UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| | |
þ | | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2010
or
| | |
o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-33571
DOUBLE EAGLE PETROLEUM CO.
(Exact name of registrant as specified in its charter)
| | |
MARYLAND | | 83-0214692 |
(State or other jurisdiction of | | (I.R.S. employer |
incorporation or organization) | | identification no.) |
1675 Broadway, Suite 2200, Denver, Colorado 80202
(Address of principal executive offices) (Zip code)
303-794-8445
(Registrant’s telephone number, including area code)
None
(Former name, former address, and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo
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.
| | | | | | |
Large accelerated filero | | Accelerated filero | | Non-accelerated filerþ | | Small reporting companyo |
| | | | (Do not check if a small reporting company) | | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
| | |
Class | | Outstanding as of April 20, 2010 |
Common stock, $.10 par value | | 11,116,589 |
DOUBLE EAGLE PETROLEUM CO.
FORM 10-Q
TABLE OF CONTENTS
1
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of dollars except share and per share data)
| | | | | | | | |
| | March 31, | | | December 31, | |
| | 2010 | | | 2009 | |
| | (Unaudited) | | | | | |
ASSETS | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 5,449 | | | $ | 5,682 | |
Cash held in escrow | | | 612 | | | | 611 | |
Accounts receivable | | | 6,541 | | | | 6,772 | |
Assets from price risk management | | | 3,769 | | | | — | |
Other current assets | | | 4,364 | | | | 3,982 | |
| | | | | | |
Total current assets | | | 20,735 | | | | 17,047 | |
| | | | | | |
| | | | | | | | |
Oil and gas properties and equipment, successful efforts method: | | | | | | | | |
Developed properties | | | 166,019 | | | | 165,279 | |
Wells in progress | | | 7,513 | | | | 7,544 | |
Gas transportation pipeline | | | 5,465 | | | | 5,465 | |
Undeveloped properties | | | 2,607 | | | | 2,502 | |
Corporate and other assets | | | 1,925 | | | | 1,914 | |
| | | | | | |
| | | 183,529 | | | | 182,704 | |
Less accumulated depreciation, depletion and amortization | | | (58,222 | ) | | | (53,682 | ) |
| | | | | | |
Net properties and equipment | | | 125,307 | | | | 129,022 | |
| | | | | | |
Assets from price risk management | | | 4,696 | | | | 3,566 | |
Other assets | | | 848 | | | | 859 | |
| | | | | | |
TOTAL ASSETS | | $ | 151,586 | | | $ | 150,494 | |
| | | | | | |
| | | | | | | | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | |
| | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable | | $ | 6,227 | | | $ | 6,177 | |
Accrued expenses | | | 4,684 | | | | 6,918 | |
Liabilities from price risk management | | | — | | | | 4,739 | |
Accrued production taxes | | | 3,142 | | | | 2,439 | |
Capital lease obligations, current portion | | | 525 | | | | 533 | |
Other current liabilities | | | 307 | | | | 308 | |
| | | | | | |
Total current liabilities | | | 14,885 | | | | 21,114 | |
| | | | | | | | |
Credit facility | | | 31,000 | | | | 34,000 | |
Asset retirement obligation | | | 4,834 | | | | 4,807 | |
Liabilities from price risk management | | | — | | | | 430 | |
Deferred tax liability | | | 8,848 | | | | 4,620 | |
Capital lease obligations, long-term portion | | | 410 | | | | 545 | |
Other long-term liabilities | | | 205 | | | | 282 | |
| | | | | | |
Total liabilities | | | 60,182 | | | | 65,798 | |
| | | | | | |
| | | | | | | | |
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of March 31, 2010 and December 31, 2009 | | | 37,972 | | | | 37,972 | |
| | | | | | | | |
Stockholders’ equity: | | | | | | | | |
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,106,108 and 11,090,725 shares issued and outstanding as of March 31, 2010 and December 31, 2009, respectively | | | 1,111 | | | | 1,109 | |
Additional paid-in capital | | | 43,916 | | | | 43,640 | |
Retained earnings | | | 4,836 | | | | (342 | ) |
Accumulated other comprehensive income | | | 3,569 | | | | 2,317 | |
| | | | | | |
Total stockholders’ equity | | | 53,432 | | | | 46,724 | |
| | | | | | |
| | | | | | | | |
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | | $ | 151,586 | | | $ | 150,494 | |
| | | | | | |
The accompanying notes are an integral part of the consolidated financial statements.
2
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF INCOME
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
| | | | | | | | |
| | Three months ended March 31, | |
| | 2010 | | | 2009 | |
| | | | | | | | |
Revenues | | | | | | | | |
Oil and gas sales | | $ | 11,049 | | | $ | 10,500 | |
Transportation revenue | | | 1,487 | | | | 1,587 | |
Price risk management activities | | | 7,822 | | | | (1,140 | ) |
Other income, net | | | 77 | | | | 93 | |
| | | | | | |
| | | | | | | | |
Total revenues | | | 20,435 | | | | 11,040 | |
| | | | | | |
| | | | | | | | |
Costs and expenses | | | | | | | | |
Production costs | | | 1,943 | | | | 1,611 | |
Production taxes | | | 1,300 | | | | 889 | |
Exploration expenses including dry hole costs | | | 38 | | | | 26 | |
Pipeline operating costs | | | 1,149 | | | | 568 | |
General and administrative | | | 1,534 | | | | 1,674 | |
Depreciation, depletion and amortization | | | 4,540 | | | | 4,382 | |
| | | | | | |
| | | | | | | | |
Total costs and expenses | | | 10,504 | | | | 9,150 | |
| | | | | | |
| | | | | | | | |
Income from operations | | | 9,931 | | | | 1,890 | |
| | | | | | | | |
Interest expense, net | | | (365 | ) | | | (252 | ) |
| | | | | | |
| | | | | | | | |
Income before income taxes | | | 9,566 | | | | 1,638 | |
| | | | | | | | |
Provision for deferred income taxes | | | (3,457 | ) | | | (631 | ) |
| | | | | | |
| | | | | | | | |
NET INCOME | | $ | 6,109 | | | $ | 1,007 | |
| | | | | | |
| | | | | | | | |
Preferred stock dividends | | | 931 | | | | 931 | |
| | | | | | |
| | | | | | | | |
Net income attributable to common stock | | $ | 5,178 | | | $ | 76 | |
| | | | | | |
| | | | | | | | |
Net income per common share: | | | | | | | | |
Basic | | $ | 0.47 | | | $ | 0.01 | |
| | | | | | |
Diluted | | $ | 0.47 | | | $ | 0.01 | |
| | | | | | |
Weighted average shares outstanding: | | | | | | | | |
Basic | | | 11,105,646 | | | | 9,201,913 | |
| | | | | | |
Diluted | | | 11,105,646 | | | | 9,201,913 | |
| | | | | | |
The accompanying notes are an integral part of the consolidated financial statements.
3
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of dollars)
(Unaudited)
| | | | | | | | |
| | Three months ended March 31, | |
| | 2010 | | | 2009 | |
Cash flows from operating activities: | | | | | | | | |
Net income | | $ | 6,109 | | | $ | 1,007 | |
Adjustments to reconcile net income to net cash from operating activities: | | | | | | | | |
Depreciation, depletion, amortization and accretion of asset retirement obligation | | | 4,560 | | | | 4,406 | |
Abandonment of non-producing properties | | | — | | | | 5 | |
Provision for deferred taxes | | | 3,457 | | | | 631 | |
Employee stock option expense | | | 227 | | | | 430 | |
Directors fees paid in stock | | | 49 | | | | 38 | |
Change in fair value of derivative contracts | | | (8,045 | ) | | | 4,066 | |
Revenue from carried interest | | | (716 | ) | | | (563 | ) |
Gain on sale of producing property | | | (72 | ) | | | (70 | ) |
Changes in current assets and liabilities: | | | | | | | | |
Increase in deposit held in escrow | | | (1 | ) | | | (2 | ) |
Decrease in accounts receivable | | | 236 | | | | 11,949 | |
Decrease (Increase) in other current assets | | | (424 | ) | | | 38 | |
Increase (Decrease) in accounts payable | | | 1,661 | | | | (12,242 | ) |
Increase (Decrease) in accrued expenses | | | 2,240 | | | | (2,847 | ) |
Increase in accrued production taxes | | | 411 | | | | 89 | |
| | | | | | |
| | | | | | | | |
NET CASH PROVIDED BY OPERATING ACTIVITIES | | | 9,692 | | | | 6,935 | |
| | | | | | |
| | | | | | | | |
Cash flows from investing activities: | | | | | | | | |
Additions of producing properties and equipment, net | | | (5,737 | ) | | | (21,429 | ) |
Additions of corporate and non-producing properties | | | (116 | ) | | | (15 | ) |
Payment of acquisition related costs | | | — | | | | (102 | ) |
| | | | | | |
| | | | | | | | |
NET CASH USED IN INVESTING ACTIVITIES | | | (5,853 | ) | | | (21,546 | ) |
| | | | | | |
| | | | | | | | |
Cash flows from financing activities: | | | | | | | | |
Principal payments on capital lease obligations | | | (143 | ) | | | (129 | ) |
Issuance of stock under Company stock plans | | | 5 | | | | 4 | |
Tax withholdings related to net share settlement of restricted stock awards | | | (3 | ) | | | (23 | ) |
Dividends on preferred stock | | | (931 | ) | | | (931 | ) |
Net borrowings (repayments) on line of credit | | | (3,000 | ) | | | 17,861 | |
| | | | | | |
| | | | | | | | |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | | | (4,072 | ) | | | 16,782 | |
| | | | | | |
| | | | | | | | |
Change in cash and cash equivalents | | | (233 | ) | | | 2,171 | |
| | | | | | | | |
Cash and cash equivalents at beginning of period | | | 5,682 | | | | — | |
| | | | | | |
| | | | | | | | |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 5,449 | | | $ | 2,171 | |
| | | | | | |
| | | | | | | | |
Supplemental disclosure of cash and non-cash transactions: | | | | | | | | |
Cash paid for interest | | $ | 448 | | | $ | 643 | |
Interest capitalized | | $ | 50 | | | $ | 300 | |
Additions to developed properties included in current liabilities | | $ | 3,092 | | | $ | 8,758 | |
Share-based compensation expense | | $ | 276 | | | $ | 468 | |
The accompanying notes are an integral part of the consolidated financial statements.
4
DOUBLE EAGLE PETROLEUM CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
1. | | Summary of Significant Accounting Policies |
Basis of presentation
The accompanying unaudited interim consolidated financial statements were prepared by Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in the annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted as allowed by such rules and regulations. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year. The Company has evaluated subsequent events through the date of issuance of its consolidated financial statements.
Certain amounts in the 2009 consolidated financial statements have been reclassified to conform to the 2010 consolidated financial statement presentation. Such reclassifications had no effect on net income.
The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2009, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.
The interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2009 included in the Annual Report on Form 10-K filed with the SEC.
Principles of consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC (“EWM”) (collectively, the “Company”). In August 2009, the Company acquired Petrosearch, which has operations in Texas and Oklahoma. The Company sold transportation assets located in the Catalina Unit, at cost, to EWM in exchange for an intercompany note receivable bearing interest of 5% per annum, maturing on January 31, 2028. The note and related interest are fully eliminated in consolidation. In addition, 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. The Company’s share of the fee related to gas gathering is also eliminated in consolidation.
Recently adopted accounting pronouncements
In January 2010, the FASB issued ASC Update No. 2010-06, an additional update to the ASC guidance for fair value measurements. The new guidance requires additional disclosures about (1) the different classes of assets and liabilities measured at fair value, (2) the valuation techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the transfers between Levels 1, 2 and 3. The updated guidance is effective for annual and interim periods beginning December 15, 2009, except for the disclosures about the activity in Level 3 fair value measurements, for which the new guidance is effective for fiscal years beginning after December 15, 2010. The Company adopted the provisions that were effective for annual and interim periods beginning December 15, 2009 effective January 1, 2010. The adoption of ASC Update 2010-06 did not have an impact on the Company’s financial position, results of operations or cash flows. Refer to Note 4 for the Company’s disclosures on fair value.
Basic earnings per share of common stock (“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, and is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock and potential common stock equivalents outstanding during the period, if dilutive. Potential common stock equivalents include incremental shares of common stock issuable upon the exercise of stock options and employee stock awards. Income attributable to common stock is calculated as net income less dividends paid on the Series A Preferred Stock. The Company declared and paid cash dividends of $931 ($.5781 per share) and $931 on the Series A Preferred Stock for the quarters ended March 31, 2010 and 2009, respectively.
5
The following is the calculation of basic and diluted weighted average shares outstanding and earnings per share of common stock for the periods indicated:
| | | | | | | | |
| | For the Quarter Ended March 31, | |
| | 2010 | | | 2009 | |
Net income | | $ | 6,109 | | | $ | 1,007 | |
Preferred stock dividends | | | 931 | | | | 931 | |
| | | | | | |
Net income attributable to common stock | | $ | 5,178 | | | $ | 76 | |
| | | | | | |
Weighted average shares: | | | | | | | | |
Weighted average shares — basic | | | 11,105,646 | | | | 9,201,913 | |
Dilution effect of stock options outstanding at the end of period | | | — | | | | — | |
| | | | | | |
Weighted average shares — diluted | | | 11,105,646 | | | | 9,201,913 | |
| | | | | | |
| | | | | | | | |
Earnings per common share: | | | | | | | | |
Basic | | $ | 0.47 | | | $ | 0.01 | |
| | | | | | |
Diluted | | $ | 0.47 | | | $ | 0.01 | |
| | | | | | |
The following options and unvested restricted shares, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:
| | | | | | | | |
| | For the Quarter Ended March 31, | |
| | 2010 | | | 2009 | |
| | | | | | | | |
Anti-dilutive shares | | | 81,116 | | | | 90,809 | |
| | | | | | |
3. | | Derivative Instruments |
The Company’s primary market exposure is to adverse fluctuations in the prices of natural gas. The Company uses derivative instruments, primarily forward contracts, costless collars and swaps, to manage the price risk associated with equity gas production, and the resulting impact on cash flow, net income, and earnings per share. The Company does not use derivative instruments for speculative purposes.
The Company recognizes its derivative instruments as either assets or liabilities at fair value on its consolidated balance sheet and accounts for the derivative instruments as either cash flow hedges or mark to market derivative instruments. On the cash flow statement, the cash flows from these instruments are classified as operating activities.
Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with third parties and financial institutions that it considers to be credit worthy. In addition, the Company’s master netting agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.
As with most derivative instruments, the Company’s 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. The Company was in an overall asset position with each of its counterparties at March 31, 2010, and no party in any of its derivative contracts has required any form of security guarantee.
Cash flow hedges
Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the balance sheet and the effective portion of the change in fair value is 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 income as the contracts settle. As of March 31, 2010, the Company expects approximately $1,366 of unrealized gains, included in its Accumulated Other Comprehensive Income (“AOCI”), to be reclassified into earnings in one year or less, as the contracts settle.
6
Mark to market hedging instruments
Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are recorded at fair value on the balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of income currently. Realized gains and losses resulting form the contract settlement of derivatives not designated as cash flow hedges also are recorded in the price risk management activities line on the consolidated statement of income.
The Company had the following commodity volumes under derivative contracts as of March 31, 2010:
| | | | | | | | |
| | Contract Settlement Date | |
Natural Gas forward purchase contracts: | | 2010 | | | 2011 | |
|
Volume (MMcf) | | | 6,050 | | | | 5,650 | |
The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of March 31, 2010, presented gross of any master netting arrangements:
| | | | | | |
Derivatives designated as hedging | | | | | |
instruments under ASC 815 | | Balance Sheet Location | | Fair Value | |
|
Assets | | | | | | |
Commodity derivatives | | Assets from price risk management — current | | $ | 1,366 | |
| | Assets from price risk management — long term | | | 4,223 | |
| | | | | |
Total | | | | $ | 5,589 | |
| | | | | |
| | | | | | |
Derivatives not designated as | | | | | |
hedging instruments under ASC 815 | | Balance Sheet Location | | Fair Value | |
|
Assets | | | | | | |
Commodity derivatives | | Assets from price risk management — current | | $ | 2,403 | |
| | Assets from price risk management — long term | | | 473 | |
| | | | | |
Total | | | | $ | 2,876 | |
| | | | | |
The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of income for the three months ended March 31, 2010 and 2009, related to the Company’s commodity derivatives was as follows:
| | | | | | | | |
Derivatives Designated | | Amount of Gain Recognized in | |
as Cash Flow | | OCI1 on Derivative for | |
Hedging Instruments | | Three months ended March 31, | |
under ASC 815 | | 2010 | | | 2009 | |
| | | | | | | | |
Commodity contracts | | $ | 2,023 | | | $ | (4,865 | ) |
7
| | | | | | | | | | | | |
| | | | | | | | | | Location of Gain | |
| | Amount of Gain Reclassified from Accumulated | | | Recognized in Income | |
Location of Gain Reclassified | | OCI into Income for | | | (Ineffective Portion and | |
from Accumulated OCI1 | | Three months ended March 31, | | | Amount Excluded from | |
into Income (effective portion) | | 2010 | | | 2009 | | | Effectiveness testing) | |
| | | | | | | | | | | | |
Oil and gas sales | | $ | — | | | $ | 4,147 | | | | N/A | |
| | |
1 | | Other comprehensive income (“OCI”). |
The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of income for the three months ended March 31, 2010 and 2009 was as follows:
| | | | | | | | | | |
Derivatives not | | | | Amount of Loss Recognized in | |
Designated as | | Location of Loss | | Income on Derivative | |
Hedging Instruments | | Recognized in Income | | Three months ended March 31, | |
under ASC 815 | | on Derivative | | 2010 | | | 2009 | |
|
Commodity contracts | | Price risk management activities | | $ | 7,822 | | | $ | (1,140 | ) |
Refer to Note 4 for additional information regarding the valuation of the Company’s derivative instruments.
4. | | Fair Value of Financial Instruments |
The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined 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 the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand 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 the Company uses for its fair value measurements.
Cash and cash equivalents
Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.
Derivative instruments
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
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.
8
At March 31, 2010, the types of derivative instruments utilized by the Company included costless collars and swaps. 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 has classified these instruments as Level 2.
Credit facility
The recorded value of the Company’s credit facility approximates fair value as it bears interest at a floating rate.
Asset retirement obligations
The Company uses the income approach to recognize the estimated liability for future costs associated with the abandonment of its oil and gas properties. The Company’s asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs include 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which is based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate.
The following table provides a summary of the fair values of assets and liabilities measured at fair value:
| | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
|
Assets | | | | | | | | | | | | | | | | |
Derivative instruments — Commodity forward contracts | | $ | — | | | $ | 8,465 | | | $ | — | | | $ | 8,465 | |
| | | | | | | | | | | | |
Total assets at fair value | | $ | — | | | $ | 8,465 | | | $ | — | | | $ | 8,465 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Asset retirement obligation | | $ | — | | | $ | — | | | $ | 4,834 | | | $ | 4,834 | |
| | | | | | | | | | | | |
Total liabilities at fair value | | $ | — | | | $ | — | | | $ | 4,834 | | | $ | 4,834 | |
| | | | | | | | | | | | |
A reconciliation of the Company’s asset retirement obligation liability is below:
| | | | |
December 31, 2009 asset retirement obligation | | $ | 4,807 | |
| | | | |
Liabilities incurred | | | 7 | |
Accretion expense | | | 20 | |
| | | |
| | | | |
March 31, 2010 asset retirement obligation | | $ | 4,834 | |
| | | |
The accretion expense recorded during the period is recorded in the production costs line item on the consolidated statement of income.
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2010.
Concentration of credit risk
Financial instruments which potentially subject the Company to credit risk consist of the Company’s accounts receivable and its derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas industry, including those from a 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.
At March 31, 2010 the Company’s derivative financial instruments were held with two counterparties. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty.
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5. | | 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 the 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 did not recognize any impairment charges during the quarters ended March 31, 2010 and 2009.
The Company recognized stock-based compensation expense of $276 during the quarter ended March 31, 2010, as compared to $468 in the quarter ended March 31, 2009.
Compensation expense related to stock options is calculated using the Black Scholes valuation model. 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 and contractual expiration dates. 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.
A summary of stock option activity under the Company’s various stock option plans as of March 31, 2010 and changes during the three months ended March 31, 2010 is presented below:
| | | | | | | | | | | | | | | | |
| | | | | | | | | | Weighted- | | | | |
| | | | | | | | | | Average | | | | |
| | | | | | Weighted- | | | Remaining | | | | |
| | | | | | Average | | | Contractual | | | Aggregate | |
| | | | | | Exercise | | | Term (in | | | Intrinsic | |
Options: | | Shares | | | Price | | | years) | | | Value | |
Outstanding at January 1, 2010 | | | 647,897 | | | $ | 15.06 | | | | 4.7 | | | | | |
Granted | | | 80,380 | | | $ | 4.50 | | | | | | | | | |
Exercised | | | — | | | | | | | | | | | | | |
Cancelled/expired | | | (10,000 | ) | | $ | 14.00 | | | | | | | | | |
| | | | | | | | | | | | | | | |
Outstanding at March 31, 2010 | | | 718,277 | | | $ | 13.89 | | | | 4.9 | | | $ | — | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Exercisable at March 31, 2010 | | | 310,535 | | | $ | 15.23 | | | | 3.7 | | | $ | — | |
| | | | | | | | | | | | |
The Company measures the fair value of the stock awards based upon the fair market value of its common stock on the date of grant and recognizes the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate and recognizes the compensation costs for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.
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Nonvested stock awards as of March 31, 2010 and changes during the three months ended March 31, 2010 were as follows:
| | | | | | | | |
| | | | | | Weighted- | |
| | | | | | Average | |
| | | | | | Grant Date | |
Stock Awards: | | Shares | | | Fair Value | |
Nonvested at January 1, 2010 | | | 87,448 | | | $ | 12.38 | |
Granted | | | 20,331 | | | $ | 4.50 | |
Vested | | | (15,622 | ) | | $ | 5.33 | |
Forfeited/returned | | | — | | | $ | — | |
| | | | | | | |
Nonvested at March 31, 2010 | | | 92,157 | | | $ | 11.68 | |
| | | | | | | |
As part of the acquisition of Petrosearch, the Company assumed all outstanding warrants to purchase common stock that had been issued by Petrosearch prior to the merger. At March 31, 2010, the Company had two tranches of warrants outstanding; 10,310 warrants with an exercise price of $34.64 that expire November 2010; and 8,660 warrants with an exercise price of $21.25 that expire December 2011. In February 2010, 14,691 warrants with an exercise price of $46.19 expired. The warrants had no intrinsic value at March 31, 2010.
Double Eagle is required to record income tax expense for financial reporting purposes, however the Company does not anticipate any payments of current tax liabilities in the near future due to its net operating loss carryforwards.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2010, 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 2005 and for state and local tax authorities for years before 2004. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.
As part of the Company’s cash management program, at March 31, 2010, the Company had a $75 million revolving line of credit in place with $45 million available for borrowing based on several factors, including its current borrowing base and the commitment levels by participating banks. The credit facility is collateralized by the Company’s oil and gas producing properties. As of March 31, 2010, the balance outstanding of $31.0 million had been used to fund capital expenditures primarily on the Company-operated Catalina Unit expansion and other non-operated projects in the Atlantic Rim in 2008, as well as projects in the Pinedale Anticline in 2008, 2009 and 2010. Effective February 5, 2010, the Company renegotiated its credit agreement primarily to extend the maturity date of the facility from July 31, 2010 to January 31, 2013. The Company paid approximately $450 in one-time financing fees related to renegotiating this facility.
Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. As of March 31, 2010, the interest rate on the line of credit was 4.5%. For the quarters ended March 31, 2010 and 2009, the Company incurred interest expense of $360 and $300, respectively, on the credit facility. The Company capitalized interest costs of $50 and $300 for the quarters ended March 31, 2010 and 2009, respectively.
Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants include maintaining (i) a current ratio, as defined in the agreement, of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of March 31, 2010, the Company was in compliance with all financial covenants. If the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
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9. | | Acquisition of Petrosearch |
On August 6, 2009, the Company acquired 100% of the common and preferred shares of Petrosearch in exchange for approximately 1.8 million shares of Double Eagle common stock, valued at approximately $7.3 million, and cash consideration of $873, for a total purchase price of approximately $8.1 million. Effective with the acquisition, each Petrosearch shareholder received .0433 shares of Double Eagle common stock and $0.0211 for each share of Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, such shareholder held. As result of the merger, Petrosearch became a wholly-owned subsidiary of the Company. Petrosearch is an independent crude oil and natural gas exploration and production company, with properties in Texas and Oklahoma. Petrosearch had approximately $8,606 in cash and cash equivalents at the time of acquisition, which the Company believes enhanced the Company’s financial position and ability to finance its current operations and future developmental projects. The Company’s results of operations include the effect of the Petrosearch acquisition from the closing date.
10. | | Series A Cumulative Preferred Stock |
In 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share.
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, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at its option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the accompanying Consolidated Balance Sheets due to the following redemption provision. Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” the Company 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, 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 of the Company’s common stock.
11. | | Comprehensive Income (Loss) |
The components of comprehensive income (loss) were as follows:
| | | | | | | | |
| | For the Quarter Ended March 31, | |
| | 2010 | | | 2009 | |
Net income attributable to common stock | | $ | 5,178 | | | $ | 76 | |
Change in derivative instrument fair value, net of tax of $771 and $0 | | | 1,252 | | | | (4,865 | ) |
Reclassification to earnings | | | — | | | | 4,147 | |
| | | | | | |
Comprehensive income (loss) | | $ | 6,430 | | | $ | (642 | ) |
| | | | | | |
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The components of accumulated other comprehensive income were as follows:
| | | | | | | | |
| | March 31, | | | December 31, | |
| | 2010 | | | 2009 | |
Net change in derivative instrument fair value, net of tax of $2,020 and $1,249 | | $ | 3,569 | | | $ | 2,317 | |
| | | | | | |
Total accumulated other comprehensive income, net | | $ | 3,569 | | | $ | 2,317 | |
| | | | | | |
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 exploration project. The unexpended portion of the deposits at March 31, 2010 and December 31, 2009 totaled $612 and $611, respectively.
Legal proceedings
From time to time, the Company is involved in various legal proceedings, including the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.
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, the Company continued to recognize sales for its share of production and has consistently collected on the receivables due. 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, the Company received the proceeds for its share of sulfur sales dating back to February 2002 and continues to receive its respective share on an on-going basis.
On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the US District Court of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and intends to defend this case vigorously.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and its subsidiaries, as a consolidated entity, unless the context suggests otherwise. Unless the context suggests otherwise, the amounts set forth in Part I and Part II herein are in thousands, except units of production, ratios, share or per share amounts.
FORWARD-LOOKING STATEMENTS
This Quarterly Report onForm 10-Q 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 thisForm 10-Q 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 our Annual Report onForm 10-K for the year ended December 31, 2009, including the following:
| • | | Our ability to maintain adequate liquidity in connection with low oil and gas prices; |
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| • | | The changing political environment in which we operate; |
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| • | | Our ability to continue to develop our Atlantic Rim project; |
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| • | | Our ability to obtain, or a decline in, oil or gas production; |
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| • | | A decline in oil or gas prices; |
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| • | | Our ability to increase our natural gas and oil reserves; |
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| • | | Incorrect estimates of required capital expenditures; |
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| • | | The amount and timing of capital deployment in new investment opportunities; |
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| • | | The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment; |
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| • | | Our future capital requirements and availability of capital resources to fund capital expenditures; |
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| • | | Our ability to successfully integrate and profitably operate any future acquisitions; |
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| • | | Increases in the cost of drilling, completion and gas collection or other costs of production and operations; |
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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, tax rates or policies, interest rates 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, climate change 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 current or future litigation or similar disputes and the impact on any such outcome or related settlements. |
We also may 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.
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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.
Business Overview and Strategy
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 on the NASDAQ Capital Market, under the symbol “DBLEP” on July 3, 2007. It began trading 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, telephone number (303) 794-8445. Our operations offices are located at 777 Overland Trail, Casper, Wyoming 82601, telephone number (307) 237-9330. Our website is www.dble.com.
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 are currently focused on two core properties located in southwestern Wyoming, where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin, and tight sands gas reserves and production in the Pinedale Anticline. The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit agreements between the working interest partners. 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”) that surround the producing wells as a percentage of the entire acreage of the PA. This PA, and the associated working interest, will change as more wells and acreage are added to the PA.
Following are summary comments of our performance in several key areas during the quarter ended March 31, 2010
| • | | Average Daily Production |
| | | During the quarter ended March 31, 2010, our total average daily net production decreased 2% to 24,907 Mcfe as compared to average daily production of 25,340 Mcfe during the same prior-year period. The changes in production by major operating area are discussed below. |
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| | | Atlantic Rim.During the quarter ended March 31, 2010, average daily net production at the Atlantic Rim increased 3% to 18,261 Mcfe, as compared to 17,797 Mcfe during the first quarter of 2009. Average daily net production at our Catalina Unit decreased 6% to 15,599 Mcfe, as compared to 16,583 Mcfe during the same prior-year period. The decrease was due in part to the continuation of our well enhancement program that began in the third quarter of 2009, which requires wells to be temporarily off-line. In addition, we are reconfiguring our compressors in an effort to maximize well performance by reducing suction pressure at the well head, which is expected to increase the output from each well. Average daily production, net to our interest, at the Sun Dog and Doty Mountain Units increased 119% to 2,662 Mcfe, as compared to average daily production of 1,214 Mcfe during the first quarter of 2009. The increase was primarily due to the additional compression capacity added at the Doty Mountain Unit in the first quarter of 2010 and increased production from well stimulations in the Sun Dog Unit. |
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| | | Pinedale Anticline. Average daily production at the Pinedale Anticline decreased 18% to 5,014 Mcfe for the quarter ended March 31, 2010, as compared to 6,148 Mcfe in the first quarter of 2009. Management believes that the production decline at the Mesa Units is related to the operator managing the production flow from the field due to the low gas prices in the Rocky Mountain region and the planned deferral of well completions during the coldest winter months each year. |
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| | | Madden Deep Unit. During the quarter ended March 31, 2010, our average daily net production at the Madden Deep Unit increased 51% to 584 Mcfe, as compared to 388 Mcfe in the quarter ended March 31, 2009. |
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| | | During the quarter ended March 31, 2010, net oil and gas sales increased 5% to $11,049, as compared to $10,500 during the first quarter of 2009. The increase in oil and gas sales was driven by higher natural gas prices. During the quarter ended March 31, 2010, the average CIG price increased 57% as compared to the same prior-year period. Our average gas price received decreased 20%, however, to $4.70 from $5.90 for the same period primarily due to lower recognized income from our derivative instruments. In calculating our average realized gas price, we sum 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of income; 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of income; and 3) realized gain/(loss) on our economic hedges, which is included in our price risk management activities line on the consolidated statement of income, totaling $(223) and $2,926, for the quarters ended March 31, 2010 and 2009, respectively. Due to the strength of our hedges in the first quarter of 2009, we realized a gas price that was $2.86 higher than the average market CIG price during the period. Oil and gas sales, plus the realized settlements on our derivative instruments included within the price risk management line on the consolidated statement of income, totaled $10,826 for the quarter ended March 31, 2010, as compared to $13,426 for the first quarter of 2009. |
| • | | Cash Flow from Operations |
| | | During the quarter ended March 31, 2010, we generated cash flow from operations of $9,692, as compared to cash flow of $6,935 in the quarter ended March 31, 2009. |
OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to continue our long-term strategic plan, including our 2010 capital program (see Capital Requirements below). We intend to use capital resources made available from future operating cash flow and through our $75 million credit facility ($45 million credit availability), to fund this activity. We also may consider additional offerings of securities. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or what the terms of any additional financing would be.
Information about our financial position is presented in the following table:
| | | | | | | | |
| | March 31, | | | December 31, | |
| | 2010 | | | 2009 | |
| | (unaudited) | | | | | |
Financial Position Summary | | | | | | | | |
Cash and cash equivalents | | $ | 5,449 | | | $ | 5,682 | |
Working capital | | $ | 5,850 | | | $ | (4,067 | ) |
Balance outstanding on credit facility | | $ | 31,000 | | | $ | 34,000 | |
Stockholders’ equity and preferred stock | | $ | 91,404 | | | $ | 84,696 | |
Ratios | | | | | | | | |
Debt to total capital ratio | | | 25.3 | % | | | 28.6 | % |
Total debt to equity ratio | | | 58.0 | % | | | 72.8 | % |
During the quarter ended March 31, 2010, our working capital increased to $5,850 compared to negative working capital of $(4,067) at December 31, 2009. The higher working capital is primarily the result of an increase in the fair value of our derivative contracts expected to settle within one year. Based on changes in the expected commodity prices, certain derivative contracts moved from a current liability position at December 31, 2009 to a current asset position at March 31, 2010. In addition, our accounts payable and accrued liabilities balance decreased $2,184 from December 31, 2009, primarily due to a slowdown in work-over and drilling activity at our non-operated properties.
Cash flow activities
The table below summarizes our cash flows for the quarters ended March 31, 2010 and 2009, respectively:
| | | | | | | | |
| | Quarter ended March 31, | |
| | 2010 | | | 2009 | |
| | (unaudited) | |
Cash provided by (used in): | | | | | | | | |
Operating activities | | $ | 9,692 | | | $ | 6,935 | |
Investing activities | | | (5,853 | ) | | | (21,546 | ) |
Financing activities | | | (4,072 | ) | | | 16,782 | |
| | | | | | |
Net change in cash | | $ | (233 | ) | | $ | 2,171 | |
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During the quarter ended March 31, 2010, net cash provided by operating activities was $9,692 compared to $6,935 in the same prior-year period. During the quarter ended March 31, 2010, the primary sources of cash were $6,109 of net income, which was net of non-cash charges of $4,560 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense and non-cash stock-based compensation expense of $276. In addition, we had an increase in accounts payable and accrued expenses from operations of $3,901 and an increase of $3,457 in provision for deferred income taxes. These increases were partially offset by the non-cash gain on derivative contracts of $8,045.
During the quarter ended March 31, 2010, net cash used in investing activities was $5,853, as compared to $21,546 in the same prior-year period. Drilling activity slowed significantly in 2009, and as a result, our cash outflow related to capital expenditures also decreased as compared to the prior year. The capital expenditures in the first quarter of 2010 primarily related to non-operated drilling in the Pinedale Anticline.
During the quarter ended March 31, 2010, we had net cash used by financing activities of $4,072, as compared to net cash provided by financing activities of $16,782 in the same prior-year period. In the first quarter of 2009, we had significant draws on our credit facility to fund costs incurred in the drilling program in the fourth quarter of 2008. In contrast, we were able to repay $3,000 on our credit facility in the first quarter of 2010 due to increased operating cash flow and slower drilling and workover activity. We also expended cash to make the first quarter dividend payment totaling $931. Dividends are expected to continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.
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-Q.
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 are the derivative instruments discussed in “Contracted Volumes” below. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.
Line of Credit
Effective February 5, 2010, the Company renegotiated its $75 million credit facility, to extend the maturity date from July 31, 2010 to January 31, 2013. The borrowing availability on the facility remained at $45 million, collateralized by our oil and gas properties. There were no material changes to any other terms of the credit facility, including our financial and non-financial covenants. The Company paid approximately $450 in one-time financing fees related to renegotiating this facility.
As of March 31, 2010, the outstanding balance on our credit facility was $31.0 million. The interest rate as of March 31, 2010, calculated in accordance with the agreement, was 4.5%, compared to an interest rate between 6.0% and 6.75% for the first quarter of March 31, 2009.
For the quarters ended March 31, 2010 and 2009, we incurred interest expense of $360 and $300, respectively, on the credit facility. We capitalized interest costs of $50 and $300 for the quarters ended March 31, 2010 and 2009, respectively.
We are subject to certain financial and non-financial covenants with respect to the above credit facility, including requirements to maintain (i) a current ratio, as defined in the agreement, of at least 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to EBITAX ratio of less than 3.5 to 1.0. As of March 31, 2010, we were in compliance with all covenants under the facility. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
Our borrowing base is subject to redetermination each June 15 and December 15, beginning June 15, 2010. We currently have a borrowing base in excess of our current borrowing availability.
Capital Requirements
Our estimated capital budget for 2010 is approximately $15-$20 million for drilling up to eight wells within the Catalina Unit, and ongoing non-operated development programs on the Pinedale Anticline and within the Sun Dog and Doty Mountain Units. The 2010 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, or potential acquisitions. We expect to fund our 2010 capital expenditures with cash provided by operating activities and funds made available through our $75 million credit facility. We may find it necessary in the future to raise additional funds through private placements or registered offerings of equity or debt.
17
Contractual Obligations
The impact that our contractual obligations as of March 31, 2010 are expected to have on our liquidity and cash flows in future periods is:
| | | | | | | | | | | | | | | | | | | | |
| | | | | | One year | | | 2 – 3 | | | 4 – 5 | | | More than | |
| | Total | | | or less | | | Years | | | Years | | | 5 Years | |
Credit facility (a) | | $ | 31,000 | | | $ | — | | | $ | 31,000 | | | $ | — | | | $ | — | |
Interest on line of credit (b) | | | 4,014 | | | | 1,414 | | | | 2,600 | | | | — | | | | — | |
Capital leases | | | 1,316 | | | | 752 | | | | 564 | | | | — | | | | — | |
Operating leases | | | 8,761 | | | | 2,350 | | | | 5,211 | | | | 1,143 | | | | 57 | |
| | | | | | | | | | | | | | | |
Total contractual cash commitments | | $ | 45,091 | | | $ | 4,516 | | | $ | 39,375 | | | $ | 1,143 | | | $ | 57 | |
| | | | | | | | | | | | | | | |
| | |
(a) | | The amount listed reflects the balance outstanding as of March 31, 2010. Any balance outstanding on our credit facility at January 31, 2013, will be due at that time. |
|
(b) | | Assumes the interest rate on our credit facility is consistent with that of March 31, 2010. |
RESULTS OF OPERATIONS
Quarter ended March 31, 2010 compared to the quarter ended March 31, 2009
Oil and gas sales volume and price comparisons
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended March 31, | | | Percent | | | Percent | |
| | 2010 | | | 2009 | | | Volume | | | Price | |
| | Volume | | | Average Price | | | Volume | | | Average Price | | | Change | | | Change | |
Product: | | | | | | | | | | | | | | | | | | | | | | | | |
Gas (Mcf) | | | 2,200,010 | | | $ | 4.70 | | | | 2,234,415 | | | $ | 5.90 | | | | -2 | % | | | -20 | % |
Oil (Bbls) | | | 6,936 | | | $ | 71.43 | | | | 7,696 | | | $ | 30.68 | | | | -10 | % | | | 133 | % |
Mcfe | | | 2,241,624 | | | $ | 4.83 | | | | 2,280,591 | | | $ | 5.89 | | | | -2 | % | | | -18 | % |
Our average gas price realized for the quarter ended March 31, 2010 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of income; 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of income; and 3) realized gain/(loss) on our economic hedges, which is included in our price risk management activities line on the consolidated statement of income, totaling $(223) and $2,926, for the quarters ended March 31, 2010 and 2009, respectively. This amount is divided by the total Mcfe volume for the period.
For the quarter ended March 31, 2010, total net production decreased 2% to 2,242 MMcfe, as compared to the quarter ended March 31, 2009. The decrease is due to lower production volumes at the Catalina Unit and Mesa Units, as discussed below.
During the quarter ended March 31, 2010, average daily net production at the Atlantic Rim increased 3% to 18,261 Mcfe, as compared to 17,797 Mcfe during the same prior-year period. Average daily net production at our Catalina Unit decreased 6% to 15,599 Mcfe, as compared to 16,583 Mcfe during the first quarter of 2009. The decrease was due in part to the continuation of our well-enhancement program, which began in the third quarter of 2009. This program requires individual wells to be off-line for short periods of time while the well is worked-over. In addition, we began reconfiguring our compressors in March 2010 in an effort to maximize well performance by reducing suction pressure at the well head, which is expected to increase the output from each well. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 119% to 2,662 Mcfe, as compared to average daily production of 1,214 during the same prior-year period. The increase was primarily due to the additional compression capacity added at the Doty Mountain Unit in the first quarter of 2010 and increased production from well stimulations in the Sun Dog Unit.
Average daily production in the Pinedale Anticline decreased 18% during the quarter ended March 31, 2010, to 5,014 Mcfe, as compared to 6,148 Mcfe in the same prior-year period. Management believes that the production decline at the Mesa Units is related to the operator managing the production flow from the field due to the low gas prices in the Rocky Mountain region and the planned deferral of well completions during the coldest winter months each year The operator at the Mesa Units has informed us that it is in process of drilling 16 additional wells, which are expected to come on-line in the second and third quarters of 2010.
18
During the quarter ended March 31, 2009, the average daily production at the Madden Unit increased 51% to 584 Mcfe compared to 388 Mcfe in the same prior-year period.
For the quarter ended March 31, 2010, oil and gas sales, plus the realized settlements on our derivative instruments included within the price risk management line on the consolidated statement of income, totaled $10,826 as compared to $13,426 for the first quarter of 2009. During the quarter ended March 31, 2010, our average gas price realized decreased 20%, to $4.70 from $5.90, as compared to an increase of 57% in the average CIG index price. Due to the strength of our hedges in the first quarter of 2009, we realized a gas price that was $2.86 higher than the average market CIG price during the period, and therefore our 2010 realized average price did not change from our 2009 realized average price in a manner consistent with the change in the CIG index prices.
Transportation and gathering revenue
During the quarter ended March 31, 2010, transportation and gathering revenue decreased 6% to $1,487 from $1,587 for the quarter ended March 31, 2009. The Company receives fees 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 decrease in revenue is consistent with the decrease in production volumes at the Catalina Unit discussed above.
Price risk management activities
We recorded a net gain on our derivative contracts that did not qualify for cash flow hedge accounting of $7,822 for the quarter ended March 31, 2010, as compared to a loss of $(1,140) for the quarter ended March 31, 2009. For the first quarter of 2010, this amount consisted of an unrealized non-cash gain of $8,045, which represents a change in the fair value of our mark-to-market derivative instruments at March 31, 2010, and a net realized loss of $(223) related to the settlements of certain of our economic hedges.
Oil and gas production expenses, depreciation, depletion and amortization
| | | | | | | | |
| | Quarter Ended March 31, | |
| | 2010 | | | 2009 | |
| | (unaudited, in dollars per mcfe) | |
Average price | | $ | 4.83 | | | $ | 5.89 | |
| | | | | | | | |
Production costs | | | 0.87 | | | | 0.71 | |
Production taxes | | | 0.58 | | | | 0.39 | |
Depletion and amortization | | | 1.98 | | | | 1.88 | |
| | | | | | |
Total operating costs | | | 3.43 | | | | 2.98 | |
| | | | | | |
| | | | | | | | |
Gross margin | | $ | 1.40 | | | $ | 2.91 | |
| | | | | | |
Gross margin percentage | | | 29 | % | | | 49 | % |
| | | | | | |
During the quarter ended March 31, 2010, well production costs increased 21% to $1,943, as compared to $1,611 during the same prior-year period, and production costs in dollars per Mcfe increased 23%, or $0.16 to $0.87, as compared to the same prior-year period. The increase in production costs in total, and on a per Mcfe basis, is primarily due to higher workover costs related to the well enhancement program at the Catalina Unit, as well as an increase in the number of producing wells at the Mesa Units.
Depreciation, depletion, and amortization (“DD&A”) for the quarter ended March 31, 2010 increased 4% to $4,540, as compared to $4,382 in the same prior-year period, and depletion and amortization related to producing assets increased 4% to $4,437, as compared to $4,280 in the same prior-year period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 5%, or $0.10, to $1.98, as compared to the same prior-year period.
19
Pipeline operating costs
During the quarter ended March 31, 2010, pipeline operating costs increased to $1,149 from $568 for the first quarter of 2009. The Catalina Unit expanded from 47 producing wells to 67 producing wells throughout the first quarter of 2009. As a result of this expansion, our power and fuel costs increased. The 2010 pipeline operating costs reflect a full quarter of the increased power and fuel charges. In addition, we incurred consulting costs related to refiguring our compressor units. The 2009 expenses were net of a vendor credit we received for compressor downtime, which lowered the pipeline operating costs for the period.
General and administrative expenses
General and administrative expenses decreased 8% to $1,534 for the quarter ended March 31, 2010, as compared to $1,674 for the quarter ended March 31, 2009. Our general and administrative expenses were lower in the first quarter of 2010 due primarily to $259 of expenses that were incurred in the first quarter of 2009 related to the acquisition of Petrosearch Energy Corporation. In addition, stock-based compensation decreased by approximately $192 due primarily to the timing of our 2009 executive bonus payout, which was paid at the end of 2009, instead of the first quarter of 2010, as had occurred in the prior year. These decreases were offset by a $160 increase in salary and salary-related expenses, primarily driven by non-executive salary increases and higher benefit costs, higher audit and tax fees of approximately $79, and higher non-merger related legal fees of approximately $39.
Income taxes
During the quarter ended March 31, 2010, we recorded income tax expense of $3,457 compared to income tax expense of $631 during the same prior-year period. Our effective tax rate for the quarter ended March 31, 2010 was 36.1% compared to 38.5% for the first quarter of 2009. The rate was lower in the 2010 period due to a reduction in permanent income tax differences related to stock option expense. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2010 at an expected federal and state rate of approximately 35.0%.
CONTRACTED VOLUMES
Changes in the market price of oil and natural gas can significantly affect our profitability and cash flow. We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price. Historically these derivative instruments have consisted of fixed delivery contracts, swaps, options and costless collars. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.
Our outstanding derivative instruments as of March 31, 2010 are summarized below (volume and daily production are expressed in Mcf):
| | | | | | | | | | | | | | |
| | Remaining | | | | | | | | | | |
| | Contractual | | | Daily | | | | | | | Price |
Type of Contract | | Volume | | | Production | | | Term | | Price | | Index (1) |
| | | | | | | | | | | | | | |
Fixed Price Swap | | | 3,300,000 | | | | 12,000 | | | 1/10-12/10 | | $4.30 | | CIG |
Fixed Price Swap | | | 2,920,000 | | | | 8,000 | | | 1/11-12/11 | | $7.07 | | CIG |
Costless Collar | | | 2,435,000 | | | | 5,000 | | | 8/09-7/11 | | $4.50 floor | | NYMEX |
| | | | | | | | | | | | $7.90 ceiling | | |
Costless Collar | | | 3,045,000 | | | | 5,000 | | | 12/09-11/11 | | $4.50 floor | | NYMEX |
| | | | | | | | | | | | $9.00 ceiling | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Total | | | 11,700,000 | | | | | | | | | | | |
| | | | | | | | | | | | |
| | |
(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. |
20
Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional discussion on the accounting treatment of our derivative contracts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risks
Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the quarter ended March 31, 2010, our income before income taxes would have changed by $490 for each $0.50 change per Mcf in natural gas prices and $6 for each $1.00 change per Bbl in crude oil prices.
We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments typically consistent of forward sales contracts, swaps, and collars, which allow us to effectively “lock in” a portion of our future production of natural gas at prices that we considered favorable to Double Eagle at the time we entered into the contract. These derivative instruments which have differing expiration dates, are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contracted Volumes.”
Interest Rate Risks
At March 31, 2010 we had a total of $31.0 million outstanding under our $75 million credit facility. We pay interest on outstanding borrowings under our credit facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and the prevailing market rates. The minimum interest rate is 4.5%. 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 March 31, 2010, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $310 before taxes. As of March 31, 2010, the interest rate on the line of credit, calculated in accordance with the agreement, was 4.5%.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer), of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) have concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.
There has been no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
21
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are involved in various legal proceedings, including the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
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.
On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the US District Court of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and intends to defend this case vigorously.
ITEM 1A. RISK FACTORS
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2008 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.
ITEM 6. EXHIBITS
The following exhibits are filed as part of this report:
| | | | |
Exhibit | | Description: |
| | | | |
| 3.1 | (a) | | Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | | |
| 3.1 | (b) | | Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | | |
| 3.1 | (c) | | Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | | |
| 3.1 | (d) | | Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001). |
| | | | |
| 3.1 | (e) | | Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007). |
| | | | |
| 3.1 | (f) | | Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007). |
22
| | | | |
Exhibit | | Description: |
| | | | |
| 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). |
| | | | |
| 3.1 | (i) | | Amendment to Bylaws, New Article II, Section 3 — Quorum (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated March 5, 2010). |
| | | | |
| 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) | | Credit Agreement dated February 5, 2010 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; (incorporated by reference from Exhibit 10.1, of the Company’s Current report of Form 8-K dated February 9, 2010). |
| | | | |
| 10.1 | (b) | | Employment Agreement between the Company and Ashley Jenkins, dated January 1, 2010 (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated January 7, 2010). |
| | | | |
| 31.1 | | | Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a-14(a) and Rule 15a-14(a) of the Securities Exchange Act, as amended. |
| | | | |
| 31.2 | | | Certification of Chief Financial Officer (Principal Accounting Officer) pursuant to Rule 13a-14(a) and Rule 15a-14(a) of the Securities Exchange Act, as amended. |
| | | | |
| 32 | | | Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
23
SIGNATURES
Pursuant to the requirements 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. (Registrant) | |
|
Date: April 29, 2010 | By: | /s/ Richard D. Dole | |
| | Richard D. Dole | |
| | Chief Executive Officer (Principal Executive Officer) | |
| | | | |
Date: April 29, 2010 | By: | /s/ Kurtis S. Hooley | |
| | Kurtis S. Hooley | |
| | Chief Financial Officer (Principal Accounting Officer) | |
24
EXHIBIT INDEX
| | | | |
Exhibit Number | | Description |
| | | | |
| 3.1 | (a) | | Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | | |
| 3.1 | (b) | | Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | | |
| 3.1 | (c) | | Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001). |
| | | | |
| 3.1 | (d) | | Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001). |
| | | | |
| 3.1 | (e) | | Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007). |
| | | | |
| 3.1 | (f) | | Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007). |
| | | | |
| 3.1 | (g) | | Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007). |
| | | | |
| 3.1 | (h) | | Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007). |
| | | | |
| 3.1 | (i) | | Amendment to Bylaws, New Article II, Section 3 — Quorum (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated March 5, 2010). |
| | | | |
| 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). |
25
| | | | |
Exhibit Number | | Description |
| | | | |
| 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) | | Credit Agreement dated February 5, 2010 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; (incorporated by reference from Exhibit 10.1, of the Company’s Current report of Form 8-K dated February 9, 2010). |
| | | | |
| 10.1 | (b) | | Employment Agreement between the Company and Ashley Jenkins, dated January 1, 2010 (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated January 7, 2010). |
| | | | |
| 31.1 | | | Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a-14(a) and Rule 15a-14(a) of the Securities Exchange Act, as amended. |
| | | | |
| 31.2 | | | Certification of Chief Financial Officer (Principal Accounting Officer) pursuant to Rule 13a-14(a) and Rule 15a-14(a) of the Securities Exchange Act, as amended. |
| | | | |
| 32 | | | Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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