions has been difficult, but due to the economic downturn, rig and staff availability is not anticipated to have any material negative impact on our ability to deploy our capital drilling budget for 2009.
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 in response to economic or political conditions.
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 also are 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.
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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 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.
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 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:
| | • | | The changing political environment in which we operate |
| |
| | • | | Our ability to continue to develop our Atlantic Rim project; |
| |
| | • | | Our ability to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices; |
| |
| | • | | Our ability to maintain adequate liquidity in connection with low oil and gas prices; |
17
| | • | | Incorrect estimates of required capital expenditures; |
| |
| | • | | Increases in the cost of drilling, completion and gas collection or other costs of production and operations; |
| |
| | • | | Our ability to increase our natural gas and oil reserves; |
| |
| | • | | 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 conditions, including the current financial crisis, 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; |
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| | • | | The volatility of our stock price; 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, 2008, we had 26 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 our operations headquarters. We lease 3,932 square feet of office space in Denver, Colorado, for our principal executive 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 11(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.
c/o John Campbell, Investor Relations
1675 Broadway, Suite 2200
Denver, CO 80202
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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.
Glossary
The terms defined in this section are used throughout this Annual Report on Form 10-K.
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.
Darcy.A standard unit of measure of permeability of a porous medium.
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.
Millidarcy.One thousandth of a darcy and is a commonly used unit for reservoir rocks. See definition of darcy above.
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.
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.
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. Working interest owners also share a proportionate share of the costs of exploration, development, and production costs.
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’’
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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 develop our existing acreage due to the change in the current political environment and administration.
The anticipated growth and planned expenditures are based upon the presumption that existing leases and regulations will remain intact and allow for the future development of carbon based fuels. With the change in the United States political balance and the unclear and unknown direction that the new administration will pursue, our ability to develop known and unknown reserves in areas in which we have reserves or leases may be limited, thereby limiting our ability to grow and generate cash flows from operations.
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 additional coal bed methane drilling. 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. 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. 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. In June 2008 and January 2009, two of the appeals by conservation groups were denied. Currently there is one appeal from conservation groups still pending. It is unknown whether the third appeal will be successful, 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 ability to sustain production levels” 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 in the Rocky Mountain region of the Unites States, and in particular Wyoming, have been more adversely affected by the market volatility than other regions of the country, due to insufficient pipeline capacity and the resulting excess supply. 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 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:
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| | • | | general economic and financial market conditions; |
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| | • | | oil and natural gas prices; and |
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| | • | | 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.
Our credit facility has borrowing base restrictions, which could adversely affect our operations.
Our revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by our lenders in their sole discretion, based upon, among other things, our level of proved reserves and the projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the credit facility. Any increase in the borrowing base requires the consent of all lenders.
Upon a downward adjustment of the borrowing base, if borrowings in excess of the revised borrowing base are outstanding, we have the option to repay our indebtedness in excess of the borrowing base immediately, or in six monthly installments, or pledge additional properties as collateral. We may not have sufficient funds to make such repayments under our credit facility.
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.
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 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.
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.
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; |
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| | • | | 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
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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, net income and cash flows 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 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
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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.
We depend on key personnel.
Our success depends to a significant extent upon the efforts and abilities of our senior management and key employees. The loss of the services of these individuals could have a material adverse effect upon our business and results of operations.
Declining economic conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a potential or prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.
The trading volatility and price of our common stock may be affected by many factors.
In addition to our operating results and business prospects, many other factors affect the volatility and price of our common stock. The most important of these, some of which are outside our control, are the following:
| | • | | The current financial crisis, which has caused significant market volatility worldwide; |
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| | • | | Governmental action or inaction in light of key indicators of economic activity or events that can significantly influence U.S. financial markets, and media reports and commentary about economic or other matters, even when the matter in question does not directly relate to our business; and |
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| | • | | Trading activity in our common stock, which can be a reflection of changes in the prices for oil and gas, or market commentary or expectations about our business and overall industry. |
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 Conoco/Phillips 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. For the period from November 1, 2006 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. Subsequent to June 2007, we continued to recognize sales for our share of production and have consistently collected on the receivables due to us. 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, 2008.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURTIES.
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, 2007 through December 31, 2008 as reported by the NASDAQ Stock Market, is set forth below:
| | | | | | | | | |
| Quarter Ended | | High | | Low |
| December 31, 2008 | | $ | 13.76 | | | $ | 4.02 | |
| September 30, 2008 | | | 18.99 | | | | 12.55 | |
| June 30, 2008 | | | 19.91 | | | | 16.91 | |
| March 31, 2008 | | | 17.25 | | | | 13.05 | |
| | | | | | | | | |
| 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 | |
On February 27, 2009, the closing sales price for the Common Stock as reported by the NASDAQ Global Select Market was $3.68 per share.
Holders. On February 27, 2009, the number of holders of record of our common stock was 993.
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, 2008 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.
| | | | | | | | | | | | | |
| | | | | | | | | (c) | |
| | | | | | | | | | | Number of securities | |
| | | (a) | | | | | | | remaining available | |
| | | Number of | | | (b) | | | for future issuance | |
| | | securities to be | | | Weighted- | | | under equity | |
| | | issued upon | | | average | | | compensation plans | |
| | | exercise of | | | exercise price | | | (excluding securities | |
| | | outstanding | | | of outstanding | | | reflected in column | |
| Plan category | | options | | | options | | | (a)) | |
| Equity Compensation plans approved by security holders | | | 626,897 | | | $ | 15.68 | | | | 265,203 | (1) |
| | | | | | | | | | |
| | |
| (1) | | Represents no shares available for issuance under the 1996 Stock Option Plan, the 2000 Stock Option Plan, and 2002 Stock Option Plan; 18,099 shares available for issuance under the 2003 Stock Option and Compensation Plan and 247,104 shares available for issuance under the 2007 Stock Incentive Plan. |
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Performance graph
Comparison of Five-Year Cumulative Total Return Among
Double Eagle Petroleum Co., the Standard and Poor’s 500 Stock Index, and the Peer Group Index
Total Return (Stock Price Plus Reinvested Dividends)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | December 31, |
| | | January 1, 2004 | | 2004 | | 2005 | | 2006 | | 2007 | | 2008 |
| Double Eagle Petroleum | | $ | 100.00 | | | $ | 126.62 | | | $ | 133.77 | | | $ | 160.98 | | | $ | 103.34 | | | $ | 46.03 | |
| Peer Group | | $ | 100.00 | | | $ | 116.77 | | | $ | 166.32 | | | $ | 139.08 | | | $ | 120.76 | | | $ | 45.73 | |
| S&P500 | | $ | 100.00 | | | $ | 108.99 | | | $ | 112.26 | | | $ | 127.55 | | | $ | 132.06 | | | $ | 81.23 | |
The total return assumes that dividends were reinvested quarterly and is based on a $100 investment on December 31, 2003. During the five year period ended December 31, 2008, Double Eagle’s common stock cumulative annual growth rate was -14.4%, as compared to -14.5% for our Peer Group and -4.1% for the S&P 500 Index.
The Peer Group Index is comprised of the following companies, which are selected by Company management: American Oil & Gas, Brigham Exploration Co., Credo Petroleum Corp., Delta Petroleum Corp., FX Energy Inc., Gasco Energy Inc., and Teton Energy Corp.
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.
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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, 2008, as reported by the NASDAQ Stock Market, is set forth below:
| | | | | | | | | |
| Quarter Ended | | High | | Low |
| December 31, 2008 | | $ | 21.35 | | | $ | 14.00 | |
| September 30, 2008 | | | 19.75 | | | | 18.79 | |
| June 30, 2008 | | | 27.00 | | | | 25.50 | |
| March 31, 2008 | | | 30.20 | | | | 23.40 | |
| | | | | | | | | |
| December 31, 2007 | | $ | 26.95 | | | $ | 24.50 | |
| September 30, 2007 | | | 28.25 | | | | 23.56 | |
On February 27, 2009, the closing sales price for the Series A Preferred Stock as reported by the NASDAQ Global Select Market was $16.20 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, 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, |
| | | 2008 | | 2007 | | 2006 | | 2005 | | 2004 |
| | | (In thousands, except per share and volume data) |
Statement of Operations Information | | | | | | | | | | | | | | | | | | | | |
| Total operating revenues | | $ | 49,578 | | | $ | 17,197 | | | $ | 19,032 | | | $ | 20,496 | | | $ | 13,267 | |
| Income (loss) from operations (1) | | $ | 15,949 | | | $ | (17,909 | ) | | $ | 3,695 | | | $ | 5,985 | | | $ | 4,451 | |
| Net income (loss) | | $ | 10,381 | | | $ | (11,603 | ) | | $ | 2,109 | | | $ | 3,965 | | | $ | 4,028 | |
| Net income (loss) attributable to common stock | | $ | 6,658 | | | $ | (13,413 | ) | | $ | 2,109 | | | $ | 3,965 | | | $ | 4,028 | |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | | | $ | 0.48 | |
| Diluted | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | | | $ | 0.46 | | | $ | 0.47 | |
| | | | | | | | | | | | | | | | | | | | | |
Balance Sheet Information | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 171,989 | | | $ | 84,597 | | | $ | 64,406 | | | $ | 44,211 | | | $ | 30,969 | |
| Line of credit | | $ | 24,639 | | | $ | 3,445 | | | $ | 13,221 | | | $ | 3,000 | | | $ | — | |
| Total long-term liabilities | | $ | 33,011 | | | $ | 5,895 | | | $ | 17,184 | | | $ | 5,732 | | | $ | 583 | |
| Stockholders’ equity | | $ | 54,903 | | | $ | 28,624 | | | $ | 33,042 | | | $ | 29,778 | | | $ | 24,927 | |
| | | | | | | | | | | | | | | | | | | | | |
Cash Flow Information | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 22,904 | | | $ | 5,166 | | | $ | 10,951 | | | $ | 10,319 | | | $ | 7,434 | |
| Investing activities | | $ | (40,778 | ) | | $ | (42,056 | ) | | $ | (22,241 | ) | | $ | (16,259 | ) | | $ | (7,377 | ) |
| Financing activities | | $ | 17,749 | | | $ | 36,404 | | | $ | 10,470 | | | $ | 3,701 | | | $ | 692 | |
| | | | | | | | | | | | | | | | | | | | | |
Total proved reserves | | | | | | | | | | | | | | | | | | | | |
| Oil (MBbl) | | | 420 | | | | 413 | | | | 360 | | | | 329 | | | | 278 | |
| Gas (MMcf) | | | 86,331 | | | | 71,254 | | | | 48,497 | | | | 47,234 | | | | 34,935 | |
| MMcfe | | | 88,852 | | | | 73,731 | | | | 50,657 | | | | 49,207 | | | | 36,603 | |
| | | | | | | | | | | | | | | | | | | | | |
Net production volumes | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | | 25,668 | | | | 13,963 | | | | 12,729 | | | | 15,470 | | | | 16,886 | |
| Gas (Mcf) | | | 6,559,662 | | | | 2,928,335 | | | | 3,140,653 | | | | 2,976,094 | | | | 2,559,557 | |
| Mcfe | | | 6,713,670 | | | | 3,012,113 | | | | 3,217,027 | | | | 3,068,914 | | | | 2,660,873 | |
| | |
| (1) | | 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)”), |
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 17 of this Form 10-K.
BUSINESS OVERVIEW
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. Our core 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. We do not have any significant exploration projects at this time.
As of December 31, 2008, we had estimated proved reserves of 86.3 Bcf of natural gas and 420 MBbl of oil, or a total of 88.9 Bcfe, with a PV-10 value of approximately $155.8 (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, 2008, we controlled approximately 254,433 net undeveloped acres, representing approximately 97% of our total net acreage position.
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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; (ii) continued participation in the development of the Mesa Fields on the Pinedale Anticline and (iii) expansion of our midstream business. 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.
Developments since December 31, 2007:
The Company’s focus in 2008 was the continuing development of production and reserve growth at 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 2008, including the following:
| | • | | At our Company-operated Catalina Unit, located within the Atlantic Rim, we completed and brought on-line a total of 32 new producing wells. Twenty-seven of the new wells were drilled as part of the 2007 drilling program, and were completed and brought on-line for production during the first six months of 2008. In the third and fourth quarter of 2008, we also drilled 24 additional potential producing wells as part of our 2008 drilling season, of which five were completed and producing by December 31, 2008. One of the 24 potential producing wells drilled was determined to be a developmental dry hole and was plugged and abandoned. This well encountered a major structural fault, resulting in the absence of mesaverde coals at that location. Knowing the location of this fault of the fault will assist us in locating future well positions. Wells beyond this fault are believed to be productive. We expect to have the remaining wells completed and available for production by the end of the first quarter 2009. Upon reaching the total drilled depth of the 24 wells spud in the 2008 drilling program, our working interest in the Catalina Unit decreased from 73.84% to 68.35%. Our working interest will continue to adjust upon expansion of the unit. |
| |
| | • | | At the Sun Dog Unit, in which the Company currently has a working interest of 9.75%, 64 wells were brought on-line for production during 2008. We also participated in the drilling of 45 additional producing wells within the Sun Dog Unit. Drilling is complete on these new wells, and the operator expects the wells to be completed and producing by the end of the second quarter of 2009. At the Doty Mountain Unit, in which Double Eagle has 18.00% working interest, the operator drilled 18 new producing wells during 2008. In addition, the operator began a test pilot program for fracture stimulation of existing wells. We are currently awaiting results of this study. |
| |
| | • | | In the Mesa “B” Unit at the Pinedale Anticline, 22 new wells were brought on-line during the second and third quarters of 2008. We are also participating in the drilling of 20 additional wells. These wells were spud in the fall of 2008, and are expected to be completed in 2009 at a rate of four wells in May, four wells in August, four wells in September, two wells in October, and six wells in November. |
| |
| | • | | In the Wind River Basin, we completed the Waltman 34-24 well in June, 2008. This well is a 40-acre offset to the Chevron Waltman 96 well that has been producing since early 2007. However, due to unfavorable hole conditions, we were unable to install casing to the well’s total depth. The well was completed at a depth of 4,349-4,374 and we intend to produce the upper gas zone in the second quarter of 2009. In August 2008, we began drilling the Waltman 24-24 well. We expect to complete the well at a depth of between 8,500 and 9,100 feet, and to begin producing in both the upper and lower gas zones in the second quarter of 2009. |
| |
| | • | | On the Moxa Arch, we participated in the drilling of 47 development wells in 2008, with working interests ranging from 0.14% to 6.02% in 2008. |
Effective February 26, 2009, the Company renegotiated its $50 million revolving line of credit into a $75 million credit facility collateralized by its oil and gas producing properties and other assets, and the borrowing base increased to $45 million from $35 million. Under the agreement, $5 million of the $45 million borrowing base represents a term loan, which if drawn upon, has to be repaid on or before July 31, 2009 and the remaining $40 million of available
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borrowing base will be a revolving line of credit. Any remaining outstanding balances on the line of credit mature on July 31, 2010. Under this credit facility, we are subject to both financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0:1.0, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”) to interest plus dividends of 1.5:1.0. The interest rate on the new credit facility will vary based upon the prevailing market rates, with a floor rate of 4.5%. The Company paid approximately $100 in one-time financing fees and related expenses in renegotiating this new facility in 2009.
The Company implemented a market awareness program during 2008 in order to increase the Company’s visibility to sophisticated investors and grow the institutional shareholder base. As part of this program, the Company’s Chief Executive Officer, Chief Financial Officer, and Senior Vice-President of Exploration and New Ventures conducted a road show in six different cities across the country, and presented at four investor conferences. The Company expects to continue this effort into 2009.
In June, 2008, the Company joined the Russell 2000® and 3000® indices when Russell performed its annual reconstitution of the Russell US Indexes. Membership in the indices will remain in place for one year.
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 and other economic hedging instruments for some of our production. The duration of our various hedging instruments depends on our view of market conditions, available contract prices and our operating strategy. Use of such hedging instruments may limit the risk of fluctuating cash flows. As of December 31, 2008, we had sales delivery contracts in effect for approximately 61% of our current daily net production. |
| |
| | • | | 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. |
Development Outlook for 2009:
We expect to have $10-$20 million of capital available for development programs in 2009. The drilling activity provided for in the 2009 capital budget is primarily allocated to the projects below.
Atlantic Rim.We intend to initiate and participate in well production enhancement projects in the Catalina, Sun Dog and Doty Mountain Units during 2009. In 2008, Anadarko fracture stimulated several pilot wells within the Doty Mountain Unit. The operator intends to continue to fracture stimulate additional wells within the Doty Mountain Unit during 2009. We do not intend to drill any new production wells within the Catalina Unit in 2009, but we do expect to incur some costs as we complete and hook up 18 wells drilled during 2008, which were not producing at December 31, 2008.
Pinedale Anticline.At the Pinedale Anticline, the operator has informed us of its intentions to complete and hook up the 20 wells spud in the fall of 2008 at a rate of four wells in May, four in August, four in September, two in October, and six in November. We believe the operator will drill four additional wells in 2009.
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Other.Management intends to complete the Waltman 24-24 well, and bring on production along with the Waltman 24-34 by the second quarter of 2009. We also are evaluating the opportunity to begin drilling at least one additional well in the South Waltman field during 2009.
We believe that we have the necessary capital, personnel and available drilling equipment to successfully execute this development program.
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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 | |
| | | 2008 | | | 2007 | | | 2006 | | | 2007 to 2008 | | | 2006 to 2007 | |
Total proved reserves | | | | | | | | | | | | | | | | | | | | |
| Oil (MBbl) | | | 420 | | | | 413 | | | | 360 | | | | 2 | % | | | 15 | % |
| Gas (MMcf) | | | 86,331 | | | | 71,254 | | | | 48,497 | | | | 21 | % | | | 47 | % |
| MMcfe | | | 88,852 | | | | 73,731 | | | | 50,657 | | | | 21 | % | | | 46 | % |
| | | | | | | | | | | | | | | | | | | | | |
Net production volumes | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | | 25,668 | | | | 13,963 | | | | 12,729 | | | | 84 | % | | | 10 | % |
| Gas (Mcf) | | | 6,559,662 | | | | 2,928,335 | | | | 3,140,653 | | | | 124 | % | | | -7 | % |
| Mcfe | | | 6,713,670 | | | | 3,012,113 | | | | 3,217,027 | | | | 123 | % | | | -6 | % |
| | | | | | | | | | | | | | | | | | | | | |
Average daily production | | | | | | | | | | | | | | | | | | | | |
| Mcfe | | | 18,343 | | | | 8,252 | | | | 8,814 | | | | 122 | % | | | -6 | % |
| | | | | | | | | | | | | | | | | | | | | |
Average price per unit production | | | | | | | | | | | | | | | | | | | | |
| Oil (Bbl) | | $ | 77.24 | | | $ | 63.17 | | | $ | 57.90 | | | | 22 | % | | | 9 | % |
| Gas (Mcf) | | $ | 6.08 | | | $ | 5.18 | | | $ | 5.57 | | | | 17 | % | | | -7 | % |
| Mcfe | | $ | 6.23 | | | $ | 5.33 | | | $ | 5.67 | | | | 17 | % | | | -6 | % |
| | | | | | | | | | | | | | | | | | | | | |
Oil and gas production revenues | | | | | | | | | | | | | | | | | | | | |
| Oil revenues | | $ | 1,983 | | | $ | 882 | | | $ | 737 | | | | 125 | % | | | 20 | % |
| Gas revenues | | | 37,166 | | | | 15,162 | | | | 17,491 | | | | 145 | % | | | -13 | % |
| | | | | | | | | | | | | | | | | | |
| Total | | $ | 39,149 | | | $ | 16,044 | | | $ | 18,228 | | | | 144 | % | | | -12 | % |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Oil and gas production costs | | | | | | | | | | | | | | | | | | | | |
| Production costs | | $ | 7,601 | | | $ | 5,696 | | | $ | 3,560 | | | | 33 | % | | | 60 | % |
| Production taxes | | | 4,701 | | | | 1,933 | | | | 2,209 | | | | 143 | % | | | -12 | % |
| | | | | | | | | | | | | | | | | | |
| Total | | $ | 12,302 | | | $ | 7,629 | | | $ | 5,769 | | | | 61 | % | | | 32 | % |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Data on a per Mcfe basis | | | | | | | | | | | | | | | | | | | | |
| Average price (1) | | $ | 6.23 | | | $ | 5.33 | | | $ | 5.67 | | | | 17 | % | | | -6 | % |
| | | | | | | | | | | | | | | | | | |
| Production costs | | | 1.13 | | | | 1.89 | | | | 1.11 | | | | -40 | % | | | 70 | % |
| Production taxes | | | 0.70 | | | | 0.64 | | | | 0.69 | | | | 9 | % | | | -7 | % |
| Depletion and amortization | | | 1.65 | | | | 1.51 | | | | 1.29 | | | | 9 | % | | | 17 | % |
| | | | | | | | | | | | | | | | | | |
| Total operating costs | | | 3.48 | | | | 4.04 | | | | 3.09 | | | | -14 | % | | | 31 | % |
| | | | | | | | | | | | | | | | | | |
| Gross margin | | $ | 2.75 | | | $ | 1.29 | | | | 2.58 | | | | 113 | % | | | -50 | % |
| | | | | | | | | | | | | | | | | | |
| Gross margin percentage | | | 44 | % | | | 24 | % | | | 46 | % | | | 82 | % | | | -47 | % |
| | |
| (1) | | Our average gas price per Mcfe realized for the years ended December 31, 2008, 2007 and 2006 is calculated by summing a) production revenue received from third parties for sale of our gas, included in the oil and gas sales line item on the Consolidated Statement of Operations, b) settlement of our cash flow hedges included within oil and gas sales on the Consolidated Statement of Operations and c) realized gain/loss on our economic hedges, which due to accounting rules is included in our price risk management activities line on the Consolidated Statement of Operations, totaling $2,698, $0 and $0, for the years ended December 31, 2008, 2007 and 2006, respectively. This amount is divided by the total Mcfe volume for the period. |
Year ended December 31, 2008 compared to the year ended December 31, 2007
Oil and gas sales volume and price comparisons
During the year ended December 31, 2008, total net production increased 123% to 6,714 MMcfe as compared to the
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year ended December 31, 2007. The increase in production volumes was due largely to the addition of wells at our operated Catalina Unit and non-operated well additions in the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest at the Catalina Unit due to unitization.
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. Prior to December 21, 2007, we owned 100% of the working interest in the Cow Creek Unit. With the formation of the Catalina Unit and expansion of the PA, which included the 14 wells in the original Cow Creek Unit, as well as the 33 wells from the 2007 drilling program, our working interest decreased to 73.84% in the Catalina Unit. In October, 2008, our working interest adjusted again from 73.84% to 68.35% upon reaching certain contractual thresholds in our 2008 drilling program. This PA, and our associated working interest will continue to change as more wells and acreage are added to the PA.
During the year-ended December 31, 2008, average daily net production at the Atlantic Rim increased 161% to 12,221 Mcfe, as compared to 4,678 Mcfe in 2007, largely resulting from the addition of 33 new wells at the Catalina Unit, which were drilled in 2007. These wells were partially brought on-line during the fourth quarter of 2007, with the remaining wells coming on during the first six months of 2008. Additionally, we drilled 24 potential producing wells during 2008, of which five were completed and producing at December 31, 2008. Average daily net production for the year ended December 31, 2008 at the Catalina Unit increased 167% to 10,881 Mcfe, as compared to 4,068 Mcfe during the same prior year period. Average daily net production, net to our interest, at the Doty Mountain and Sun Dog Units increased 120% to 1,340 Mcfe, as compared to 610 Mcfe during the same prior year period. The increase was due primarily to the addition of 64 wells from the Sun Dog Unit’s 2007 drilling program. The operator has informed us that it intends to do fracture stimulations and well enhancement projects on the wells in the Sun Dog and Doty Mountain Unit in 2009.
Average daily net production in the Pinedale Anticline increased 106% for the year ended December 31, 2008, to 4,467 Mcfe, as compared to 2,166 Mcfe in the prior year. The increase was the result of the addition of 22 new wells in the Mesa “B” Unit during the second and third quarters of 2008. This increase was offset slightly by the natural production decline typical of wells in the Mesa Unit. We are also participating in the drilling of 20 additional wells at the Pinedale Anticline. These wells were spud in the fall of 2008, and are expected to be completed in 2009. The operator has informed us that these wells are expected to be brought on for production at a rate of four wells in May, four wells in August, four wells in September, two wells in October, and six wells in November.
During the year ended December 31, 2008, average daily net production at the Madden Unit decreased to 407 Mcfe as compared to 502 Mcfe in the prior year. The decrease in production was largely due to operational difficulties at the sour gas plant in the first half of 2008.
During the year ended December 31, 2008, oil and gas sales increased 144% to $39,149, as compared to the year ended December 31, 2007. This increase in oil and gas sales was driven by both the volume increase discussed above, as well as an increase in our average gas price realized. During 2008, our average gas price realized increased 17% to $6.23 from $5.33, as compared to an increase of 61% in the average CIG index price. Our price did not increase consistent with the CIG index prices due to the fixed price contracts and economic hedges we had in place throughout 2008.
Transportation and gathering revenue
Transportation and gathering revenue increased 426%, to $4,788 for the year ended December 31, 2008, as compared to $910 during the prior year. The Company receives a fee for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The growth in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit. With additional compression, the pipeline is expected to have approximately 100 MMcf per day capacity, which is expected to be sufficient to handle the development of the Catalina Unit and also additional third party gas from other non-operated properties in the Atlantic Rim proximity.
Price risk management
We recorded a net gain on our derivative contracts of $5,329 for the year ended December 31, 2008. This amount consists of an unrealized gain of $2,631, which represents the change in the fair value on our economic hedges at
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December 31, 2008, based on the future expected prices of the related commodities, and a net realized gain of $2,698 related to the settlement of some of our economic hedges. We had no derivative instruments accounted for under mark-to-market accounting at December 31, 2007.
Oil and gas production expenses, depreciation, depletion and amortization
During the year ended December 31, 2008, well production costs increased 33% to $7,601, as compared to $5,696 during the prior year, and production costs in dollars per Mcfe decreased 40%, or $0.76, to $1.13, as compared to the same prior year period. The increase in production costs is due primarily to a $1,829 million increase in the lease operating expenses at the Catalina Unit, as 33 new wells were brought on-line during the fourth quarter of 2007 and the first six months of 2008. We also brought five additional wells on-line in December 2008. In addition, transportation costs increased by $585 at the Sun Dog and Doty Mountain Units. Offsetting these increases, was a decrease in well workover costs. The decrease in production costs on a per Mcfe basis, is largely attributed to operating efficiencies gained from the increased production at the Company-operated Catalina Unit and lower well workover costs, partially offset by increased transportation costs at our non-operated Sun Dog and Doty Mountain units.
During the year ended December 31, 2008, total depreciation, depletion and amortization expenses (“DD&A”) increased 126% to $11,473, as compared to $5,068 in the prior year, and depletion and amortization related to producing assets increased 143% to $11,078, as compared to $4,550 in the prior year. The increase is due primarily to increased capital expenditures at the Catalina, Sun Dog, and Mesa units, increased production levels, and a decrease in the reserve estimates at the Doty Mountain Unit used in the calculation of DD&A. This increase was partially offset by an increase in the reserve estimates used in the calculation of DD&A at the Catalina and Mesa units, which caused a decrease in the expense recognized during the period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 9%, or $0.14, to $1.65, as compared to the prior year.
Pipeline operating costs
Pipeline operating costs totaled $2,596 for the year ended December 31, 2008, which represented an increase over the prior year of 302%. The increase is due to the expansion of the Catalina Unit and related transportation assets, and compressor rental costs.
Dry hole and impairment
Dry hole and impairment expense decreased to $1,654 for the year ended December 31, 2008, as compared to $17,631 for the year ended December 31, 2007. The 2008 expense primarily relates to a $741 write-off of our Nevada leases, as the Company has determined that we will not develop these properties in the future, and we do not plan to renew the leases upon their expiration. We also made rental payments of $340 on other undeveloped leaseholds. In 2007, the Company wrote off the following exploratory costs that did not meet the requirements for continued capitalization; 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).
General and administrative
General and administrative expenses increased 36% to $5,604 as compared to $4,133 in the prior year. The increase was due largely to higher non-cash stock-based compensation expense of $688 due to additional grants to employees, higher Board of Director related costs of $241, additional costs related to the implementation of our new accounting software of $174, additional salary and salary-related expenses due primarily to headcount additions of $289, and $61 related to the two reserve studies performed in 2008. These increases were offset partially by a $174 decrease in audit and tax related fees.
Income taxes
During the year ended December 31, 2008, we recorded an income tax expense of $5,343, as compared to an income tax benefit of $6,143 during the prior year. Our income tax expense reflects an effective book rate of 34.0% in 2008. The lower than expected effective book rate reflects the tax effect of the permanent difference caused by the stock option expense in 2008. We expect to continue to generate losses for federal income tax reporting purposes, and anticipate net income from operations in future years, which has resulted in a deferred tax position reported under U.S. 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 $30.3 million at December 31, 2008. The Company has
35
evaluated the need to provide a valuation allowance on the amount recorded as the net operating loss carry-forward, and management has concluded that no valuation allowance is required as of December 31, 2008. In reaching this conclusion, management considered that the Company generated positive net income in 2008, and by continuing to develop our core assets in the Catalina Unit, we expect to generate income in excess of our current NOL’s. Our current NOL’s do not begin to expire for 11 years. In addition, the Company routinely considers the sale of non-core assets, which is likely to generate a tax gain, as the tax cost per Mcfe of our assets is generally lower than the current market rates being paid in the open market for gas producing properties.
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, average daily net 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 net 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 was 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. Average daily net 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 was due largely to the initial recording of gas imbalances during 2006. We were in an under-produced position for the 2006 production at the Doty Mountain Unit and began receiving make up gas on August 1, 2007. We were also in an under-produced position for 2007 and 2006 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 net 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 was 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.
During the year ended December 31, 2007, average daily net 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.
During the year ended December 31, 2007, oil and gas sales 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 at the Atlantic Rim and Pinedale Anticline, as discussed above, and lower average gas prices. This decrease was partially offset by the increase in production at the Madden Deep Unit. Our average price for the year ended December 31, 2007 decreased 6% to $5.33 from $5.67 in the prior year.
Transportation and gathering revenue
During the year ended December 31, 2007, we recorded $910 in transportation and gathering revenue, as compared to $523 during the prior year. The increase in transportation revenue over the prior year was attributable to the fact the 2007 revenues included a full year of pipeline activity, while 2006 only included the period June to December 2006.
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 was 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 fulfill the fixed delivery contracts at our Catalina Unit. Transportation expenses increased by $343 at the Doty Mountain and Sun Dog Units, 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 its drilling activities during 2007.
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During the year ended December 31, 2007, DD&A 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 was 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.
Pipeline operating costs
Pipeline operating costs totaled $645 for the year ended December 31, 2007, as compared to $170 in the prior year. The increase in the pipeline operating expenses over prior year was attributable to the fact the 2007 included a full year of pipeline activity, while 2006 only included the period June to December 2006.
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 of $1,351 related to the Mad #1, $693 related to the State 1-36 and $97 related to other properties and $91 on undeveloped leaseholds.
General and administrative
During the year ended December 31, 2007, general and administrative expenses increased 4% to $4,113 as compared to $3,959 in the prior year. The increase was due largely to an increase in professional fees, including legal fees of $105, and audit and tax fees of $88, as well as an increase in salaries and employer contributions to the Company’s Simplified Employee Pension plan of $163 and to an increase in Director’s fees of $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 attributable to the early stages of the Company’s Sarbanes Oxley implementation.
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 had NOL’s of $30.7 million at December 31, 2007.
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. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, the sources of liquidity and capital have been sufficient to meet our needs and finance the growth of our business. We believe that the liquidity available from these sources will meet the anticipated short and long-term requirements of the Company. We can give no assurances that these 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.
Our Credit Facility at December 31, 2008
At December 31, 2008, the Company had a $50 million revolving line of credit, with a $35 million borrowing base, collateralized by oil and gas producing properties and other assets of the Company. All outstanding balances on this line of credit mature on July 31, 2010. As of December 31, 2008, 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 2.125%, and the balance outstanding was $24.6 million, which was used primarily to fund the 2008 drilling program at the Company-operated Catalina Unit, and the non-operated properties in the Atlantic Rim and Pinedale Anticline.
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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, as defined, of at least 1.0 to 1.0. As of December 31, 2008, we were not in compliance with the current ratio covenant due to the factors discussed below. Effective February 26, 2009, we renegotiated our $50 million revolving line of credit into a $75 million credit facility collateralized by our oil and gas producing properties and other Company assets, with the borrowing base being increased to $45 million from $35 million. Under the modified agreement, $5 million of the $45 million borrowing base represents a term loan that, if drawn upon, must be repaid on or before July 31, 2009 and the remaining $40 million of available borrowing base will be a revolving line of credit. Any remaining outstanding balances on the line of credit mature on July 31, 2010. Under the facility, we are subject to both financial and non-financial covenants. The financial covenants have been modified include maintaining a current ratio, as defined, of 1.0 to 1.0, beginning June 30, 2009, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”) to interest plus dividends, of 1.5 to 1.0. The interest rate on the new credit facility will vary based on prevailing market rates with the minimum floor rate of 4.5%.
If we had been unable to modify our credit agreement or obtain a waiver from our lenders, the lenders would have had the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding. We believe that it is probable that we will be in compliance with all covenants within the time frame cited by the modified credit agreement, and therefore, our credit facility is still appropriately classified as long-term.
Several factors have led to our December 31, 2008, financial position and covenant non-compliance. During our negotiation with our lenders, in the second and third quarters of 2008, to expand our credit facility to more closely reflect our increased reserve base, the financial markets experienced significant upheaval and changes. This turmoil in turn caused lending institutions, including ours, to delay extensions of loans or lines of credit. In 2008, we drilled 24 potential producing wells in the Catalina Unit and began installation of some infrastructure for 24 additional wells that will be drilled at a future date. We experienced a significant increase in the cost of pipe used in our wells and gathering system, due to a rise in steel prices and drilling related costs. In addition, we drilled six injection wells instead of the anticipated three injection wells, to handle the quantity of water produced from our new wells. Secondly, we saw an acceleration in timing of the joint interest billings from the non-operated properties in which we participated in their 2008 drilling program. This shift in timing contributed to the increase in current liabilities at December 31, 2008. Lastly, the sharp decline in gas prices in the fourth quarter of 2008 decreased cash flows during the period in which the majority of these capital billings were received. During the first and second quarter of 2008, we realized a price per Mcfe of $7.56 and $7.71, respectively, as compared to $4.89 in the fourth quarter of 2008.
We believe that the amounts available under the new credit facility, combined with our net cash from operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2009 capital expenditure program. Depending on the timing and amounts of future projects, we may be required to seek additional sources of capital. While we believe that we would be able to secure additional capital through financing or equity offerings, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional capital. Our borrowing base is determined based on the financial institutions assessment of current and future commodity prices, primarily natural gas available to the Company. An assessment of available borrowing base is done semi-annually. Should natural gas commodity prices significantly decrease for extended periods of time, the Company’s borrowing base could be reduced, thus limiting the future amounts of funds under the current facility.
Capital Expenditures
Our primary capital expenditures by type for the years ended December 31, 2008 and 2007 were:
| | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | | | |
| Property acquisition costs | | $ | 30 | | | $ | 316 | |
| Exploration | | | 536 | | | | 3,600 | |
| Development | | | 64,462 | | | | 41,337 | |
| | | | | | | |
| | | $ | 65,028 | | | $ | 45,253 | |
| | | | | | | |
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Year Ended December 31, 2008
Our development projects in 2008 focused our core projects in the Atlantic Rim and the Pinedale Anticline, as well as developmental drilling in the South Waltman acreage. The total cost of development at the Catalina Unit in 2008 was $44,048, net to our working interest. In 2008, we completed 27 of the 33 wells in the Catalina Unit that were not completed at December 31, 2007. In addition, we drilled an additional 24 potential producing wells and six injections wells, and installed partial infrastructure for 24 additional well sites that we expect to drill in future years. Of the 24 potential producing wells drilled in 2008, five were producing as of December 31, 2008. We expect to bring 18 more of the wells on for production in the first quarter of 2009. One of the 24 potential producing wells was determined to be a developmental dry hole.
Capital expenditures recorded at the Sun Dog and Doty Mountain Units in 2008 totaled $4,106, net to our interest. In 2008, we participated in the continuation of the 2007 drilling program in the Sun Dog Unit, and the 2008 drilling program at the Sun Dog and Doty Mountain Units. Sixty-four wells drilled during 2007 were completed in 2008 in the Sun Dog Unit, and the operator drilled an additional 63 producing wells in the units in the third and fourth quarters of 2008. These wells are expected to come on-line for production during the first and second quarters of 2009.
We also incurred capital costs of $13,007, net to our interest, related to the Pinedale Anticline development, as we. participated in the continuation of the 2007 drilling program in the Mesa Units in the Pinedale Anticline. In 2008, the operator completed 18 wells in the Mesa “B” Unit that were spud in 2007, and drilled and completed an additional four wells in second and third quarters of 2008. In the fourth quarter, the operator began drilling 20 new wells, which are expected to begin producing in the second, third and fourth quarters of 2009.
In 2008, we continued the drilling of the Waltman 34-24 in the Wind River basin, which was spud in December 2007. We completed the well at 4,349-4,374 feet and intend to produce the upper gas zones by the second quarter of 2009. In August 2008, we also drilled the Waltman 24-24 well to a depth of 9,397 feet. We expect to complete the well at a depth between 8,500 and 9,100 feet, and also intend to begin production in the second quarter of 2009. We incurred capital costs of $2,352 related to the Waltman wells in 2008, net to our interest.
We did not pursue any significant exploration activities in 2008.
Year Ended December 31, 2007
In 2007, we drilled 33 wells in the Catalina Unit, of which six were completed and hooked up by December 31, 2007, which accounted for capital costs of approximately a $20,675. Also within the Atlantic Rim, we are participated in the drilling and completion of 64 wells within the Sun Dog Unit. Capital expenditures, net to our working interest, were $426 at the Sun Dog Unit 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.
During the third quarter of 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.
Calendar 2009
For 2009, we have budgeted approximately $10-$20 million for on-going non-operated development projects at the Pinedale Anticline and well production enhancement projects in the Atlantic Rim. We do not currently plan to drill in the Catalina Unit in 2009. The 2009 capital budget does not include the impact of potential future exploration projects 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.
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Cash Flows
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 |
| | | 2008 | | 2007 | | 2006 | | 2007 to 2008 | | 2006 to 2007 |
| | | | | | | | | | | | | | | | | | | | | |
| Financial information | | | | | | | | | | | | | | | | | | | | |
| Working capital | | $ | (6,314 | ) | | $ | (7,012 | ) | | $ | (7,006 | ) | | | 10 | % | | | 0 | % |
| Line of credit | | $ | 24,639 | | | $ | 3,445 | | | $ | 13,221 | | | | 615 | % | | | -74 | % |
| Stockholders’ equity | | $ | 54,903 | | | $ | 28,624 | | | $ | 33,042 | | | | 92 | % | | | -13 | % |
| Net income (loss) attributable to common stock | | $ | 6,658 | | | $ | (13,413 | ) | | $ | 2,109 | | | | -150 | % | | | -736 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | | | | 150 | % | | | -713 | % |
| Diluted | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | | | | 150 | % | | | -713 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities | | $ | 22,904 | | | $ | 5,166 | | | $ | 10,951 | | | | 343 | % | | | -53 | % |
| Net cash used in investing activities | | $ | (40,778 | ) | | $ | (42,056 | ) | | $ | (22,241 | ) | | | -3 | % | | | 89 | % |
| Net cash provided by financing activities | | $ | 17,749 | | | $ | 36,404 | | | $ | 10,470 | | | | -51 | % | | | 248 | % |
Net cash provided by operating activities
Operating activities provided cash of $22,904 in 2008, $5,166 in 2007, and $10,951 in 2006. In 2008, the primary sources of cash were $10,381 of net income, which was net of non-cash charges of $11,648 related to DD&A and accretion expenses, and stock-based compensation expense of $1,178. In addition, we had an increase of $15,508 in accounts payable and accrued expenses related to operations and an increase of $5,343 in provision for deferred taxes. These increases were partially offset by the increase in accounts receivable from operations of $17,522 and the non-cash gain on derivative contracts of $2,631
Product prices and volumes, as well as the timely collection of receivables, are expected to have a significant influence on our future net cash provided by operating activities. In the fourth quarter of 2008, oil and gas prices dropped sharply from the record levels seen earlier in 2008. While we do have various hedges in place to protect ourselves from the fluctuating commodity prices, we did see a significant decline in our operating cash flow. Several of our hedge contracts expire in 2009 (see Contracted Volumes on page 40). If there is no substantial increase in oil and gas prices and we are unable to enter into additional hedges, we will continue to see a decline in operating cash flow in 2009 as compared to 2008 levels.
In 2008 we incurred significant capital expenditures at our Catalina Unit, drilling 24 new potential producing wells, six injection wells and the related infrastructure. We pay the vendors we contract in full, and bill our partners in the Unit for their share of the costs based upon their current working interest in the Unit. This timing issue has contributed to the increase in accounts receivable related to operations from 2007 to 2008. At this time, we do not believe that any of our partners at the Catalina Unit have long-term cash flow and credit issues and expect all receivables will be collected.
In addition, during 2008, we experienced a shift in the timing of billings from our partners at our non-operated properties in the Atlantic Rim and Pinedale Anticline as discussed in more detail above. This shift in timing contributed to the increase in accounts payable and accrued liabilities related to operations from 2007 to 2008. We expect to see this trend to continue in future years.
Net cash used in investing activities
Cash used in investing activities in 2008 totaled $40,778 and was primarily an investment in capital at our operated Catalina Unit and South Waltman field, and the non-operated Sun Dog and Doty Mountain Units in the Atlantic Rim, and the Mesa Units on the Pinedale Anticline. See the discussion of capital expenditures above. We also entered into a sale-leaseback arrangement on several gas compressors located in the Catalina Unit. Under this agreement, the vendor purchased the equipment for cash proceeds of $3,788 million, and we will lease the equipment going forward.
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Net cash used in financing activities
Cash provided by financing activities totaled $17,749 million in 2008 as compared to $36,404 in 2007 and $10,470 in 2006. The major financing inflow of cash in 2008 was from our revolving line of credit, which was used to fund expenditures related to our 2007 and 2008 drilling program. This was partially offset by four quarterly Series A Preferred Stock dividend payments totaling $3,723.
Contractual Obligations
The impact that our contractual obligations as of December 31, 2008 are expected to have on our liquidity and cash flow in future periods is:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | One year | | | 2 — 3 | | | 4 — 5 | | | More than | |
| | | Total | | | or less | | | Years | | | Years | | | 5 Years | |
| Line of credit (a) | | $ | 24,639 | | | $ | — | | | $ | 24,639 | | | $ | — | | | $ | — | |
| Interest on line of credit (b) | | | 1,777 | | | | 1,124 | | | | 653 | | | | — | | | | — | |
| Capital leases | | | 2,259 | | | | 753 | | | | 753 | | | | 753 | | | | | |
| Operating leases | | | 7,430 | | | | 1,566 | | | | 3,138 | | | | 2,725 | | | | — | |
| | | | | | | | | | | | | | | | |
| Total contractual cash commitments | | $ | 36,105 | | | $ | 3,443 | | | $ | 29,183 | | | $ | 3,478 | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | |
| (a) | | The amount listed reflects the balance outstanding as of December 31, 2008. Any balance outstanding at July 31, 2010, is due at that time. |
| |
| (b) | | The interest rate assumed on the credit facility is 4.5% per annum, which is the floor rate from our new credit facility that was effective February 26, 2009. |
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 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
Derivative Instruments
We have entered into fixed delivery contracts and other economic hedges with two energy marketing companies as part of our risk management strategy to reduce our overall exposure to downward commodity price fluctuations. The duration of our various contracts depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts limits the risk of fluctuating cash flows due to changing commodity prices. Our derivative 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 derivative contracts has required any form of security guarantee as of December 31, 2008.
As of December 31, 2008, we had sales delivery contracts and other financial instruments in effect for approximately 61% of our daily net production. We were able to satisfy all delivery contract volumes in 2008. However, in the months of January, September, October and November 2007, we experienced volume shortfalls due to weather and operational difficulties and were not able to deliver the contracted quantities, and we were required to purchase such amounts on the open market to fulfill the terms of these contracts.
41
Our outstanding forward sales contracts as of December 31, 2008 are summarized below (volume and daily production are expressed in Mcf):
FORWARD SALES CONTRACTS
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | | | | |
| | | Contractual | | | Daily | | | | | | | | | | | Price | |
| Property | | Volume | | | Production | | | Term | | | Price | | | Index (1) | |
| | | | | | | | | | | | | | | | | | | | | |
| Catalina | | | 151,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | | | CIG |
| | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | | | CIG |
| | | | 362,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | | | CIG |
| | | | 304,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | | | CIG |
| | | | 270,000 | | | | 3,000 | | | | 11/08-03/09 | | | $8.85 floor/
$13.05 ceiling | | | CIG |
| Atlantic Rim | | | 212,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | | | CIG |
| Pinedale Anticline | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | | | CIG |
| | | | | | | | | | | | | | | | | | | | |
| |
| Company Total | | | 1,661,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
In order to limit the credit risk associated with our sales delivery contracts, we purchased a NYMEX futures contract for 3,000 Mcf per day for the period November 1, 2008 through March 31, 2009.
The Company also has entered into various other derivative instruments to protect prices on future production. The terms of our other hedging instruments are summarized as follows (volume and daily production are expressed in Mcf):
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | | | | |
| | | Contractual | | | Daily | | | | | | | | | | | Price | |
| Type of Contract | | Volume | | | Production | | | Term | | | Price | | | Index (1) | |
| | | | | | | | | | | | | | | | | | | | | |
| Costless Collar | | | 270,000 | | | | 3,000 | | �� | | 11/08-3/09 | | | $6.50 floor/$13.50 ceiling | | CIG |
| Option | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $10.50 floor | | NYMEX |
| Fixed Price Swap | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $2.27 CIG basis hedge | | NYMEX |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/09-12/09 | | | $ | 7.34 | | | CIG |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/11-12/11 | | | $ | 7.07 | | | CIG |
| | | | | | | | | | | | | | | | | | | | |
| |
| Total | | | 7,010,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
The costless collars have the effect of providing a protective floor while allowing us to share in upward pricing movements. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. We have also entered into an economic hedge that locks in the basis differential between the NYMEX index and the CIG spot price we receive upon sale of gas. Due to pipeline capacity constraints in the Rocky Mountain region, we saw the basis differential as high as $6.32 during 2008. We have two fixed price swap contracts for calendar 2009 and 2011 for 8,000 Mcf per day at a CIG price of $7.34 and $7.07, respectively.
Subsequent to December 31, 2008, we entered into a natural gas swap agreement for 12,000 Mcf per day at a CIG price of $4.30 for calendar 2010. In January 2009, we monetized the $10.50 NYMEX floor for proceeds of $1,351.
See Item 15, Note 5 to the Notes to the Consolidated Financial Statements for additional discussion of hedge accounting.
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Other Volumes Contracted
We also have a transportation and gathering agreement for all production volumes through our pipeline, for which we receive a third party fee per Mcf of gas transported.
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, and lease acquisition costs are 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.
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
43
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 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. We engage independent reserve engineers to review a substantial portion of our reserves. In 2008, 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”).
Impairment of Long-Lived Assets
The Company reviews the carrying values of its long-lived assets periodically, or 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. The Company recorded non-cash impairment charges on properties included in Developed Properties of $0, $2,141, and $0 for the years ended December 31, 2008, 2007 and 2006, respectively. In addition, the Company recorded impairment charges of $743, $91, and $10 on undeveloped leaseholds the years ended December 31, 2008, 2007 and 2006, respectively.
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 Consolidated Statement of Operations impact of these estimates is reflected in our production costs and occurs over the remaining life of our oil and gas properties.
Derivative Instruments
We use derivative instruments to hedge exposures to oil and gas production cash-flow risks caused by fluctuating commodity prices. All derivatives are initially, and subsequently, measured at estimated fair value and recorded as liabilities or assets on the Consolidated Balance Sheet. Certain of our derivative instruments qualify for cash flow hedge accounting, under which the change in fair value is recorded as a component of accumulated other comprehensive income and is subsequently reclassified into earnings as the contract settles. For derivative contracts that do not qualify as cash flow hedges accounting, changes in the estimated fair value of the contracts are recorded as unrealized gains and losses in the price risk management activities line item in the accompanying Consolidated Statement of Operations.
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 meet the definition of a derivative instrument and to determine the fair value of each instrument identified.
Fair Value of Measurements
The Company adopted the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157 — Fair Value Measurements (“SFAS 157”) for financial instruments on January 1, 2008. See additional discussion underRecently Issued Accounting Pronouncements.
SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. In determining the fair value of the Company’s derivative instruments, the Company considers quoted market prices in active markets, the credit rating of each counterparty, and the Company’s own credit rating.
44
The Company then compares its valuation estimates against mark-to-market statements from counterparties for reasonableness.
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
Share-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 and stock awards) 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 $1,178 during the year ended December 31 2008. As of December 31, 2008, total estimated unrecognized compensation expense from unvested stock options and stock grants was $3,576, 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 stock option. 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.
We measure the fair value of the stock awards based upon the fair market value of our common stock on the date of grant and recognize any resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. We recognize these compensation costs net of a forfeiture rate, if applicable, and recognize the compensation costs for only those shares expected to vest. We typically estimate forfeiture rates based on historical experience, while also considering the duration of the vesting term of the option or stock award. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation expense could be significantly different from what we have recorded in the current period.
Recently Issued Accounting Pronouncements
In September 2006, the FASB issued 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. In February 2008, the FASB issued Staff Position No. FAS 157-2 which proposed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On January 1, 2008, the Company elected to implement this Statement with the one-year deferral. Given the nature of the Company’s current financial instruments, the adoption of SFAS No. 157 did not have a material impact on the Company’s financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The Company is in the process of evaluating this standard with respect to its effect on nonfinancial assets and liabilities and has not yet determined the impact that it will have on its financial statements upon full adoption in 2009.
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. The Company adopted SFAS No. 159 on January 1, 2008. The adoption of SFAS No. 159 did not have a material effect on our financial condition, results of operations or cash flows as the Company did not elect this fair value option.
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New Accounting Pronouncements
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 — Non-controlling Interests in Consolidated Financial Statements, an amendment to ARB NO. 51 (“SFAS 160”). SFAS 160 requires non-controlling 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.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 — Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 does not change current accounting treatment of derivatives, but requires expanded disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance and cash flows. The standard is effective for fiscal years and interim periods beginning after November 15, 2008 and early adoption is encouraged.
In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have an impact on the Company’s financial position, results of operations or cash flows.
In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements, is a broader definition of reserves, which allows consideration of new technologies. In addition, oil and gas reserves will be reported using an average price based on the prior 12-month period, rather than year-end prices and allow companies to disclose their probable and possible reserves to investors. The new rule is expected to be effective for years ending on or after December 31, 2009. The Company is in the process of evaluating the effect of these new requirements, and has not yet determined the impact that it will have on its financial statements upon full adoption on December 31, 2009.
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risks
At December 31, 2008 we had $24,639 outstanding on our $50 million revolving line ($35 million borrowing base). 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, 2008, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $246 before taxes. As of December 31, 2008, the interest rate on the line of credit, calculated in accordance with the agreement of 1.125% below the posted Wall Street Journal Prime Rate, was 2.125%.
Effective February 26, 2009, we renegotiated our $50 million revolving line of credit into a $75 million credit facility ($45 million borrowing base). The interest rate on the new credit facility will vary based on prevailing market rates with the minimum floor rate of 4.5%.
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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, including many factors outside of our control. For the year ended December 31, 2008, our income before income taxes would have changed by $1,028 for each $0.50 change per Mcf in natural gas prices and $22 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.
As of December 31, 2008, we had sales delivery contracts and other financial instruments in effect for approximately 61% of our daily net production.
Our outstanding forward sales contracts as of December 31, 2008 are summarized below (volume and daily production are expressed in Mcf):
FORWARD SALES CONTRACTS
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | | | | |
| | | Contractual | | | Daily | | | | | | | | | | | Price | |
| Property | | Volume | | | Production | | | Term | | | Price | | | Index (1) | |
| | | | | | | | | | | | | | | | | | | | | |
| Catalina | | | 151,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | | | CIG |
| | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | | | CIG |
| | | | 362,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | | | CIG |
| | | | 304,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | | | CIG |
| | | | 270,000 | | | | 3,000 | | | | 11/08-03/09 | | | $8.85 floor/
$13.05 ceiling | | | CIG |
| Atlantic Rim | | | 212,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | | | CIG |
| Pinedale Anticline | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | | | CIG |
| | | | | | | | | | | | | | | | | | | | |
| Company Total | | | 1,661,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
We were able to satisfy all delivery contract volumes in 2008. However, in the months of January, September, October and November 2007, we experienced volume shortfalls due to weather and operational difficulties and were not able to deliver the contracted quantities, and we were required to purchase such amounts on the open market to fulfill the terms of these contracts. In order to limit the credit risk associated with our sales delivery contracts, we purchased a NYMEX futures contract for 3,000 Mcf per day for the period November 1, 2008 through March 31, 2009.
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The Company also has entered into various other derivative instruments to protect prices on future production. The terms of our other hedging instruments are summarized as follows (volume and daily production are expressed in Mcf):
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | | | | |
| | | Contractual | | | Daily | | | | | | | | | | | Price | |
| Type of Contract | | Volume | | | Production | | | Term | | | Price | | | Index (1) | |
| | | | | | | | | | | | | | | | | | | | | |
| Costless Collar | | | 270,000 | | | | 3,000 | | | | 11/08-3/09 | | | $6.50 floor/$13.50 ceiling | | CIG |
| Option | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $10.50 floor | | NYMEX |
| Fixed Price Swap | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $2.27 CIG basis hedge | | NYMEX |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/09-12/09 | | | $ | 7.34 | | | CIG |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/11-12/11 | | | $ | 7.07 | | | CIG |
| | | | | | | | | | | | | | | | | | | | |
| |
| Total | | | 7,010,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
The costless collars have the effect of providing a protective floor while allowing us to share in upward pricing movements. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. We have also entered into an economic hedge that locks in the basis differential between the NYMEX index and the CIG spot price we receive upon sale of gas. We have two fixed price swap contracts for calendar 2009 and 2011 for 8,000 Mcf per day at a CIG price of $7.34 and $7.07, respectively.
Subsequent to December 31, 2008, we entered into a natural gas swap agreement for 12,000 mcf per day at a CIG price of $4.30. The term of the agreement is for calendar 2010. In January 2009, we monetized the $10.50 NYMEX floor for proceeds of $1,351.
As with most derivative instruments, our derivative 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 derivative contracts has required any form of security guarantee as of December 31, 2008.
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 Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 11a-15(e) and 15d-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.
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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 11a-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, 2008. 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. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.
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, 2008 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 (the “Company”) internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanyingManagement’s Report on 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 U.S. 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 U.S. 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, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
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 12, 2009, expressed an unqualified opinion.
/s/HEIN& ASSOCIATES LLP
Denver, Colorado
March 12, 2009
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ITEM 9B. OTHER INFORMATION
None.
PART III
Pursuant to instruction G(3) to Form 10-K, the following Items 10,11,12,11 and 14 are incorporated by reference to the information provided in Double Eagle’s definitive proxy statement for the 2009 annual meeting of stockholders to be filed within 120 days from December 31, 2008.
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 met by all executive officers and directors of the Company, and to the Company’s knowledge, all persons who own more than 10% of our common stock or preferred stock.
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). |
| | | |
| 3.1(b) | | Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the |
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| | | |
| Exhibit No. | | Description |
| | | |
| | | 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). |
52
| | | |
| Exhibit No. | | Description |
| | | |
| 10.1(c) | | Credit Agreement dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by reference from Exhibit 10.1 to the Company’s Current report on Form 8-K dated February 26, 2009). |
| | | |
| 10.1(d) | | Promissory Term Note dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. (incorporated by reference from Exhibit 10.2 to the Company’s Current report on Form 8-K dated February 26, 2009). |
| | | |
| 10.1(e) | | Revolving Notes dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by reference from Exhibit 10.3 to the Company’s Current report on Form 8-K dated February 26, 2009). |
| | | |
| 10.1(f) | | 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). |
| | | |
| 10.1(g) | | Employment Agreement between the Company and Richard Dole, dated September 4 2008 (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated September 9, 2008). |
| | | |
| 10.1(h) | | Employment Agreement between the Company and Kurtis Hooley, dated September 4, 2008 (incorporated by reference from Exhibit 10.2 of the Company’s Current Report of Form 8-K dated September 9, 2008). |
| | | |
| 10.1(i) | | Employment Agreement between the Company and D. Steven Degenfelder, dated September 4, 2008 (incorporated by reference from Exhibit 10.3 of the Company’s Current Report of Form 8-K dated September 9, 2008). |
| | | |
| 10.1(j) | | Employment Agreement between the Company and Robert Reiner, dated September 4, 2008 (incorporated by reference from Exhibit 10.4 of the Company’s Current Report of Form 8-K dated September 9, 2008). |
| | | |
| 10.1(k) | | Employment Agreement between the Company and Aubrey Harper, dated September 4, 2008 (incorporated by reference from Exhibit 10.5 of the Company’s Current Report of Form 8-K dated September 9, 2008). |
| | | |
| 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, Inc. |
| | | |
| 31.1* | | Certification of Principal Executive Officer and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | |
| 31.2* | | Certification of Principal Accounting Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | |
| 32* | | Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to section 906 of the Sarbanes- Oxley Act of 2002. |
| | |
| * | | Filed with this Form 10-K. |
53
SIGNATURES
Pursuant to the requirements of Section 11 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 12, 2009 | /s/ Richard Dole | |
| | Richard Dole | |
| | Chief Executive Officer | |
| |
| | | |
| Date: March 12, 2009 | /s/ Kurtis S. Hooley | |
| | Kurtis S. Hooley | |
| | Chief Financial 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 12, 2009 | /s/ Richard Dole | |
| | Principal Executive Officer | |
| | Chief Executive Officer | |
| |
| | | |
| Date: March 12, 2009 | /s/ Kurtis S. Hooley | |
| | Chief Financial Officer | |
| | Principal Accounting Officer | |
| |
| | | |
| Date: March 12, 2009 | /s/ Sigmund Balaban | |
| | Sigmund Balaban, Director | |
| | | |
| | | |
| Date: March 12, 2009 | /s/ Roy G. Cohee | |
| | Roy G. Cohee, Director | |
| | | |
| | | |
| Date: March 12, 2009 | /s/ Brent Hathaway | |
| | Brent Hathaway, Director | |
| | | |
| |
54
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Double Eagle Petroleum Co.
We have audited the accompanying consolidated balance sheets of Double Eagle Petroleum Co. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 12, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/HEIN& ASSOCIATES LLP
Denver, Colorado
March 12, 2009
F-1
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of dollars except share and per share data)
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2008 | | | 2007 | |
| ASSETS | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | — | | | $ | 125 | |
| Cash held in escrow | | | 605 | | | | 719 | |
| Accounts receivable, net | | | 21,381 | | | | 3,664 | |
| Assets from price risk management | | | 14,290 | | | | — | |
| Other current assets | | | 3,513 | | | | 586 | |
| | | | | | | |
| Total current assets | | | 39,789 | | | | 5,094 | |
| | | | | | | |
| Oil and gas properties and equipment, successful efforts method: | | | | | | | | |
| Developed properties | | | 133,516 | | | | 61,394 | |
| Wells in progress | | | 18,518 | | | | 29,768 | |
| Gas transportation pipeline | | | 5,465 | | | | 5,465 | |
| Undeveloped properties | | | 2,907 | | | | 3,147 | |
| Corporate and other assets | | | 1,920 | | | | 1,585 | |
| | | | | | | |
| | | | 162,326 | | | | 101,359 | |
| Less accumulated depreciation, depletion and amortization | | | (35,253 | ) | | | (24,785 | ) |
| | | | | | | |
| Net properties and equipment | | | 127,073 | | | | 76,574 | |
| | | | | | | |
| Deferred tax asset | | | — | | | | 2,873 | |
| Assets from price risk management | | | 5,029 | | | | — | |
| Other assets | | | 98 | | | | 56 | |
| | | | | | | |
| TOTAL ASSETS | | $ | 171,989 | | | $ | 84,597 | |
| | | | | | | |
| | | | | | | | | |
| LIABILITIES, PREFERRED STOCK, AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 35,488 | | | $ | 8,584 | |
| Accrued expenses | | | 6,794 | | | | 2,079 | |
| Liabilities from price risk management | | | — | | | | 474 | |
| Accrued production taxes | | | 3,017 | | | | 969 | |
| Capital lease obligations, current portion | | | 522 | | | | — | |
| Other current liabilities | | | 282 | | | | — | |
| | | | | | | |
| Total current liabilities | | | 46,103 | | | | 12,106 | |
| | | | | | | | | |
| Line of credit | | | 24,639 | | | | 3,445 | |
| Asset retirement obligation | | | 4,208 | | | | 1,449 | |
| Liabilities from price risk management | | | — | | | | 1,001 | |
| Deferred tax liability | | | 2,470 | | | | — | |
| Capital lease obligations, long-term portion | | | 1,078 | | | | — | |
| Other long-term liabilities | | | 616 | | | | — | |
| | | | | | | |
| Total liabilities | | | 79,114 | | | | 18,001 | |
| | | | | | | |
| Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of December 31, 2008 and December 31, 2007 | | | 37,972 | | | | 37,972 | |
| | | | | | | |
| | | | | | | | | |
| Stockholders’ equity: | | | | | | | | |
| Common stock, $0.10 par value; 50,000,000 shares authorized; 9,192,356 and 9,148,105 shares issued and outstanding as of December 31, 2008 and December 31, 2007, respectively | | | 919 | | | | 915 | |
| Additional paid-in capital | | | 35,122 | | | | 33,670 | |
| Retained earnings (accumulated deficit) | | | 2,172 | | | | (4,486 | ) |
| Accumulated other comprehensive income (loss) | | | 16,690 | | | | (1,475 | ) |
| | | | | | | |
| Total stockholders’ equity | | | 54,903 | | | | 28,624 | |
| | | | | | | |
| TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS’ EQUITY | | $ | 171,989 | | | $ | 84,597 | |
| | | | | | | |
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, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Revenues | | | | | | | | | | | | |
| Oil and gas sales | | $ | 39,149 | | | $ | 16,044 | | | $ | 18,228 | |
| Transportation and gathering revenue | | | 4,788 | | | | 910 | | | | 523 | |
| Price risk management activities | | | 5,329 | | | | — | | | | — | |
| Other income | | | 312 | | | | 243 | | | | 281 | |
| | | | | | | | | | |
| Total revenues | | | 49,578 | | | | 17,197 | | | | 19,032 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Costs and expenses | | | | | | | | | | | | |
| Production costs | | | 7,601 | | | | 5,696 | | | | 3,560 | |
| Production taxes | | | 4,701 | | | | 1,933 | | | | 2,209 | |
| Exploration expenses including dry hole costs | | | 911 | | | | 15,399 | | | | 530 | |
| Pipeline operating costs | | | 2,596 | | | | 645 | | | | 170 | |
| Impairment of equipment and properties | | | 743 | | | | 2,232 | | | | — | |
| General and administrative | | | 5,604 | | | | 4,133 | | | | 3,959 | |
| Depreciation, depletion and amortization | | | 11,473 | | | | 5,068 | | | | 4,909 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total costs and expenses | | | 33,629 | | | | 35,106 | | | | 15,337 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (loss) from operations | | | 15,949 | | | | (17,909 | ) | | | 3,695 | |
| | | | | | | | | | | | | |
| Interest (expense) income, net | | | (225 | ) | | | 163 | | | | (187 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (loss) before income taxes | | | 15,724 | | | | (17,746 | ) | | | 3,508 | |
| | | | | | | | | | | | | |
| (Provision) benefit for deferred income taxes | | | (5,343 | ) | | | 6,143 | | | | (1,399 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | 10,381 | | | $ | (11,603 | ) | | $ | 2,109 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Preferred stock dividends | | | (3,723 | ) | | | (1,810 | ) | | | — | |
| | | | | | | | | | |
| Net income (loss) attributable to common stock | | $ | 6,658 | | | $ | (13,413 | ) | | $ | 2,109 | |
| | | | | | | | | | |
| Net income (loss) per common share: | | | | | | | | | | | | |
| Basic | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | |
| | | | | | | | | | |
| Diluted | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Weighted average shares outstanding: | | | | | | | | | | | | |
| Basic | | | 9,159,865 | | | | 9,114,622 | | | | 8,632,567 | |
| | | | | | | | | | |
| Diluted | | | 9,161,985 | | | | 9,114,622 | | | | 8,655,587 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the consolidated financial statements.
F-3
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Amounts in thousands of dollars)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Cash flows from operating activities: | | | | | | | | | | | | |
| Net income (loss) | | $ | 10,381 | | | $ | (11,603 | ) | | $ | 2,109 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | |
| Depreciation, depletion, amortization and accretion of asset retirement obligation | | | 11,648 | | | | 5,062 | | | | 4,909 | |
| Abandonment of non-producing properties and leases | | | 743 | | | | 14,941 | | | | 20 | |
| Bad debt expense | | | — | | | | 559 | | | | — | |
| Non cash revenue from carried interest | | | (1,665 | ) | | | — | | | | — | |
| Impairment of equipment and properties | | | — | | | | 2,234 | | | | — | |
| Provision for deferred taxes | | | 5,343 | | | | (6,143 | ) | | | 1,399 | |
| Directors fees paid in stock | | | 128 | | | | 90 | | | | 97 | |
| Non-cash gain on derivative contracts | | | (2,631 | ) | | | — | | | | — | |
| Non-cash employee stock option expense | | | 1,050 | | | | 362 | | | | 460 | |
| Gain on sale of working interest in non-producing property | | | (90 | ) | | | (98 | ) | | | — | |
| Changes in current assets and liabilities: | | | | | | | | | | | | |
| Decrease (Increase) in deposit held in escrow | | | 114 | | | | (12 | ) | | | (707 | ) |
| Decrease (Increase) in accounts receivable | | | (17,522 | ) | | | 824 | | | | (799 | ) |
| Decrease (Increase) in other current assets | | | (2,871 | ) | | | 223 | | | | (591 | ) |
| Increase (Decrease) in accounts payable | | | 15,461 | | | | (1,890 | ) | | | 4,118 | |
| Increase in accrued expenses | | | 47 | | | | 739 | | | | 502 | |
| Increase (Decrease) in accrued production taxes | | | 2,768 | | | | (122 | ) | | | (566 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET CASH PROVIDED BY OPERATING ACTIVITIES | | | 22,904 | | | | 5,166 | | | | 10,951 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | |
| Additions of producing properties and equipment | | | (44,378 | ) | | | (41,550 | ) | | | (21,861 | ) |
| Additions of corporate and non-producing properties | | | (878 | ) | | | (750 | ) | | | (390 | ) |
| Proceeds from sales of properties and assets | | | 4,478 | | | | 244 | | | | — | |
| (Additions) reductions of other assets | | | — | | | | — | | | | 10 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET CASH USED IN INVESTING ACTIVITIES | | | (40,778 | ) | | | (42,056 | ) | | | (22,241 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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 | | | (3,723 | ) | | | (1,810 | ) | | | — | |
| Net borrowings/(payments) on line of credit | | | 21,194 | | | | (9,776 | ) | | | 10,221 | |
| Proceeds from Company stock plans | | | 278 | | | | 28 | | | | 353 | |
| Exercise of options/vesting of restricted shares | | | — | | | | — | | | | (104 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| NET CASH PROVIDED BY FINANCING ACTIVITIES | | | 17,749 | | | | 36,404 | | | | 10,470 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Change in cash and cash equivalents | | | (125 | ) | | | (486 | ) | | | (820 | ) |
| Cash and cash equivalents at beginning of period | | | 125 | | | | 611 | | | | 1,431 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | — | | | $ | 125 | | | $ | 611 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Supplemental disclosure of cash and non-cash transactions: | | | | | | | | | | | | |
| Cash paid for interest | | $ | 657 | | | $ | 426 | | | $ | 490 | |
| Interest capitalized | | $ | 705 | | | $ | 279 | | | $ | 293 | |
| Receivables due from joint-interest partners related to change in working interest | | $ | 193 | | | $ | — | | | $ | — | |
| Share-based compensation expense | | $ | 1,178 | | | $ | 452 | | | $ | 557 | |
| Additions to developed properties included in current liabilities | | $ | 20,299 | | | $ | 4,908 | | | $ | 6,183 | |
| Additions to developed properties for retirement obligations | | $ | 2,584 | | | $ | 757 | | | $ | 171 | |
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 (loss) | | | Equity | |
| Balance at January 1, 2006 | | | 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 loss | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | | | — | | | | — | | | | — | | | | (11,603 | ) | | | — | | | | (11,603 | ) |
| Net change in derivative instrument fair value, net of tax benefit of $0 | | | — | | | | — | | | | — | | | | — | | | | (1,475 | ) | | | (1,475 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive 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 | |
| Comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | — | | | | — | | | | — | | | | 10,381 | | | | — | | | | 10,381 | |
| Net change in derivative instrument fair value, net of tax benefit of $0 | | | — | | | | — | | | | — | | | | — | | | | 18,253 | | | | 18,253 | |
| Reclassification to earnings, net of tax benefit of $0 | | | — | | | | — | | | | — | | | | — | | | | (88 | ) | | | (88 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 28,546 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Stock options exercised | | | 15,000 | | | | 1 | | | | 275 | | | | — | | | | — | | | | 276 | |
| Share-based compensation expense | | | — | | | | — | | | | 1,050 | | | | — | | | | — | | | | 1,050 | |
| Directors fees paid in stock | | | 7,805 | | | | 1 | | | | 127 | | | | — | | | | — | | | | 128 | |
| Issuance of common shares upon restricted stock vesting | | | 21,446 | | | | 2 | | | | — | | | | — | | | | — | | | | 2 | |
| Dividends declared & paid on preferred stock | | | — | | | | — | | | | — | | | | (3,723 | ) | | | — | | | | (3,723 | ) |
| | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2008 | | | 9,192,356 | | | $ | 919 | | | $ | 35,122 | | | $ | 2,172 | | | $ | 16,690 | | | $ | 54,903 | |
| | | | | | | | | | | | | | | | | | | |
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.
The Company also has a wholly-owned subsidiary, Eastern Washakie Midstream LLC (“EWM”), which owns and operates a 13-mile intrastate gas pipeline (the “Pipeline”). Beginning in 2006, Double Eagle presented consolidated financial statements to reflect the consolidation of the two entities for reporting purposes (collectively, the “Company”). The Company has an agreement with EWM, under which the Company pays a fee to EWM to gather and compress gas produced at the Catalina Unit. Our share of the fee related to gas gathering is 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 2008 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.
Cash Held in Escrow
The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 (Christmas Meadows) exploration project. The unexpended portion of the deposits at December 31, 2008 and 2007 totaled $605 and $719, respectively.
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 $0, $559 and $0 for the periods ended December 31, 2008, 2007 and 2006, 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 derivative financial instruments. 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.
F- 6
The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of our counterparties, which are generally energy companies.
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, 2008 resulted in an imbalance receivable of 99 MMcf, or $343, and an imbalance payable of 65 MMcf, or $314.
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, 2008, 2007 and 2006, was $11,078, $4,550, and $4,163, respectively.
Double Eagle invests in unevaluated oil and gas properties for the purpose of future 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, 2008, 2007 and 2006 and amounts include costs capitalized and subsequently expensed in the same period(amounts in thousands).
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| Beginning balance at January 1, | | $ | 692 | | | $ | 11,541 | | | $ | 2,972 | |
| | | | | | | | | | | | | |
| Additions to capitalized exploratory well costs pending the determination of proved reserves | | | — | | | | 5,727 | | | | 11,203 | |
| Reclassifications to wells, facilities and equipment based on the determination of proved reserves | | | (692 | ) | | | (1,666 | ) | | | (2,356 | ) |
| Capitalized exploratory well costs charged to expense | | | — | | | | (14,910 | ) | | | (278 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Ending balance at December 31, | | $ | — | | | $ | 692 | | | $ | 11,541 | |
| | | | | | | | | | |
F- 7
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, 2008, 2007 and 2006, an expense of $175, $25, and $15, respectively, was recorded as accretion expense on the liability and included in production costs on the Consolidated Statement of Operations. During 2008, 2007 and 2006, the Company recorded an additional $2,261, $739, and $170, respectively, in oil and gas properties and asset retirement obligation liability to reflect the present value of plugging liability on new wells and revisions to estimated cash flows added during the respective years.
A reconciliation of the Company’s asset retirement obligation liability:
| | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | | | |
| Beginning asset retirement obligation | | $ | 1,449 | | | $ | 694 | |
| | | | | | | | | |
| Liabilities incurred | | | 995 | | | | 655 | |
| Liabilities settled | | | — | | | | (9 | ) |
| Accretion expense | | | 175 | | | | 25 | |
| Changes in ownership interest | | | (77 | ) | | | — | |
| Revision to estimated cash flows | | | 1,666 | | | | 84 | |
| | | | | | | |
| | | | | | | | | |
| Ending asset retirement obligation | | $ | 4,208 | | | $ | 1,449 | |
| | | | | | | |
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. The Company recognized a non-cash charge on producing properties during the years ending December 31, 2008, 2007 and 2006 of $0, $2,141, and $0, respectively, and a non-cash charge on undeveloped leaseholds during the years ending December 31, 2008, 2007 and 2006 of $743, $91, and $0, respectively.
The Company’s pipeline facilities are recorded at cost, which totaled $5,465 as of December 31, 2008. 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. The Company evaluated the expected useful life of the pipeline assets as of December 31, 2008, and determined that the assets are expected to be utilized for at least the estimated useful life used in the depreciation calculation.
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 40 years for office facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense for the years ended December 31, 2008, 2007 and 2006 was $177, $160, and $107, respectively.
F- 8
Major Customers
The Company had sales to one major unaffiliated customer for years ended December 31, 2008, 2007 and 2006, totaling $32,045, $11,530, and $13,649, respectively. No other single customer accounted for 10% or more of revenues in 2008, 2007 or 2006. Although a substantial portion of our production is purchased by one customer, the Company does not believe the loss of this customer would have a material adverse effect on the Company’s business as other customers would be accessible.
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 States. Consequently, the Company currently reports as a single industry segment. The Company’s transportation and gathering subsidiary provides services exclusively for our gas marketing company and all of the revenue generated by this subsidiary is related to volumes produced from the Catalina Unit. Segmentation of such net income would not provide a better understanding of the Company’s performance, and is not viewed by management as a discrete reporting segment. However, gross revenue and expense related to our transportation and gathering subsidiary are presented as separate line items in the accompanying Consolidated Statement of Operations.
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 2008, 2007 and 2006 were $117, $118, and $87, respectively.
Income Taxes
The Company accounts for deferred income taxes utilizing Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” (“SFAS No. 109”) as amended. 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 (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of common shares outstanding during the period.
Calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Net income (loss) | | $ | 10,381 | | | $ | (11,603 | ) | | $ | 2,109 | |
| Preferred stock dividends | | | (3,723 | ) | | | (1,810 | ) | | | — | |
| | | | | | | | | | |
| Income (loss) attributable to common stock | | $ | 6,658 | | | $ | (13,413 | ) | | $ | 2,109 | |
| | | | | | | | | | |
| Weighted average shares: | | | | | | | | | | | | |
| Weighted average shares — basic | | | 9,159,865 | | | | 9,114,622 | | | | 8,632,567 | |
| Dilutive effect of stock options outstanding at the end of period | | | 2,120 | | | | — | | | | 23,020 | |
| | | | | | | | | | |
| Weighted average shares — fully diluted | | | 9,161,985 | | | | 9,114,622 | | | | 8,655,587 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings (loss) per share: | | | | | | | | | | | | |
| Basic | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | |
| | | | | | | | | | |
| Diluted | | $ | 0.73 | | | $ | (1.47 | ) | | $ | 0.24 | |
| | | | | | | | | | |
F- 9
The following options and stock awards 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, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Potential common shares | | | 56,249 | | | | 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 and stock awards) 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, 2006 included the cost for options which were granted prior to January 1, 2006, as determined under the provisions of SFAS 123(R).
Shareholder Rights Plan
In 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, 2008.
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 accounts for certain derivative contracts 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. The Company also marks to market other derivative instruments not accounted for as cash flow hedges, with the change in fair values recorded within the price risk management line on the Consolidated Statement of Operations. Reference is made to Notes 5 and 6 of the Notes to the Consolidated Financial Statements.
Derivative Financial Instruments
The Company uses derivative instruments, primarily forwards, swaps, and collars, to hedge risk associated with fluctuating commodity prices. The Company does not use derivative instruments for speculative purposes. See Notes 4 and 5 for a full description of our derivative activities and related accounting policies.
F- 10
Other Comprehensive Income
Comprehensive income (loss) consists of net income (loss) and changes to the Company’s derivative instruments that are treated as cash flow hedges, including realized and unrealized gains and losses as well as changes in fair value, net of tax. The Company recorded a tax benefit of $0 on the change in derivative instrument fair value during the years ended December 31, 2008 and 2007, as the tax benefit is not likely to be realized given the Company’s operating loss carryforwards and timing of the derivative contract settlements.
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, net of tax. The Company’s accumulated other comprehensive income related to cash flow hedges at December 31, 2008 totaled $16,690. As of December 31, 2008, the Company expected to reclassify $11,660 of the accumulated other comprehensive income balance to earnings in one year or less.
Recently Adopted 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. In February 2008, the FASB issued Staff Position No. FAS 157-2 which proposed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities, including asset retirement obligations, that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On January 1, 2008, the Company elected to implement this Statement with the one-year deferral. Given the nature of the Company’s current financial instruments, the adoption of SFAS No. 157 did not have a material impact on the Company’s financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The Company is in the process of evaluating this standard with respect to its effect on nonfinancial assets and liabilities and has not yet determined the impact that it will have on its financial statements upon full adoption in 2009.
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. The Company adopted SFAS No. 159 on January 1, 2008. To date, the Company has not elected to account for any financial instruments under the FAS 159 option and therefore the adoption of SFAS No. 159 did not have a material effect on our financial condition, results of operations or cash flows.
New Accounting Pronouncements
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 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.
F- 11
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 — Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 does not change current accounting treatment of derivatives, but requires expanded disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance and cash flows. The standard is effective for fiscal years and interim periods beginning after November 15, 2008 and early adoption is encouraged.
In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162,The Hierarchy of Generally Accepted Accounting Principles(“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have an impact on the Company’s financial position, results of operations or cash flows.
In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements, is a broader definition of reserves, which allows consideration of new technologies. In addition, oil and gas reserves will be reported using an average price based on the prior 12-month period, rather than year-end prices and allow companies to disclose their probable and possible reserves to investors. The new rule is expected to be effective for years ending on or after December 31, 2009. The Company is in the process of evaluating the effect of these new requirements, and has not yet determined the impact that it will have on its financial statements upon full adoption on December 31, 2009.
2.Line of Credit
As part of our cash management program, the Company secured a $50 million revolving line of credit collateralized by oil and gas producing properties, with a $35 million borrowing base. All outstanding balances on the line of credit mature on July 31, 2010. As of December 31, 2008, 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 2.125%. For the years ended December 31, 2008, 2007, and 2006, we recognized interest expense on the line of credit of $0, $154, and $187, respectively. We capitalized interest costs of $705, $279, and $293 for the years ended December 31, 2008, 2007, and 2006, respectively.
As of December 31, 2008, the balance outstanding of $24,639 was used to fund capital expenditures primarily on our Catalina Unit expansion and other non-operated projects in the Atlantic Rim, as well as projects in the Pinedale Anticline.
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, 2008, we were not in compliance with the current ratio covenant. Effective February 26, 2009, we renegotiated our $50 million revolving line of credit into a $75 million credit facility collateralized by our oil and gas producing properties and other Company assets, with the borrowing base being increased to $45 million from $35 million. Under the agreement, $5 million of the $45 million borrowing base represents a term loan that, if drawn upon, must be repaid on or before July 31, 2009, and the remaining $40 million of available borrowing base will be a revolving line of credit. Any remaining outstanding balances on the line of credit mature on July 31, 2010. Under the facility, we are subject to both financial and non-financial covenants. The financial covenants have been modified to include maintaining a current ratio, as defined, of 1.0 to 1.0, beginning June 30, 2009, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”) to interest plus dividends, of 1.5 to 1.0. The interest rate on the new credit facility will vary based on prevailing market rates with the minimum floor rate of 4.5%.
If we had been unable to renegotiate our credit facility or obtain a waiver from our lenders, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding. Management believes it is probable that we will be in compliance with all covenants at the 2009 assessment dates; therefore the Company has classified the line of credit as a long-term liability.
F- 12
3.Income Taxes
The provision for income taxes consists of:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Current taxes | | $ | — | | | $ | — | | | $ | — | |
| Deferred taxes | | | 5,343 | | | | (6,143 | ) | | | 1,399 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total income tax expense | | $ | 5,343 | | | $ | (6,143 | ) | | $ | 1,399 | |
| | | | | | | | | | |
The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2008 and 2007 were:
| | | | | | | | | |
| | | As of December 31, | |
| | | 2008 | | | 2007 | |
| Deferred tax assets: | | | | | | | | |
| Net operating loss carry-forward | | $ | 10,691 | | | $ | 10,885 | |
| Asset retirement obligation | | | 1,474 | | | | 272 | |
| Share-based compensation | | | 167 | | | | — | |
| Accrued compensation | | | 94 | | | | — | |
| Allowance for doubtful accounts | | | — | | | | 198 | |
| Other | | | 5 | | | | — | |
| | | | | | | |
| | | | 12,431 | | | | 11,355 | |
| | | | | | | |
| | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | |
| Net gas imbalance receivable | | | (32 | ) | | | (192 | ) |
| Net basis difference in oil and gas properties | | | (14,869 | ) | | | (8,290 | ) |
| | | | | | | |
| Net deferred tax asset (liability) | | $ | (2,470 | ) | | $ | 2,873 | |
| | | | | | | |
In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities and projected future taxable income. As of December 31, 2008, the Company has determined that it is more likely than not that all of the deferred tax assets will be utilized.
At December 31, 2008, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $30.3 million, which will begin expiring in 2021.
Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:
| | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | |
| Expected federal tax rate | | | 35.00 | % | | | 35.00 | % |
| Effect of non-deductibility of SFAS 123(R) Incentive Stock Option Expense and other permanent differences | | | -1.06 | % | | | -0.74 | % |
| State tax rate and other | | | 0.04 | % | | | 0.36 | % |
| | | | | | | |
| Effective tax rate | | | 33.98 | % | | | 34.62 | % |
| | | | | | | |
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
F- 13
December 31, 2008 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, 2008, 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 2004 and for state and local tax authorities for years before 2003. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.
4.Commitments and Contingencies
To partially mitigate the Company’s exposure to adverse fluctuations in the prices of natural gas, the Company has entered into various derivative contracts.
Gas Contracts
At December 31, 2008, the Company had commitments to sell a total of 1,661,000 Mcf under seven forward sales gas contracts with third-parties. 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, which 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 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 derivative contracts has required any form of security guarantee as of December 31, 2008.
Certain provisions of the fixed price contracts, including quantities (expressed in Mcf), terms and prices, are:
| | | | | | | | | | | | | | | | | | | | | |
| FORWARD SALES CONTRACTS | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | |
| | | Contractual | | Daily | | | | | | | | | | Price |
| Property | | Volume | | Production | | Term | | Price | | Index (1) |
| | | | | | | | | | | | | | | | | | | | | |
| Catalina | | | 151,000 | | | | 1,000 | | | | 06/07-05/09 | | | $ | 5.47 | | | CIG |
| | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 5.84 | | | CIG |
| | | | 362,000 | | | | 2,000 | | | | 07/07-06/09 | | | $ | 5.69 | | | CIG |
| | | | 304,000 | | | | 1,000 | | | | 11/07-10/09 | | | $ | 5.66 | | | CIG |
| | | | 270,000 | | | | 3,000 | | | | 11/08-03/09 | | | $8.85 floor/ | | CIG |
| | | | | | | | | | | | | | | $13.05 ceiling | | | | |
| Atlantic Rim | | | 212,000 | | | | 1,000 | | | | 08/07-07/09 | | | $ | 6.15 | | | CIG |
| Pinedale Anticline | | | 181,000 | | | | 1,000 | | | | 07/07-06/09 | | | $ | 6.41 | | | CIG |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Company Total | | | 1,661,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
The Company also has a NYMEX futures contract in place for 3,000 Mcf per day for the period November 2008 through March 2009 at a price of 9.53 per Mcf. The instrument was entered into in an effort to limit the Company’s credit risk exposure during the winter months when prices historically rise.
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The Company has also entered into various other derivative instruments to protect prices on future production. The terms of our other hedging instruments are summarized as follows (volume and daily production are expressed in Mcf):
| | | | | | | | | | | | | | | | | | | | | |
| | | Remaining | | | | | | | | | | | | |
| | | Contractual | | Daily | | | | | | | | | | Price |
| Type of Contract | | Volume | | Production | | Term | | Price | | Index (1) |
| | | | | | | | | | | | | | | | | | | | | |
| Costless Collar | | | 270,000 | | | | 3,000 | | | | 11/08-3/09 | | | $6.50 floor/$13.50 ceiling | | CIG |
| Option | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $10.50 floor | | NYMEX |
| Fixed Price Swap | | | 450,000 | | | | 5,000 | | | | 11/08-3/09 | | | $2.27 CIG basis hedge | | NYMEX |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/09-12/09 | | | $ | 7.34 | | | CIG |
| Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | | 1/11-12/11 | | | $ | 7.07 | | | CIG |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | | 7,010,000 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. |
Subsequent to December 31, 2008, we sold the $10.50 NYMEX floor that made up the option listed above, for net cash settlement of $1,351. We also entered into a natural gas swap agreement for 12,000 Mcf per day at a CIG price of $4.30 for calendar 2010.
Refer to Note 5Commodity Risk Managementfor additional information related to the accounting treatment of the Company’s derivative contracts.
Capital Lease Commitments
During the fourth quarter of 2008, the Company entered into two sale/leaseback transactions with a third party for compression equipment located in the Catalina Unit. The agreements transferred all title, maintenance, repairs and other ownership costs to the third party. In the first of the two transactions, the Company sold the equipment for proceeds of $2.2 million and agreed to lease the equipment for a 60 month term. This lease of compressor equipment is accounted for as an operating lease in accordance with FASB Statement of Financial Accounting Standards No. 13, Accounting for Leases (“FAS 13”), and is included in the lease table below underOperating Lease Commitments. There was no material gain or loss on the sale. In the second transaction, the Company received proceeds of $1.6 million and agreed to lease the equipment for a term of 36 months. This lease will be accounted for as a capital lease, in accordance with FAS 13. The effective interest rate on the capital lease is 2.125%. The Company realized a gain of $931 on the transaction, which will be recognized proportionately over the term of the lease.
Property under capital lease at December 31, 2008 and 2007, totaled $1,600 and $0, respectively and is included in the developed properties line on the balance sheet. Related accumulated depreciation was approximately $0 and $0 at December 31, 2008 and 2007, respectively.
Future minimum lease payments under noncancelable capital leases at December 31, 2008 are as follows (in thousands):
| | | | | |
| | | Lease | |
| Year ending December 31, | | Commitments | |
| 2009 | | $ | 753 | |
| 2010 | | | 753 | |
| 2011 | | | 753 | |
| | | | |
| Total minimum lease payments | | $ | 2,259 | |
| | | | |
| Less: Executory costs | | | 600 | |
| Less: Amounts representing interest | | | 59 | |
| | | | |
| Present value of minimum lease payments | | $ | 1,600 | |
| | | | |
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Operating Lease Commitments
In 2008, the Company extended our current operating lease through August 2013 for approximately 3,900 square feet of office space in Denver, Colorado. The Company also maintains operating leases on certain compressor equipment in the Catalina Unit (see discussion above) and 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:
| | | | | |
| | | Lease | |
| Year ending December 31, | | Commitments | |
| 2009 | | $ | 1,566 | |
| 2010 | | | 1,568 | |
| 2011 | | | 1,570 | |
| 2012 | | | 1,566 | |
| 2013 and thereafter | | | 1,160 | |
| | | | |
| Total | | $ | 7,430 | |
| | | | |
Total expense from operating leases totaled $419, $62, and $58 in 2008, 2007 and 2006, respectively.
Litigation and 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 Conoco/Phillips 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-parties for our production at the Atlantic Rim and the Pinedale Anticline, and other financial derivatives, which reduce our overall exposure to commodity price fluctuations. The duration of our various derivative instruments depends on our view of market conditions, available contract prices and our operating strategy. Use of such contracts limits the risk of fluctuating cash flows due to changing commodity prices. As of December 31, 2008, we
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have hedges in place for approximately 61% of our daily net production. Refer to Footnote 4Commitments and Contingenciesfor the listing of the current contracts the Company had in place as of December 31, 2008.
Normal purchases and normal sales
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, the fixed delivery contracts for production from Sun Dog and Doty Mountain at the Atlantic Rim and the Pinedale Anticline 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. Under the “normal purchase and normal sale” exception, we record the revenue upon contract settlement in oil and gas sales on the Consolidated Statement of Operations.
Cash flow hedges
In accordance with the provisions of SFAS No. 133, the Catalina Unit fixed delivery contracts and other derivative instruments are accounted for as cash flow hedges, under which the change in fair value is initially reported as a component of accumulated other comprehensive income and is subsequently reclassified into the oil and gas sales line on the Consolidated Statement of Operations as the contracts settle. 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. The Company formally documents the relationship between the derivative instruments and the hedged production, as well as the Company’s risk management objective and strategy for the particular derivative contracts. This process includes linking all derivatives that are designated as cash flow hedges to the specific forecasted sale of gas at its physical location as well as routinely evaluating the effectiveness of the cash flow hedges. The Company seeks to minimize the ineffectiveness of the cash flow hedges by entering into contracts indexed to regional index prices associated with pipelines in proximity to the Company’s areas of production. As the Company’s cash flow hedges contain the same index as the Company’s sales contracts, this results in hedges that are highly correlated with the underlying hedged item. We did not recognize any gains/losses related to the ineffective portion of our cash flow hedges for the years ended December 31, 2008, 2007, and 2006. The settlements of these contracts are included within the oil and gas sales line on the Consolidated Statement of Operations.
Other derivative instruments
The Company also has other economic hedges in place, for which, the Company did not qualify cash flow hedge accounting at the contract inception. These instruments were recorded at fair value and marked to market, with changes in the fair value subsequent to the initial measurement flowing through earnings. The change in fair value is recorded in the price risk management line on the Consolidated Statement of Operations. Upon settlement of the derivative instruments accounted for under mark-to-market accounting, the realized gain/loss is also recorded in the price risk management line on the Consolidated Statement of Operations. We did not have any economic hedges in place for the years ended December 31, 2007 and 2006.
The following table summarizes the realized and unrealized gains and losses the Company recognized related to its derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006:
| | | | | | | | | | | | | |
| | | For the years ended December 31, |
| | | 2008 | | 2007 | | 2006 |
| | | | | | | | | | | | | |
| Realized gain (loss) on derivatives designated as cash flow hedges(1) | | $ | (88 | ) | | $ | 304 | | | $ | — | |
| Realized gain on economic hedges (2) | | $ | 2,698 | | | $ | — | | | $ | — | |
| Unrealized gain on economic hedges (2) | | $ | 2,631 | | | $ | — | | | $ | — | |
| | |
| (1) | | Included in the oil and gas sales on the Consolidated Statement of Operations |
| |
| (2) | | Included in the price risk management line on the Consolidated Statement of Operations |
6. Fair Value of Financial Instruments
Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, Fair Value Measurements, for all financial
F- 17
instruments. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exact price) in an orderly transaction between market participants at the measurement date. The statement establishes observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. SFAS 157 establishes a three-level valuation hierarchy for grouping these assets and liabilities. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
| | • | | Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets. |
| |
| | • | | Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable. |
| |
| | • | | Level 3 — Unobservable inputs that reflect the Company’s own assumptions |
The following describes the valuation methodologies we use to measure financial instruments at fair value.
The Company considers several factors in determining its estimate of fair value, including quoted market prices in active markets, the credit rating of each counterparty, and the Company’s own credit rating. The Company then compares its valuation estimates against mark-to-market statements from counterparties for reasonableness.
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
The natural gas derivative markets are highly active. Although the Company’s cash flow and economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company’s has classified these instruments as Level 2.
The following table provides a summary of the fair values of assets and liabilities measured on a recurring basis under SFAS No. 157:
| | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | | |
| Derivative instruments | | $ | — | | | $ | 19,319 | | | $ | — | | | $ | 19,319 | |
| |
| Total assets at fair value | | $ | — | | | $ | 19,319 | | | $ | — | | | $ | 19,319 | |
| |
| | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | |
| Derivative instruments | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| |
| Total liabilities at fair value | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| |
6. Series A Cumulative Preferred Stock
In 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, and subsequently 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.
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 or Ownership or Control, we may not redeem the Series A Preferred Stock prior to June 30, 2012. On or 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
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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.
| | | | | |
| Redemption Date on or Before | | Redemption Price |
| June 30, 2009 | | $ | 25.75 | |
| June 30, 2010 | | $ | 25.50 | |
| June 30, 2011 | | $ | 25.25 | |
| June 30, 2012 or thereafter | | $ | 25.00 | |
In the event of 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 or our common stock.
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.
7.Compensation Plans
Double Eagle has outstanding stock options issued to employees under various 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. As of December 31, 2008, there were 18,099 options available for grant under the 2003 Stock Option Plan.
In 2007, the Company’s shareholders approved the 2007 Stock Incentive Plan (“2007 Plan”), which allows both stock options and stock awards to be granted to the Company’s employees, directors, consultants, and other persons designated by the Compensation Committee of the Board of Directors. In 2008, the Company began granting stock awards and stock options under this plan. These awards vest annually over various periods of three to five years of continuous service. As of December 31, 2008, there were 260,667 shares available for grant under the 2007 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 and stock awards) made to employees and directors based on estimated fair value. The Company adopted FAS 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). During the years ended December 31, 2008, 2007 and 2006, total share-based compensation expense for equity-classified awards, was $1,178, $552, and $557, respectively, and is reflected in general and administrative expense in the Consolidated Statement of Operations.
Stock Options
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:
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| | | | | | | | | | | | | |
| | | For the year ended December 31, |
| | | 2008 | | 2007 | | 2006 |
| Weighted-average volatility | | | 40-41 | % | | | 42 | % | | | 40% - 44 | % |
| Expected dividends | | | 0.00 | % | | | 0.00 | % | | | 0.00 | % |
| Expected term (in years) | | | 4-5 | | | | 4.25 | | | | 2 - 4 | |
| Risk-free rate | | | 2.42%-3 | % | | | 4.58 | % | | | 4.68% - 5.10 | % |
| Expected forfeiture rate | | | 5%-7 | % | | | 7.00 | % | | | 5% - 10 | % |
Summary of option activity during the year ended December 31, 2008:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Weighted-Average | | | | |
| | | | | | | | | | | Remaining | | | | |
| | | | | | | Weighted-Average | | | Contractual Term | | | Aggregate | |
| Options: | | Shares | | | Exercise Price | | | (in years) | | | Intrinsic Value | |
| Outstanding at January 1, 2008 | | | 263,500 | | | $ | 17.71 | | | | 3.4 | | | | | |
| Granted | | | 445,897 | | | $ | 14.91 | | | | | | | | | |
| Exercised | | | (15,000 | ) | | $ | 18.52 | | | | | | | | | |
| Cancelled/expired | | | (67,500 | ) | | $ | 17.56 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Outstanding at December 31, 2008 | | | 626,897 | | | $ | 15.68 | | | | 5.1 | | | $ | 2 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exerciseable at December 31, 2008 | | | 175,679 | | | $ | 16.37 | | | | 3.5 | | | $ | — | |
| | | | | | | | | | | | | |
The weighted average grant date fair value price per share of options granted during the three years ended December 31, 2008, 2007, and 2006 was $14.91, $17.86, and $19.53, respectively. During the years ended December 31, 2008, 2007, and 2006, 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 $276, $150, and $501. As of December 31, 2008, 2007, and 2006, the fair value of options vested and exercisable was $0, $2,255, and $2,497.
Stock options outstanding and currently exercisable at December 31, 2008 are:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Options | | | | | | Options Exercisable |
| | | | | | | 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 | | Exercisable | | per Share |
| $6.78 - $7.26 | | | 15,000 | | | | 5.3 | | | $ | 6.94 | | | | — | | | $ | — | |
| $14.00 - $16.21 | | | 445,897 | | | | 5.8 | | | $ | 14.74 | | | | 112,179 | | | $ | 14.71 | |
| $17.86 - $19.55 | | | 138,500 | | | | 3.2 | | | $ | 18.52 | | | | 52,500 | | | $ | 18.88 | |
| $20.21 - $23.61 | | | 27,500 | | | | 3.2 | | | $ | 21.30 | | | | 11,000 | | | $ | 21.30 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 626,897 | | | | 5.1 | | | $ | 15.68 | | | | 175,679 | | | $ | 16.37 | |
| | | | | | | | | | | | | | | | | | | | | |
As of December 31, 2008, there was $2,264 of total unrecognized stock-based compensation expense related to stock options to be recognized over a weighted-average period of 3.6 years.
Stock awards
We measure the fair value of the stock awards based upon the fair market value of our common stock on the date of grant and recognize the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. We recognize these compensation costs net of a forfeiture rate, if applicable, and recognize the compensation costs for only those shares expected to vest. We typically estimate forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.
F-20
Nonvested stock awards as of December 31, 2008 and changes for the year ended December 31, 2008 were as follows:
| | | | | | | | | |
| | | | | | | Weighted- |
| | | | | | | Average Grant |
| Stock Awards: | | Shares | | Date Fair Value |
| Outstanding at January 1, 2008 | | | — | | | $ | — | |
| Granted | | | 124,013 | | | $ | 14.81 | |
| Vested | | | (29,251 | ) | | $ | 15.15 | |
| Forfeitures | | | — | | | $ | — | |
| | | | | | | | | |
| Nonvested at December 31, 2008 | | | 94,762 | | | $ | 14.70 | |
| | | | | | | | | |
As of December 31, 2008, there was $1,312 of unrecognized stock-based compensation expense related to nonvested stock awards. This cost is expected to be recognized over a weighted-average period of 3.7 years.
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, 2008, 2007 and 2006 are:
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Developed properties | | $ | 133,516 | | | $ | 61,394 | | | $ | 53,677 | |
| Wells in progress | | | 18,518 | | | | 29,768 | | | | 13,839 | |
| Undeveloped properties | | | 2,907 | | | | 3,147 | | | | 3,313 | |
| | | | | | | | | | |
| | | | 154,941 | | | | 94,309 | | | | 70,829 | |
| | | | | | | | | | | | | |
| Accumulated depletion and amortization | | | (33,905 | ) | | | (22,218 | ) | | | (19,442 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Net capitalized costs | | $ | 121,036 | | | $ | 72,091 | | | $ | 51,387 | |
| | | | | | | | | | |
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, 2008, 2007 and 2006 were:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Property acquisitions — unproved | | $ | 30 | | | $ | 316 | | | $ | 100 | |
| Exploration | | | 536 | | | | 3,600 | | | | 11,304 | |
| Development | | | 64,462 | | | | 41,337 | | | | 10,046 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total | | $ | 65,028 | | | $ | 45,253 | | | $ | 21,450 | |
| | | | | | | | | | |
F-21
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, 2008, 2007 and 2006 were:
| | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| Operating revenues (1) | | $ | 41,847 | | | $ | 16,044 | | | $ | 18,228 | |
| Costs and expenses: | | | | | | | | | | | | |
| Production | | | 12,302 | | | | 7,629 | | | | 5,769 | |
| Exploration | | | 911 | | | | 15,399 | | | | 530 | |
| Depletion, amortization and impairment | | | 11,078 | | | | 6,691 | | | | 4,163 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total costs and expenses | | | 24,291 | | | | 29,719 | | | | 10,462 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income (loss) before income taxes | | $ | 17,556 | | | $ | (13,675 | ) | | $ | 7,766 | |
| | | | | | | | | | |
| | |
| (1) | | Our operating revenues are comprised of the oil and gas sales from the Consolidated Statement of Operations, plus settlements on our economic hedges during the period. For the years ended December 31, 2008, 2007 and 2006, the settlements on economic hedges totaled $2,698, $0, and $0, respectively. |
Oil and Gas Reserves (Unaudited)
The reserves at December 31, 2008, 2007 and 2006 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, 2008 2007, and 2006 are:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | Oil | | | Gas | | | Oil | | | Gas | | | Oil | | | Gas | |
| | | (Bbl) | | | (Mcf) | | | (Bbl) | | | (Mcf) | | | (Bbl) | | | (Mcf) | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning of year | | | 412,812 | | | | 71,253,865 | | | | 360,165 | | | | 48,496,719 | | | | 328,752 | | | | 47,234,335 | |
| Revisions of estimates | | | (33,439 | ) | | | (4,637,562 | ) | | | (112,093 | ) | | | (18,449,972 | ) | | | 41,546 | | | | (5,976,392 | ) |
| Extensions and discoveries | | | 65,429 | | | | 26,244,840 | | | | 178,208 | | | | 44,135,456 | | | | 2,596 | | | | 10,379,429 | |
| Sales of reserves in place | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Production | | | (24,613 | ) | | | (6,530,323 | ) | | | (13,468 | ) | | | (2,928,338 | ) | | | (12,729 | ) | | | (3,140,653 | ) |
| | | | | | | | | | | | | | | | | | | |
| End of year | | | 420,189 | | | | 86,330,820 | | | | 412,812 | | | | 71,253,865 | | | | 360,165 | | | | 48,496,719 | |
| | | | | | | | | | | | | | | | | | | |
| Proved developed reserves | | | 295,698 | | | | 63,007,126 | | | | 253,478 | | | | 44,782,553 | | | | 254,346 | | | | 30,075,467 | |
| | | | | | | | | | | | | | | | | | | |
| Percentage of proved developed reserves | | | 70 | % | | | 73 | % | | | 61 | % | | | 63 | % | | | 71 | % | | | 62 | % |
| | | | | | | | | | | | | | | | | | | |
F-22
As of December 31, 2008, 79% of the proved developed gas reserves and 95% 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.
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, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Future cash inflows | | $ | 406,017 | | | $ | 462,655 | | | $ | 246,270 | |
| Future production costs | | | (118,299 | ) | | | (102,515 | ) | | | (65,650 | ) |
| Future development costs | | | (18,275 | ) | | | (23,651 | ) | | | (17,049 | ) |
| Future income taxes | | | (58,313 | ) | | | (96,370 | ) | | | (42,578 | ) |
| | | | | | | | | | |
| Future net cash flows | | | 211,130 | | | | 240,119 | | | | 120,993 | |
| 10% annual discount | | | (89,075 | ) | | | (109,820 | ) | | | (70,960 | ) |
| | | | | | | | | | |
| Standardized measure of | | | | | | | | | | | | |
| Discounted future net cash flows | | $ | 122,055 | | | $ | 130,299 | | | $ | 50,033 | |
| | | | | | | | | | |
F-23
Principal changes in the Standardized Measure for the years ended December 31, 2008, 2007 and 2006:
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Standard measure, as of January 1, | | $ | 130,299 | | | $ | 50,033 | | | $ | 91,293 | |
| | | | | | | | | | | | | |
| Sales of oil and gas produced, net of production costs | | | (26,846 | ) | | | (8,416 | ) | | | (12,460 | ) |
| Extensions and discoveries | | | 49,511 | | | | 118,002 | | | | 14,724 | |
| | | | | | | | | | | | | |
| Net change in prices and production costs related to future production | | | (63,682 | ) | | | 41,821 | | | | (44,698 | ) |
| Development costs incurred during the year | | | | | | | | | | | | |
| | | | 11,181 | | | | 9,924 | | | | 3,147 | |
| | | | | | | | | | | | | |
| Changes in estimated future development costs | | | (5,188 | ) | | | (24,107 | ) | | | (10,632 | ) |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| Revisions of previous quantity estimates | | | (9,119 | ) | | | (50,750 | ) | | | (7,749 | ) |
| Accretion of discount | | | 15,919 | | | | 6,764 | | | | 14,315 | |
| Net change in income taxes | | | 18,576 | | | | (18,064 | ) | | | 13,299 | |
| Changes in timing and other | | | 1,404 | | | | 5,092 | | | | (11,206 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Standardized measure, as of December 31, | | $ | 122,055 | | | $ | 130,299 | | | $ | 50,033 | |
| | | | | | | | | | |
9.Quarterly Financial Data (Unaudited)
Summary of the unaudited financial data for each quarter for the years ended December 31, 2008 and 2007 (in thousands except per share data):
| | | | | | | | | | | | | | | | | |
| | | Fourth | | Third | | Second | | First |
| | | Quarter | | Quarter | | Quarter | | Quarter |
Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 9,710 | | | $ | 11,662 | | | $ | 10,981 | | | $ | 6,796 | |
| Income from operations | | $ | 3,287 | | | $ | 4,464 | | | $ | 5,189 | | | $ | 3,009 | |
| Net income | | $ | 2,338 | | | $ | 2,907 | | | $ | 3,273 | | | $ | 1,863 | |
| Net income attributable to common stock | | $ | 1,407 | | | $ | 1,977 | | | $ | 2,342 | | | $ | 932 | |
| Basic net income per common share | | $ | 0.15 | | | $ | 0.22 | | | $ | 0.26 | | | $ | 0.10 | |
| Diluted net income per common share | | $ | 0.15 | | | $ | 0.22 | | | $ | 0.26 | | | $ | 0.10 | |
| | | | | | | | | | | | | | | | | |
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 | |
| Diluted net income (loss) per common share | | $ | (0.82 | ) | | $ | (0.62 | ) | | $ | (0.06 | ) | | $ | 0.03 | |
| | |
| (1) | | Quarterly oil and gas sales have been reclassified to conform to presentation for the quarter ended December 31, 2008. |
F-24
