|• FORM 10-Q • EX-31.1 • EX-31.2 • EX-32 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE • XBRL TAXONOMY EXTENSION LABEL LINKBASE • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE|
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended March 31, 2012
For the transition period from to
Commission File Number 1-33571
DOUBLE EAGLE PETROLEUM CO.
(Exact name of registrant as specified in its charter)
(Registrants telephone number, including area code)
(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. Yes x No ¨
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). Yes x No ¨
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.
Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date.
DOUBLE EAGLE PETROLEUM CO.
DOUBLE EAGLE PETROLEUM CO.
(Amounts in thousands of dollars except share data)
The accompanying notes are an integral part of the consolidated financial statements.
DOUBLE EAGLE PETROLEUM CO.
(Amounts in thousands of dollars except share and per share data)
The accompanying notes are an integral part of the consolidated financial statements.
DOUBLE EAGLE PETROLEUM CO.
(Amounts in thousands of dollars)
The accompanying notes are an integral part of the consolidated financial statements.
DOUBLE EAGLE PETROLEUM CO.
(Amounts in thousands of dollars)
The accompanying notes are an integral part of the consolidated financial statements.
DOUBLE EAGLE PETROLEUM CO.
(Amounts in thousands of dollars except share and per share data)
Basis of presentation
The accompanying unaudited interim consolidated financial statements and related notes were prepared by Double Eagle Petroleum Co. (Double Eagle or the Company) in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial reporting and were prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the SEC). Certain information and note disclosures normally included in the annual audited consolidated financial statements 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.
Certain amounts in the 2011 consolidated financial statements have been reclassified to conform to the 2012 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 Companys consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2011, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.
The unaudited interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto included in the Annual Report on Form 10-K filed for the year ended December 31, 2011 with the SEC.
Principles of consolidation
The unaudited interim consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation (Petrosearch) and Eastern Washakie Midstream LLC (EWM). In August 2009, the Company acquired Petrosearch, which has operations in Texas and Oklahoma. In 2006, 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. This fee related to gas gathering is also eliminated in consolidation.
Recently adopted accounting pronouncements
The Company adopted Accounting Standards Update No. 2011-05 (ASC No. 2011-05), an update to ASC Topic 220, Comprehensive Income, effective January 1, 2012. The update amended current guidance to require companies to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. Under the single-statement approach, entities must include the components of net income, a total for net income, the components of other comprehensive income (OCI) and a total for comprehensive income. Under the two-statement approach, entities must report an income statement and, immediately following, a statement of OCI. We also adopted ASC No. 2011-12, which defers until further notice ASC No. 2011-05s requirement that items that are reclassified from other comprehensive income to net income be presented on the face of the financial statements. ASC No. 2011-05 required retrospective application. The adoption of these updates affected presentation only, and had no impact on the Companys financial position, results of operation or cash flows.
Basic earnings per share (EPS) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of shares of common stock outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on the Companys Series A Preferred Stock. The Company declared and paid cash dividends of $931 ($.5781 per share of preferred stock) for each of the three months ended March 31, 2012 and 2011.
The following is the calculation of basic and diluted weighted average shares outstanding and earnings per share of common stock for the periods indicated:
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:
The Companys 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 its 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 extent of the Companys risk management activities is controlled through policies and procedures that involve senior management and were approved by the Companys Board of Directors. Senior management is responsible for proposing hedging recommendations, executing the approved hedging plan, overseeing the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Companys Board of Directors is responsible for approving risk management policies and for establishing the Companys overall risk tolerance levels. The duration of the various derivative instruments depends on senior managements view of market conditions, available contract prices and the Companys operating strategy. Under the Companys credit agreement, the Company can hedge up to 90% of the projected proved developed producing reserves for the next 12 month period, and up to 80% of the projected proved producing reserves for the ensuing 24 month period.
In the first quarter of 2012, the Company accounted for all of its derivative instruments as mark-to-market derivative instruments. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Companys consolidated balance sheets and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of derivatives not designated as cash flow hedges also are recorded in the price risk management activities line on the consolidated statements of operations.
In 2011, the Company had one derivative instrument that was accounted for as a cash flow hedge. Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the consolidated balance sheets, and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (AOCI) and is subsequently reclassified into oil and gas sales on the consolidated statements of operations as the contracts settle. The last derivative instrument that the Company accounted for under cash flow hedge accounting settled in December 2011.
On the consolidated statements of cash flows, 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 creditworthy. In addition, the Companys 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 Companys 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. As of March 31, 2012, no party to any of the Companys derivative contracts has required any form of security guarantee.
The Company had the following commodity volumes under derivative contracts as of March 31, 2012:
Interest Rate Swap
The Company has a $30 million fixed interest rate swap contract in place with a third party to manage the risk associated with the floating interest rate on its credit facility. The contract is effective through December 31, 2012. In accordance with its credit facility, the Company pays interest amounts based upon the Eurodollar LIBOR rate, plus 1%, and plus a spread ranging from 1.25% to 2.0% depending on its outstanding borrowings. Under the interest rate swap terms, the Company swapped its floating LIBOR interest rate for a fixed LIBOR rate of 0.578%. This contract was not designated as a fair value hedge or cash flow hedge and is recorded at fair value on the consolidated balance sheets. Changes in fair value, both realized and unrealized, are recognized in interest expense, net on the consolidated statements of operations. On the statements of cash flows, the cash flows from the interest rate swap are classified as operating activities.
The table below contains a summary of all the Companys derivative positions reported on the consolidated balance sheet as of March 31, 2012, presented gross of any master netting arrangements:
The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statements of income for the three months ended March 31, 2012 and 2011, related to the Companys commodity derivatives was as follows:
Derivatives Designated as Cash Flow Hedging Instruments under ASC 815
The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations for the three months ended March 31, 2012 and 2011 was as follows:
Refer to Note 4 for additional information regarding the valuation of the Companys derivative instruments.
The Company records certain of its assets and liabilities on the consolidated balance sheets 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 in the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
The following table provides a summary of the fair values as of March 31, 2012 of assets and liabilities measured at fair value on a recurring basis:
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, 2012.
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.
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Companys own credit rating. The Company also performs an internal valuation to evaluate 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.
At March 31, 2012, the Company had various types of derivative instruments, which included costless collars and swaps. The natural gas derivative markets and interest rate swap markets are highly active. Although the Companys 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.
The recorded value of the Companys credit facility approximates fair value as it bears interest at a floating rate.
Concentration of credit risk
Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. Substantially all of the Companys receivables are within the oil and gas industry, including those from a third party gas marketing company. Collectability is dependent upon the financial wherewithal of each counterparty as well as the general economic conditions of the industry. The receivables are not collateralized.
The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. Net settlement refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.
The Company reviews the carrying values of its long-lived assets annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The impairment analysis performed by the Company may utilize Level 3 inputs. The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds.
In the three months ended March 31, 2012, the Company recorded impairment expense of $301 related to wells that were plugged and abandoned at a non-operated property. The Company did not record any proved property impairment expense in the three months ended March 31, 2011. The Company wrote off $4 and $73 during the three months ended March 31, 2012 and 2011, respectively, related to expired undeveloped leaseholds.
The Company recognized stock-based compensation expense totaling $414 for the three months ended March 31, 2012, and $275 for the three months ended March 31, 2011.
Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatilities are based on the historical volatility of the Companys common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Companys common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.
A summary of stock option activity under the Companys various stock option plans as of March 31, 2012 and changes during the three months ended March 31, 2012 is presented below:
The Company measures the fair value of 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 the compensation expenses net of a forfeiture rate and recognizes the compensation expenses 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.
Nonvested stock awards as of March 31, 2012 and changes during the three months ended March 31, 2012 were as follows:
In 2011, the Company adopted a Long-Term Incentive Plan (LTIP), under which the executive officers of the Company may earn up to an aggregate of 476,906 shares of common stock of the Company. The executive officers may earn one-third of the shares by continued employment with the Company through December 31, 2013. The remaining two-thirds may be earned through increases in the Companys adjusted net asset value, as defined. If the Company ultimately achieves the service requirements and performance objectives determined by the LTIP, the associated total share-based compensation expense is expected to be approximately $3.1 million, based on the grant date fair value. The compensation expense recorded by the Company in the three months ended March 31, 2012, included $140 related to the LTIP.
The Company is required to record income tax expense for financial reporting purposes. 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, 2012, 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 2007 and for state and local tax authorities for tax years before 2006.
As of March 31, 2012, the Company had a $150 million revolving line of credit in place with $60 million available for borrowing based on several factors, including the current borrowing base and the commitment levels by participating banks. The credit facility is collateralized by the Companys oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.
As of March 31, 2012, the balance outstanding of $42,000 on the credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects in the Pinedale Anticline, and the Companys Niobrara exploration project.
Borrowings under the revolving line of credit bear interest at 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 0.75% and 1.75% depending on the level of funds borrowed. The average interest rate on the facility at March 31, 2012 was 2.6%. For the three months ended March 31, 2012 and 2011, the Company incurred interest expense related to the credit facility of $329 and $326, respectively. The Company capitalized interest costs of $72 and $35 for the three months ended March 31, 2012 and 2011, respectively.
The Company has a $30 million fixed rate swap contract with a third party in place as an economic hedge against the floating interest rate on its credit facility. Under the hedge contract terms, the Company locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for this tranche of its outstanding debt, which, based on the Companys current level of outstanding debt translates to an interest rate on this tranche of approximately 3.08%. The contract is effective through December 31, 2012.
Under the credit facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio 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, 2012, the Company was in compliance with all financial and non-financial covenants. If the covenants are violated and the Company is unable to negotiate a waiver or amendment thereof, the lenders would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
In 2007, the stockholders of the Company approved an amendment to the Companys Articles of Incorporation to provide for the issuance of 10,000,000 shares of preferred stock, and the Company subsequently completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price 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 certain circumstances upon a change of ownership or control. Except pursuant to the special redemption upon a change of 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 consolidated balance sheets due to the following change of control redemption provision. Following a change of ownership or control of the Company 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. 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 Companys common stock.
In August 2011, the Company entered into an At-The-Market issuance sales agreement (ATM), which allows the Company to offer and sell shares of its common stock from time to time at an aggregate offering price of up to $20 million. The Companys sales agent may make sales of the Companys common stock in privately negotiated transactions or in any method permitted by law deemed to be an ATM offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NASDAQ Global Select Market or sales made through a market maker other than on an exchange. The Companys sales agent will make all sales using commercially reasonable efforts consistent with its normal sales and trading practices. The Company has no obligation to sell any shares in the ATM offering and may terminate the ATM offering at any time. No shares have been sold to date. The ATM agreement expires in August 2013.
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 Companys financial condition or results of operations.
On December 18, 2009, Tiberius Capital, LLC (Plaintiff), a stockholder of Petrosearch prior to the Companys acquisition (the Acquisition) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the District Court for the Southern District 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. On March 31, 2011, the District Court judge dismissed the case. The plaintiff filed a notice of appeal on April 29, 2011 and filed its appellate brief with the Second Circuit Court of Appeals on August 11, 2011. The Company filed its brief on October 13, 2011 supporting the District Courts March 31, 2011 opinion and judgment dismissing the case. The Second Circuit Court of Appeals will begin hearing the case on June 11, 2012.
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 herein are in thousands, except units of production, ratios, share or per share amounts.
This Quarterly Report on Form 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 Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 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 Part I, Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2011 and the following factors:
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.
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. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. Our common stock is publicly traded on the NASDAQ Global Select Market under the symbol DBLE and our Series A Cumulative Preferred Stock is traded on the NASDAQ Global Select Market under the symbol DBLEP. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.
Our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we primarily focus on: (i) new CBM gas development drilling; (ii) enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the development of tight sands gas wells at the Mesa Units on the Pinedale Anticline; (iv) expansion of our midstream business; (v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns and (vi) selectively pursuing strategic acquisitions or mergers.
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. The PA, and the associated working interest, may change as more wells and acreage are added to the PA.
OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit facilities and proceeds from offerings of equity securities. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, these sources of liquidity and capital have been sufficient to meet our needs and finance the growth of our business.
We currently have a $150 million credit facility in place with a $60 million borrowing base. We believe that the amounts available under our credit facility, combined with our net cash from operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2012 capital expenditure program (see Calendar 2012 Capital Spending Budget below). We also entered into an At-The-Market issuance sales agreement (ATM) in 2011, which allows us to offer and sell shares of our common stock from time to time, up to an aggregate offering price of $20 million. We have not sold any shares under the ATM to date and the ATM is in effect through August 2013. Depending on the timing and amounts of future projects, we may need to seek additional sources of capital. We can provide no assurance that we will be able to do so on favorable terms or at all. The Company currently has an effective Form S-3 shelf registration statement on file with the SEC, which has $150 million of securities available for issuance and provides us the ability to raise additional funds through registered offerings of equity, debt or other securities. We are conducting the ATM offering under the shelf registration statement. We also may issue equity or debt in private placements or obtain additional debt financing, which may be secured by our oil and gas properties, or unsecured.
Information about our financial position is presented in the following table:
Our working capital balance decreased 6% to $12,671 at March 31, 2012 as compared to $13,540 at December 31, 2011. The change in working capital is primarily the result of our lower cash balance at March 31, 2012 resulting from the decline in natural gas prices and payment of accounts payable and accrued expenses related to our 2011 drilling program.
Cash flow activities
The table below summarizes our cash flows for the three months ended March 31, 2012 and 2011, respectively:
During the three months ended March 31, 2012, net cash provided by operating activities was $4,176, as compared to $5,794 in the same prior-year period. The primary sources of cash during the three months ended March 31, 2012 were $328 of net income, which was net of non-cash charges of $4,651 related to DD&A and accretion expense, and non-cash stock-based compensation expense of $414. The non-cash expenses were partially offset by the non-cash gain on derivative contracts of $2,574. Our cash flow from operations in 2012 included $3,175 of income from cash settlements on our derivative instruments, as compared to $2,684 in the same prior year period. Our cash flow from operations was lower in the 2012 period primarily due to a 27% decrease in our average realized natural gas price. During the three month period ended March 31, 2011, we had a $7.07 Colorado Interstate Gas fixed price swap for 8,000 Mcf per day. We entered into this hedge in 2008, when the outlook for natural gas prices was significantly higher than it is today. For 2012, we currently have 15,000 Mcf per day hedged at between $5.05 and $5.10, based upon NYMEX pricing.
During the three months ended March 31, 2012, net cash used in investing activities was $10,257, as compared to $3,980 in the same prior-year period. During the first quarter of 2012, our spending primarily related to our Niobrara exploration well, which was spud in October 2011 and reached its total depth of 9,450 feet in February 2012. The total cost of this well was approximately $7.4 million. In addition, in the first quarter of 2012 we made payments related to our 2011 drilling program at Catalina. The capital expenditures in the first quarter of 2011 primarily related to non-operated drilling in the Pinedale Anticline.
During the three months ended March 31, 2012, we had net cash used by financing activities of $957, as compared to $1,074 in the same prior-year period. We expended cash in the first quarter of 2012 and 2011 to make our quarterly dividend payment totaling $931 in each period. 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.
At March 31, 2012, we had a $150 million credit facility in place with a $60 million borrowing base. The credit facility is collateralized by our oil and gas producing properties and other assets. At March 31, 2012, we had $42 million outstanding on the facility. We have depended on our credit facility over the past four years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim, including our 2010 working interest purchase in this field, projects in the Pinedale Anticline, and the drilling of our Niobrara exploration well.
Borrowings under the revolving line of credit bear interest at 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 0.75% and 1.75% depending on the level of funds borrowed. As of March 31, 2012, the average interest rate on the outstanding debt was 2.6%. We have a $30 million fixed rate swap contract with a third party in place as an economic hedge against the floating interest rate on its credit facility. Under the hedge contract terms, we have locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for this tranche of its outstanding debt, which, based on our current level of outstanding debt translates to an interest rate on this tranche of approximately 3.08%. The contract is effective through December 31, 2012.
We are subject to a number of financial and non-financial covenants under this facility. As of March 31, 2012, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
Our lending banks conduct an assessment of our available borrowing base semi-annually on April 1 and October 1. If natural gas prices continue to decrease for extended periods of time, our borrowing base could be reduced, thus limiting the future amounts of funds under the current facility. This may impact our ability to execute our 2012 capital expenditure program, or require that we seek alternative sources of capital. Upon any downward adjustment of the borrowing base, if the outstanding borrowings are in excess of the revised borrowing base, we may have to repay our indebtedness in excess of the borrowing base immediately, or in six monthly installments, or pledge additional properties as collateral. We may not have sufficient funds to make such repayments or additional properties to pledge as collateral. Our borrowing base was reaffirmed as of April 1, 2012 at $60 million.
For 2012, we have budgeted approximately $15 to $20 million for our development and exploration programs in the Atlantic Rim and Pinedale Anticline. We intend to participate in drilling 25 new production wells in the Doty Mountain Unit in the second half of 2012. We plan to participate in drilling approximately 15 new wells at the Mesa Units. We also have allocated capital in our 2012 capital budget to complete our Niobrara exploratory well, which reached total depth in February 2012. Upon completion of the core and log analysis on this well in the second quarter of 2012, we will determine the completion opportunities, if any, in the various formations. We expect to fund our 2012 capital expenditures with cash provided by operating activities and funds made available through our credit facility. Our 2012 capital budget does not include the impact of potential future exploration projects or possible acquisitions, which we continually evaluate.
The impact that our contractual obligations as of March 31, 2012 are expected to have on our liquidity and cash flows in future periods is:
Off-Balance Sheet Arrangements
As of March 31, 2012, we did not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of SEC regulation S-K.
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 had no interest in any unconsolidated SPEs or VIEs at any time during any of the periods presented.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011
The following analysis provides comparison of the three months ended March 31, 2012 and the three months ended March 31, 2011.
Oil and gas sales
Oil and gas sales decreased 45% to $6,031, which was largely attributed to a 42% decrease in the Colorado Interstate Gas, or CIG, market price, which is the index on which most of our natural gas volumes are sold. In addition, in the three months ended March 31, 2011, one of our derivative instruments was classified as a cash flow hedge, and the settlements related to this contract were included within oil and gas sales on the consolidated statement of operations. In the three months ended March 31, 2012, all of our derivative instrument settlements are included within price risk management activities on the consolidated statement of operations. The decrease in the natural gas market price was offset by an 8% increase in production volumes, discussed below.
As shown in the table on the following page, our average realized natural gas price decreased 27% to $3.52 per Mcf due to the decrease in the CIG market price, offset by the derivative instruments in place during the period. We calculate our average realized natural gas price by summing (1) production revenues received from third parties for the sale of our gas, which is included within oil and gas sales on the consolidated statements of operations, (2) realized gain (loss) on our economic hedges, which is included within price risk management activities, net on the consolidated statements of operations, totaling $3,175 and $343, for the three months ended March 31, 2012 and 2011, respectively, and (3) in 2011 only, the settlement of our cash flow hedges which were included within oil and gas sales on the consolidated statements of operations. We did not have any cash flow hedges in the three months ended March 31, 2012.
Our total net production increased 8% to 2.4 Bcfe, primarily due to an increase in production volumes at each of our key development fields, discussed as follows.
Our total average daily net production at the Atlantic Rim increased 6% to 19,768. Our Atlantic Rim production comes from three operating units, the Catalina Unit, the Sun Dog Unit and the Doty Mountain Unit. We operate the Catalina Unit.
Average daily net production in the Pinedale Anticline increased 10% to 5,455 Mcfe, as the operator brought 19 new wells on-line for production during the second, third and fourth quarters of 2011 and four new wells in the first quarter of 2012.
Transportation and gathering revenue
We receive 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. Transportation and gathering revenue remained consistent, totaling $1,238 and $1,232 for the three months ended March 31, 2012 and 2011, respectively. Although we realized a 5% increase in production volumes at the Catalina Unit, this increase was driven by production from our new wells, in which we own a 100% working interest, and therefore the gathering fees are eliminated in consolidation.
Price risk management activities
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $5,772. This consisted of an unrealized non-cash gain of $2,597, which represents the change in the fair value on our economic hedges at March 31, 2012 based on the expected future prices of the related commodities, and a net realized gain of $3,175 related to the cash settlement of some of our economic hedges.
Oil and gas production expenses, depreciation, depletion and amortization
Well production costs increased 23% to $3,158 and production costs in dollars per Mcfe increased 13%, or $0.15 to $1.29, driven by increased production costs at the Catalina Unit. The increases at Catalina were primarily due to higher compression, power and water hauling costs due to the addition of the 13 new wells completed in late 2011.
We are required to pay taxes on the proceeds received upon the physical sale of our gas to counterparties. Production taxes decreased 29% to $749, and production taxes, on a dollars per Mcfe basis, decreased 34%, or $0.16, to $0.31 per Mcfe. The decrease was primarily due to the decrease in the market prices for natural gas.
Total depreciation, depletion and amortization expenses (DD&A) decreased 1% to $4,604, and depletion and amortization related to producing assets decreased 1% to $4,507. Expressed in dollars per Mcfe, depletion and amortization related to producing assets decreased 9%, or $0.19, to $1.84 per Mcfe primarily due to a decrease in the depletion rate at the Catalina Unit.
Exploration expenses, including dry hole costs
In the first quarter of 2012, we participated in drilling an exploratory well in the High Road Prospect near Gillette, Wyoming. The well reached total depth in February 2012 and the results of geological testing showed no economically producible hydrocarbons existed. We recorded $438 of dry hole expense related to this well.
Pipeline operating costs
Pipeline operating costs increased 29% to $1,261, which was primarily attributed to higher compression costs. In the three months ended March 31, 2011, certain of our compressor leases were accounted for as capital leases with the related expense being recorded in DD&A. In the three months ended March 31, 2012, all of our compressor leases were operating leases.
General and administrative expenses
General and administrative expenses increased 9% to $1,703, primarily due to increased non-cash stock-based compensation expenses related to our Long Term Incentive Plan, which was adopted September 30, 2011.
We recorded an income tax expense of $147. Our effective tax rate for the three months ended March 31, 2012 was 31.0%, which was lower than the 2011 period primarily due to a decrease in permanent income tax difference related to stock options. 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 2012 at an expected federal and state rate of approximately 35.3%.
Contracted gas 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, 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, 2012 are summarized below (volume and daily production are expressed in Mcf). All contracts are indexed to the New York Mercantile Exchange (NYMEX).
Interest rate swap
We have a $30 million fixed rate swap contract with a third party in place as a hedge against the floating interest rate on our credit facility. Under the hedge contract terms, we locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for this tranche of our outstanding debt, which based on our current level of outstanding debt, translates to an interest rate on this tranche of approximately 3.08%. The contract is effective through December 31, 2012.
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, 2011, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.
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. Taking in account our derivative instruments, for the three months ended March 31, 2012, our income before income taxes would have changed by $449 for each $0.50 change per Mcf in natural gas prices and $8 for each $1.00 change per Bbl in crude oil prices.
The primary objective of our commodity price risk management policy is to preserve and enhance the value of our gas production. We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments typically consist of forward sales contracts, swaps and costless collars, which allow us to effectively lock in a portion of our future production of natural gas at prices that we consider favorable to us at the time we enter into the contracts. These derivative instruments which have differing expiration dates are summarized in the table presented above under Derivative Instruments.
Interest Rate Risks
At March 31, 2012, we had a total of $42.0 million outstanding under our $150 million credit facility ($60 million borrowing base). 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 average interest rate for the period, calculated in accordance with the agreement, was 2.6%. Because the interest rate is variable and reflects current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at March 31, 2012, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $120 before taxes (including the impact of our interest rate swap). Any balance outstanding on the credit facility matures on October 24, 2016.
In accordance with the Securities Exchange Act of 1934, and 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 Financial and 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 Financial and 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 SEC rules and forms.
There has been no change in our internal control over financial reporting that occurred during the three months ended March 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
From time to time, we are involved in various legal proceedings, including, but not limited to, 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.
On December 18, 2009, Tiberius Capital, LLC (Plaintiff), a stockholder of Petrosearch Energy Corporation (Petrosearch) prior to our acquisition (the Acquisition) of Petrosearch pursuant to a merger between Petrosearch and one of our wholly-owned subsidiaries, filed a claim in the District Court for the Southern District of New York against Petrosearch, us, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against us 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 was seeking monetary damage. On March 31, 2011, the District Court judge dismissed the case. The plaintiff filed a notice of appeal on April 29, 2011 and filed its appellate brief and appendix with the Second Circuit Court of Appeals on August 11, 2011. We filed a brief on October 13, 2011 supporting the District Courts March 31, 2011 opinion and judgment dismissing Tiberiuss case. The Second Circuit Court of Appeals will begin hearing the case on June 11, 2012.
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC, which we incorporate by reference herein.
The table below summarizes repurchases of our common stock in the first quarter of 2012:
The following exhibits are filed as part of this report:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.