UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

      

FORM 10-Q

      

(Mark One)

 

For the quarterly period ended March 31, 2013

or

 

For the transition period from to

Commission File Number 1-33571

      

DOUBLE EAGLE PETROLEUM CO.

(Exact name of registrant as specified in its charter)

      

   

 

   

 

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. 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 issuer’s classes of common stock, as of the latest practicable date.

   

 

   

      

   

   

   

---

DOUBLE EAGLE PETROLEUM CO.

FORM 10-Q

TABLE OF CONTENTS

   

 

   

   

 

2  

   

---

PART I. FINANCIAL INFORMATION

 

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands of dollars except share data)

(Unaudited)

   

 

The accompanying notes are an integral part of the consolidated financial statements.

 

3  

   

---

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands of dollars except share and per share data)

(Unaudited)

   

 

The accompanying notes are an integral part of the consolidated financial statements.

   

 

4  

   

---

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in thousands of dollars)

(Unaudited)

   

 

The accompanying notes are an integral part of the consolidated financial statements.

   

 

5  

   

---

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)

   

 

The accompanying notes are an integral part of the consolidated financial statements.

   

 

6  

   

---

DOUBLE EAGLE PETROLEUM CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Amounts in thousands of dollars except share and per share data)

(Unaudited)

 

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 2012 consolidated financial statements have been reclassified to conform to the 2013 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, 2012, 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 for the year ended December 31, 2012 filed 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 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

In January 2013, the Financial Accounting Standards Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”), The objective of ASC No. 2013-01 is to clarify that the scope of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASC No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The Company adopted ASC No. 2013-01 effective January 1, 2013, and it did not have an effect on the Company’s consolidated financial statements.

 

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 Company’s 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, 2013 and 2012.

   

 

7  

   

---

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:

   

 

   

 

As of March 31, 2013, the Company had a $150,000 revolving line of credit in place with $60,000 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 Company’s oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.

As of March 31, 2013, the balance outstanding of $47,450 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 Company’s 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 Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at March 31, 2013, including the impact of our interest rate swaps, was 3.5%. For the three months ended March 31, 2013 and 2012, the Company incurred interest expense on the credit facility of $409 and $329, respectively. Of the total interest incurred, the Company capitalized interest costs of $45 and $72 for the years ended March 31, 2013 and 2012, respectively.

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, 2013, 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.

 

Commodity Contracts

The Company’s primary market exposure is to adverse fluctuations in the price 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,

 

8  

   

---

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 Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s 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 Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. Under the Company’s 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 24 month period thereafter.

The Company accounts for 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 Company’s 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 are also recorded in the price risk management activities line on the consolidated statements of operations.

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 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. As of March 31, 2013, no party to any of the Company’s derivative contracts has required any form of security guarantee.

The Company had the following commodity volumes under derivative contracts as of March 31, 2013:

   

 

 

The Company entered into one additional derivative contract subsequent to March 31, 2013. Please refer to Note 12 for the derivative contract terms.

 

9  

   

---

Interest Rate Swap

As of March 31, 2013, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on its credit facility:

   

 

 

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of March 31, 2013, presented gross of any master netting arrangements:

   

 

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, 2013 and 2012 was as follows:

   

 

¹ Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(2,804) and $5,772 for the three months ended March 31, 2013 and 2012, respectively.

² Included in interest expense, net on the consolidated statements of operations.

Refer to Note 5 for additional information regarding the valuation of the Company’s derivative instruments.

 

Assets and Liabilities Measured on a Recurring Basis

The Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility also approximates fair value as it bears interest at a floating rate.

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:

 

 

10  

   

---

 

 

The following table provides a summary as of March 31, 2013 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, 2013.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above:

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 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 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, 2013, 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 Company’s 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.

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 Company’s 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

 

11  

   

---

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.

Assets and Liabilities Measured on a Non-recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property and equipment. 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 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.

The Company completed an exploration well targeting the Niobrara, Dakota and Frontier formations in 2012. Upon completion, the Company determined that it did not expect to recover the full amount of capitalized costs associated with this exploration well, and wrote-off a portion of the capitalized costs in the fourth quarter of 2012. The Company incurred $1,039 of additional costs related to this well in the first quarter of 2013, which were charged to impairment expense consistent with the Company’s 2012 year-end assessment. 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 also wrote off $25 and $4 during the three months ended March 31, 2013 and 2012, respectively, related to expired undeveloped leaseholds.

 

The Company recognized stock-based compensation expense totaling $282 for the three months ended March 31, 2013, and $414 for the three months ended March 31, 2012.

Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatilities are based on the historical volatility of the Company’s 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 Company’s 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 Company’s various stock option plans as of March 31, 2013 and changes during the three months ended March 31, 2013 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.

 

12  

   

---

Nonvested stock awards as of March 31, 2013 and changes during the three months ended March 31, 2013 were as follows:

 

In the fourth quarter of 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 Company’s adjusted net asset value, as defined in the LTIP. If the Company ultimately achieves the service requirements and performance objectives determined by the LTIP, the associated total stock-based compensation expense would be approximately $3.1 million, based on the grant date fair value. As of March 31, 2013, the Company did not expect that it would meet the LTIP performance objectives and has not recorded any stock-based compensation expense associated with the performance shares. The total compensation expense recorded by the Company related to the LTIP in the three months ended March 31, 2013 and 2012 was $117 and $140, respectively. These shares are included as nonvested shares in the stock awards table above.

 

In October 2012, the Company exercised its preferential right to acquire additional working interest in the Catalina Unit and Spy Glass Hill Unit (which includes the former Sun Dog and Doty Mountain Units) from Anadarko Petroleum Corporation (“Anadarko”) for a total cost of $4,874.  The purchase expands the Company’s presence in one of its core development areas. The effective date of this transaction was August 1, 2012.

The following table summarizes the working interest acquired as a result of the transaction, and the Company’s post-transaction total ownership in each of the participating areas.

   

 

   

 

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, 2013, 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.

 

In 2007, the stockholders of the Company approved an amendment to the Company’s 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.

The shares of Series A Preferred Stock are classified outside of permanent equity on the consolidated balance sheets due to its 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

 

13  

   

---

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.

In the fourth quarter of 2012, the holders of the Series A Preferred Stock approved an amendment to the Articles Supplementary for the Series A Preferred Stock that modified the definition of a “Qualifying Public Company” to give the Company more flexibility when pursuing strategic acquisitions and mergers by allowing a change of control to be executed without the redemption provision being triggered if the Company’s stock is still actively traded in the open market. The amendment also extended the redemption date at which 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) from June 30, 2012 to September 30, 2013.

   

   

 

Legal proceedings

From time to time, the Company is involved in various legal proceedings. 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.

 

Additional Derivative Instruments

In April 2013, the Company entered into one new commodity contract, as summarized below (volume is expressed in MMcf and contracts are indexed to NYMEX).

   

 

   

Main Fork Unit Update

In 2009, the Company entered into an agreement to give optional farm-in rights to a third party to re-enter the TTU #1 well located in the Main Fork Unit in Utah.  The Company was notified in April 2013 that the third party was terminating the agreement and would not exercise its farm-in right.  In accordance with the agreement, the third party will pay $500 to the Company.

 

14  

   

---

 

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, and share or per share amounts.

FORWARD-LOOKING STATEMENTS

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, 2012 and the following factors:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

We may also make material acquisitions or divestitures or enter into financing or other 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.

 

15  

   

---

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) selectively pursuing strategic acquisitions or mergers; (ii) investment in and 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; and (iv) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns.

Our Pinedale Anticline and Atlantic Rim assets operate under federal exploratory unit agreements among 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.

   

RESULTS OF OPERATIONS

   

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

   

The following analysis provides comparison of the three months ended March 31, 2013 and the three months ended March 31, 2012.  

   

Oil and gas sales

   

Oil and gas sales increased 25% to $7,533, which was largely attributed to a 47% increase in the Colorado Interstate Gas, or CIG, market price, which is the index on which most of our natural gas volumes are sold.  As shown in the table below, our average realized natural gas price increased 6% to $3.75 per Mcf due to the increase in the CIG market price.  In both years, we realized a natural gas price that was higher than the prevailing market prices due to the derivatives we had in place.  Our production volume is greater than our hedged volumes, and therefore in the quarter ended March 31, 2013, we benefited from the increase in the CIG price.  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, and (2) realized gain (loss) on our economic hedges, which is included within price risk management activities, net on the consolidated statements of operations, totaling $1,869 and $3,175, for the three months ended March 31, 2013 and 2012, respectively.   

   

 

   

Our total net production decreased 2% to 2,401 MMcfe for the three months ended March 31, 2013 due primarily to lower production from our non-operated properties.     

   

 

16  

   

---

Our total average daily net production at the Atlantic Rim increased 3% to 20,359 Mcfe.  Our Atlantic Rim production comes from two operating units: the Catalina Unit and the Spy Glass Hill Unit (which includes the Sun Dog and Doty Mountain PAs). We operate the Catalina Unit and have working interests in the Spy Glass Hill Unit.  In the fourth quarter of 2012, we exercised our preferential right to acquire additional working interest in the Catalina Unit and Spy Glass Hill Unit.  Our working interest changed as follows:

   

 

   

Average daily net production at our Catalina Unit increased 6% to 15,205 Mcfe, due to our increased working interest in the unit.  Gross production from the unit decreased approximately 11%, however, as our wells continue to recover from a series of equipment challenges, including a compressor failure in the third quarter of 2012 and then unscheduled maintenance on several injection pumps.  We also continue to experience normal production decline for the older wells within the field.  

 

Average daily production, net to our interest, at the Spy Glass Hill Unit decreased 4% to 5,154 Mcfe. CBM wells can become saturated with water when they are not producing or properly maintained.  We believe the production decrease is primarily due to delayed maintenance by the former operator.  This decrease was partially offset by our increased working interest in the Unit.  

 

Average daily net production in the Pinedale Anticline decreased 8% to 5,019 Mcfe.  The operator brought five new wells on-line in late March 2013; therefore, they only added a small amount of production for the quarter.  

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 decreased 21% to $979 for the three months ended March 31, 2013.  Gathering fees charged on Company-owned production volumes are eliminated in consolidation.  As a result of our purchase of additional working interest in the Catalina Unit, there was a decrease in third-party production volumes and the associated gathering fees.  

   

Price risk management activities

   

We recorded a net loss on our derivative contracts not designated as cash flow hedges of $(2,804).  This consisted of an unrealized non-cash loss of $(4,673), which represents the change in the fair value on our economic hedges at March 31, 2013 based on the expected future prices of the related commodities, and a net realized gain of $1,869 related to the cash settlement of some of our economic hedges.  

   

Oil and gas production costs, depreciation, depletion and amortization

 

   

   

Well production costs decreased 8% to $2,908 and production costs in dollars per Mcfe decreased 6%, or $0.08 to $1.21, driven by lower production costs at the Catalina Unit.  Production costs were approximately $364 lower at the Catalina Unit due to the deferral of certain maintenance activities while the field efforts were focused on bringing the Niobrara well on-line.  

 

17  

   

---

Production taxes increased 26% to $942, and production taxes, on a dollars per Mcfe basis, also increased 26%, or $0.08 to $0.39 per Mcfe.  We are required to pay taxes on the proceeds received upon the physical sale of our gas to counterparties. Production taxes were higher in total and on a per Mcfe basis primarily due to the increase in the market prices for natural gas.

   

Total depreciation, depletion and amortization expenses (“DD&A”) increased 13% to $5,222, and depletion and amortization related to producing assets increased 14% to $5,125.  Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 16%, or $0.29, to $2.13 per Mcfe.  Our depletion rate was higher in 2013 due to a decrease in our reserves, which were estimated to be lower in our year-end reserve report, primarily due to the decrease in pricing as calculated in accordance with Securities and Exchange Commission rules.    

   

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 results of geological testing showed no economically producible hydrocarbons existed and as a result the drilling costs of $438 were charged to dry hole expense in the quarter ended March 31, 2012.  

   

Pipeline operating costs

   

Pipeline operating costs increased 20% to $1,514, which was primarily attributed to higher power charges.

 

18  

   

---

General and administrative expenses

   

General and administrative expenses decreased 5% to $1,616, primarily due to a $130 decrease in non-cash stock-based compensation expense resulting from several executive grants becoming fully vested at the end of 2012.  There were no other material changes to general and administrative expenses during the three months ended March 31, 2013.  

Income taxes

We recorded an income tax benefit of $2,733.  Our effective tax rate for the three months ended March 31, 2013 was 34.5%, which was higher than the 2012 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 2013 at an expected federal and state rate of approximately 35.0%.

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 $150,000 credit facility in place with a $60,000 borrowing base. At March 31, 2013, we had $47,450 outstanding on our credit facility. We expect that the remaining availability of $12,550, coupled with our expected cash flow from operations will be sufficient to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2013 capital expenditure program (see “Calendar 2013 Capital Spending Budget” on the following page).

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. We 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 to $3,709 at March 31, 2013 as compared to $7,851 at December 31, 2012. The change in working capital primarily resulted from a decrease in the fair value of our price risk management assets. We also had lower accounts payable and accrued expenses as of March 31, 2013, as our capital expenditures slowed during the quarter due to winter weather and wildlife stipulations.

Cash flow activities

The table below summarizes our cash flows for the three months ended March 31, 2013 and 2012, respectively:

   

 

 

19  

   

---

During the three months ended March 31, 2013, net cash provided by operating activities was $2,737, as compared to $4,716 in the same prior-year period. The decrease in our cash flow from operations was primarily due to the lower accounts payable and accrued expense balances resulting from the timing and overall decrease in production costs. Our operating cash flow is sensitive to many variables, the most significant of which is the price of natural gas. Our hedging program helps to mitigate cash flow fluctuations due to price volatility. We realized cash from settlements of derivatives of $1,869 and $3,175 during the three months ended March 31, 2013 and 2012, respectively. Our average realized natural gas price was 6% higher in the three months ended March 31, 2013 as compared to the same prior-year period.

During the three months ended March 31, 2013, net cash used in investing activities was $2,139, as compared to $10,257 in the same prior-year period. During the first quarter of 2013, our capital spending was related to expenditures to begin producing our Niobrara exploration well and non-operated drilling in the Pinedale Anticline. In the first quarter of 2012, we primarily made payments related to the drilling of the Niobrara well. We also made payments in the first quarter of 2012 related to our 2011 drilling program at Catalina, which was completed late in the fourth quarter of 2011.  

Our cash used in financing activities remained consistent for the three months ended March 31, 2013 and 2012, totaling $948 and $957, respectively. We expended cash in the first quarter of 2013 and 2012 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.  

Credit Facility

Our credit facility is collateralized by our oil and gas producing properties and other assets. At March 31, 2013, we had $47,450 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 two purchases of additional working interest 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 Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at March 31, 2013, including the impact of our interest rate swaps, was 3.5%.

We are subject to a variety of financial and non-financial covenants under this facility. As of March 31, 2013, 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, accelerate all principal and interest outstanding, and foreclose on our assets.

Our borrowing base was reaffirmed in April and will be subject to redetermination again on October 1, 2013. If natural gas prices decrease for extended period of time, our borrowing base could be reduced, thus limiting the future amounts of funds under the current facility. 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.

Capital Requirements

For 2013, we have budgeted up to $14,000 for capital projects in the Atlantic Rim and Pinedale Anticline. In the second quarter of 2013, we intend to begin a workover program in the Catalina Unit that will focus on opening up previously unfractured formations. We estimate this program will cost approximately $6,000. We expect to participate in the drilling of the final 13 well locations in the Mesa “B” Unit of the Pinedale Anticline for a cost of $3,000 to $6,000. We have also budgeted $2,500 to be used in a seismic study in the Atlantic Rim or to acquire additional leases. We also may complete the Niobrara and other lower formations in two existing wells on our acreage. Any costs associates with this development are not included in the above budget. We believe that we have the necessary capital, personnel and available drilling equipment to execute this development and exploration program.

 

20  

   

---

Contractual Obligations

The impact that our contractual obligations as of March 31, 2013 are expected to have on our liquidity and cash flows in future periods is:

 

 

Off-Balance Sheet Arrangements

As of March 31, 2013, 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.

DERIVATIVE INSTRUMENTS

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. Typically, these derivative instruments have consisted of 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, 2013 are summarized below (volume and daily production are expressed in Mcf). All contracts are indexed to the New York Mercantile Exchange (“NYMEX”). The prevailing market prices in the Rockies, including CIG which is the index on which most of our gas volumes are sold, tend to be sold at a discount relative to other U.S. natural gas markets. This discount is typically referred to as a “basis differential” and reflects, to some extent, the costs associated with transporting the natural gas in the Rockies to markets in the other regions. It also reflects the general excess supply and lack of pipeline capacity in the region.

   

 

In April 2013, the Company entered into one new commodity contract, as summarized below (volume is expressed in MMcf and contract is indexed to NYMEX).

 

 

21  

   

---

Interest rate swap

We have a $30,000 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 1.050% 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 3.55%. The contract is effective through September 30, 2016.

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, 2012, 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, 2013, our income before income taxes would have changed by $326 for each $0.50 change per Mcf in natural gas prices and $5 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, 2013, we had a total of $47,450 outstanding under our $150,000 credit facility ($60,000 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 3.5%. We have entered into an interest rate swap with a third party to manage the risk associated with the floating portion of the interest rate. Assuming no change in the amount outstanding at March 31, 2013, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $175 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, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

 

From time to time, we are involved in various legal proceedings. 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.

 

22  

   

---

 

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, 2012 filed with the SEC, which we incorporate by reference herein.

 

The table below summarizes repurchases of our common stock in the first quarter of 2013:

   

 

 

 

The following exhibits are filed as part of this report:

   

 

 

23  

   

---

   

 

   

 

24  

   

---

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

   

 

   

 

25  

   

---

EXHIBIT INDEX

   

 

   

 

26  

   

---