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Double Eagle Petroleum Company 10-Q 2010 Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended September 30, 2010
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)
1675 Broadway, Suite 2200, Denver, Colorado 80202
(Address of principal executive offices) (Zip code) 303-794-8445
(Registrant’s telephone number, including area code) None
(Former name, former address, and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
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 o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes o No þ
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
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
The accompanying notes are an integral part of the consolidated financial statements.
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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.
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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.
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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 were prepared by Double
Eagle Petroleum Co. (“Double Eagle” or the “Company”) pursuant to the rules and regulations of
the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures
normally included in the annual consolidated financial statements prepared in accordance with
accounting principles generally accepted in the United States of America have been condensed or
omitted as allowed by such rules and regulations. These consolidated financial statements
include all of the adjustments, which, in the opinion of management, are necessary for a fair
presentation of the financial position and results of operations. All such adjustments are of a
normal recurring nature only. The results of operations for the interim periods are not
necessarily indicative of the results to be expected for the full fiscal year. The Company has
evaluated subsequent events through the date of issuance of its consolidated financial
statements.
Certain amounts in the 2009 consolidated financial statements have been reclassified to conform
to the 2010 consolidated financial statement presentation. Such reclassifications had no effect
on net income.
The accounting policies followed by the Company are set forth in Note 1 to the Company’s
consolidated financial statements in the Annual Report on Form 10-K for the year ended
December 31, 2009, and are supplemented throughout the notes to this Quarterly Report on Form
10-Q.
The interim consolidated financial statements presented herein should be read in conjunction
with the consolidated financial statements and notes thereto for the year ended December 31,
2009 included in the Annual Report on Form 10-K filed with the SEC.
Principles of consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned
subsidiaries, Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC
(“EWM”) (collectively, the “Company”). In August 2009, the Company acquired Petrosearch, which
has operations in Texas and Oklahoma. 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. The
Company’s fee related to gas gathering is also eliminated in consolidation.
Recently adopted accounting pronouncements
In January 2010, the FASB issued ASC Update No. 2010-06, an additional update to the ASC
guidance for fair value measurements. The new guidance requires additional disclosures about
(1) the different classes of assets and liabilities measured at fair value, (2) the valuation
techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the
transfers between Levels 1, 2 and 3. The updated guidance is effective for annual and interim
periods beginning December 15, 2009, except for the disclosures about the activity in Level 3
fair value measurements, for which the new guidance is effective for fiscal years beginning
after December 15, 2010. The Company adopted the provisions that were effective for annual and
interim periods beginning December 15, 2009 effective January 1, 2010. The adoption of ASC
Update 2010-06 did not have an impact on the Company’s financial position, results of operations
or cash flows. Refer to Note 4 for the Company’s disclosures on fair value accounting.
Basic earnings per share of common stock (“EPS”) is calculated by dividing net income (loss)
attributable to common stock by the weighted average number of shares of common stock
outstanding during the period. Diluted earnings per share incorporates the treasury stock
method, and is calculated by dividing net income (loss) attributable to common stock by the
weighted average number of shares of common stock and potential common stock equivalents
outstanding during the period, if dilutive. Potential common stock equivalents include
incremental shares of common stock issuable upon the exercise of stock options and employee
stock awards. Income attributable to common stock is calculated as net
income less dividends paid on the Series A Preferred Stock. The Company declared and paid cash
dividends of $930 and $2,792 ($0.5781 per share) on the Series A Preferred Stock for the three
and nine months ended September 30, 2010 and 2009, respectively.
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The following is the calculation of basic and diluted weighted average shares outstanding and
net income (loss) 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 (loss) per share
of common stock because the effect would have been anti-dilutive for the periods indicated:
The Company’s primary market exposure is to adverse fluctuations in the prices of natural gas.
The Company uses derivative instruments, primarily forward contracts, costless collars and
swaps, to manage the price risk associated with 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 Company recognizes its derivative instruments as either assets or liabilities at fair value
on its consolidated balance sheets and accounts for the derivative instruments as either cash
flow hedges or mark to market derivative instruments. On the statements of cash flow, 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. The Company was in an overall asset position with each
of its counterparties at September 30, 2010, and no party in any of its derivative contracts has
required any form of security guarantee.
Cash flow hedges
Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair
value on the 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 the oil and gas sales line on the consolidated statements of
operations as the contracts settle. As of September 30, 2010, the Company expects approximately
$7,020 of unrealized gains before taxes, included in its AOCI, to be reclassified into earnings
in one year or less, as the contracts settle.
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Mark to market derivative instruments
Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are
recorded at fair value on the consolidated balance sheets and the changes in fair value are
recognized in the price risk management activities line on the consolidated statements of
operations at each reporting period. 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.
The Company had the following commodity volumes under derivative contracts as of September 30,
2010:
The table below contains a summary of all the Company’s derivative positions reported on the
consolidated balance sheet as of September 30, 2010, presented gross of any master netting
arrangements:
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The before-tax effect of derivative instruments in cash flow hedging relationships on the
consolidated statement of income for the three months and nine months ended September 30, 2010
and 2009, related to the Company’s commodity derivatives was as follows:
The before-tax effect of derivative instruments not designated as hedging instruments on
the consolidated statements of operations for the three and nine months ended September 30, 2010
and 2009 was as follows:
Derivatives Not Designated as Cash Flow Hedging Instruments under ASC 815 — Commodity Contracts
Refer to Note 4 for additional information regarding the valuation of the Company’s
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 to the valuation of an asset or liability as of the
measurement date. The three levels are defined as follows:
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The following describes the valuation methodologies the Company uses for its fair value
measurements.
Cash and cash equivalents
Cash and cash equivalents include all cash balances and any highly liquid investments with an
original maturity of 90 days or less. The carrying amount approximates fair value because of
the short maturity of these instruments.
Derivative instruments
The Company determines its estimate of the fair value of derivative instruments using a market
approach based on several factors, including quoted market prices in active markets, quotes from
third parties, the credit rating of each counterparty, and the Company’s own credit rating. The
Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
In consideration of counterparty credit risk, the Company assessed the possibility of whether
each counterparty to the derivative would default by failing to make any contractually required
payments. Additionally, the Company considers that it is of substantial credit quality and has
the financial resources and willingness to meet its potential repayment obligations associated
with the derivative transactions.
At September 30, 2010, the types of derivative instruments utilized by the Company included
costless collars and swaps. The natural gas derivative markets are highly active. Although the
Company’s cash flow and economic hedges are valued using public indices, the instruments
themselves are traded with third-party counterparties and are not openly traded on an exchange.
As such, the Company has classified these instruments as Level 2.
Credit facility
The recorded value of the Company’s credit facility approximates fair value.
Asset retirement obligations
The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic
410, “Asset Retirement and Environmental Obligations.” The income valuation technique is
utilized by the Company to determine the fair value of the liability at the point of inception
by taking into account 1) the cost of abandoning oil and gas wells, which is based on the
Company’s historical experience for similar work, or estimates from independent third-parties;
2) the economic lives of its properties, which is based on estimates from reserve engineers; 3)
the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the
Company’s credit risk and the time value of money. Given the unobservable nature of the inputs,
the initial measurement of the asset retirement obligation liability is deemed to use Level 3
inputs. There were no asset retirement obligations measured at fair value within the
accompanying consolidated balance sheets at September 30, 2010.
The following table provides a summary of the fair values of assets measured at fair value.
There were no liabilities measured at fair value at September 30, 2010.
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 nine months ended September 30, 2010.
Concentration of credit risk
Financial instruments which potentially subject the Company to credit risk consist of the
Company’s accounts receivable and its derivative financial instruments. Substantially all of
the Company’s receivables are within the oil and gas industry, including those from a
third-party marketing company. Collectability is dependent upon the financial wherewithal of
each individual company as well as the general economic conditions of the industry. The
receivables are not collateralized.
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At September 30, 2010, the Company’s derivative financial instruments were held with two
counterparties. The Company continually reviews the credit-worthiness of its counterparties.
The Company’s derivative instruments are part of master netting agreements, which reduces credit
risk by permitting the Company to net settle for transactions with the same counterparty.
The Company reviews the carrying values of its long-lived assets whenever events or changes in
circumstances indicate that such carrying values may not be recoverable. If, upon review, the
sum of the undiscounted pretax cash flows is less than the carrying value of the asset group,
the carrying value is written down to the estimated fair value. Individual assets are grouped
for impairment purposes at the lowest level for which there are identifiable cash flows that are
largely independent of the cash flows of other groups of assets, generally on a field-by-field
basis. The fair value of impaired assets is determined based on quoted market prices in active
markets, if available, or upon the present values of expected future cash flows using discount
rates commensurate with the risks involved in the asset group. The impairment analysis
performed by the Company may utilize Level 3 inputs. The long-lived assets of the Company,
which are subject to periodic evaluation, consist primarily of oil and gas properties and
undeveloped leaseholds. The Company did not recognize any impairment charges during the three
and nine months ended September 30, 2010 and 2009.
The Company recognized share-based compensation expense of $230 and $726 during the three and
nine months ended September 30, 2010, respectively, as compared to $301 and $1,071 in the three
and nine months ended September 30, 2009, respectively.
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 stock over
a period consistent with that of the expected terms of the options. The expected terms of the
options are estimated based on factors such as vesting periods and contractual expiration dates.
The risk-free rates for periods within the contractual life of the options are based on the
yields of U.S. Treasury instruments with terms comparable to the estimated option terms.
A summary of stock option activity under the Company’s various stock option plans as of
September 30, 2010 and changes during the nine months ended September 30, 2010 is presented
below:
The Company measures the fair value of the stock awards based upon the fair market value of its
common stock on the date of grant and recognizes the resulting compensation expense ratably
over the associated service period, which is generally the vesting term of the stock awards.
The Company recognizes these compensation costs net of a forfeiture rate and recognizes the
compensation costs for only those shares expected to vest. The Company typically estimates
forfeiture rates based on historical experience, while also considering the duration of the
vesting term of the award.
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Nonvested stock awards as of September 30, 2010 and changes during the nine months ended
September 30, 2010 were as follows:
As part of the acquisition of Petrosearch, the Company assumed all outstanding warrants to
purchase common stock that had been issued by Petrosearch prior to the merger. At September
30, 2010, the Company had two tranches of warrants outstanding; 10,310 warrants with an exercise
price of $34.64 that expire in November 2010; and 8,660 warrants with an exercise price of
$21.25 that expire in December 2011. In February 2010, 14,691 warrants with an exercise price
of $46.19 expired. The warrants had no intrinsic value at September 30, 2010.
The Company is required to record income tax expense for financial reporting purposes.
However, the Company does not anticipate any payments of 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 September 30, 2010, the Company made no provision for interest or penalties
related to uncertain tax positions. The Company files income tax returns in the U.S. federal
jurisdiction and various states. The Company is not currently subject to any federal or state
income tax examinations. Furthermore, the Company is no longer subject to U.S. federal income
tax examinations by the Internal Revenue Service for tax years before 2005 and for state and
local tax authorities for years before 2004. The Company’s tax years of 2004 and forward are
subject to examination by federal and state taxing authorities.
The Company amended its $75 million credit facility in August 2010 to increase its borrowing
availability to $55 million from $45 million (the “Credit Facility”). The Company’s borrowing
availability is based on several factors, including its current borrowing base and the
commitment levels by participating banks. The Credit Facility is collateralized by all the
assets of the Company. As of September 30, 2010, the balance outstanding of $34 million had been
used to fund capital expenditures primarily on the Company-operated Catalina Unit expansion and
other non-operated projects in the Atlantic Rim in 2008, projects in the Pinedale Anticline in
2008, 2009 and 2010, and the Company’s asset purchase in the Atlantic Rim in July 2010. Any
balance outstanding on the Credit Facility matures on January 31, 2013.
Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a
daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the
Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level
of funds borrowed. As of September 30, 2010, the interest rate on the line of credit was 4.5%.
For the three months ended September 30, 2010 and 2009, the Company incurred interest expense of
$405 and $476, respectively, related to the Credit Facility and $1,118 and $1,403 for the nine
months ended September 30, 2010 and 2009, respectively. The Company capitalized interest costs
of $37 and $260 for the three months ended September 30, 2010 and 2009, respectively, and $124
and $903 for the nine months ended September 30, 2010 and 2009, 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 September 30, 2010, the Company was in compliance with all financial covenants. If the
covenants are violated and the Company is unable to negotiate a waiver or amendment thereof, the
lenders would have the right to declare an event of default, terminate the remaining commitment
and accelerate all principal and interest outstanding.
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On July 20, 2010, the Company signed an asset purchase agreement with a third party to purchase
certain assets in the Atlantic Rim area of Southwestern Wyoming. The purchase increased the
Company’s ownership in one of its existing core development properties. The table below shows
the working interest acquired under the terms of the agreement and the Company’s
post-transaction total ownership in each of the units within the Atlantic Rim:
The effective date of the transaction is January 1, 2010. The total cost of the asset
purchase transaction was $8.4 million, subject to closing adjustments. The total cash paid by
the Company, subject to post closing adjustments, was $7.8 million, net of revenue, expense and
capital costs incurred from the effective date through the closing date.
The Company recorded an additional asset retirement obligation in conjunction with the asset
acquisition, totaling $1,042.
On August 6, 2009, the Company acquired 100% of the common and preferred shares of Petrosearch
in exchange for approximately 1.8 million shares of Double Eagle common stock, valued at
approximately $7.3 million, and cash consideration of $873, for a total purchase price of
approximately $8.1 million. Effective with the acquisition, each Petrosearch shareholder
received .0433 shares of Double Eagle common stock and $0.0211 for each share of Petrosearch
common stock and Petrosearch preferred stock, on an as converted basis, such shareholder held.
As result of the merger, Petrosearch became a wholly-owned subsidiary of the Company.
Petrosearch is an independent crude oil and natural gas exploration and production company, with
properties in Texas and Oklahoma. The Company’s results of operations include the effect of the
Petrosearch acquisition from the closing date.
In 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A
Cumulative Preferred Stock at a price to the public of $25.00 per share.
Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the
Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The
Series A Preferred Stock does not have any stated maturity date and is not subject to any
sinking fund or mandatory redemption provision, except, under some circumstances upon a “Change
of Ownership or Control”, as defined. 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
accompanying consolidated balance sheets due to the following 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, at
the following price per share, plus accrued and unpaid dividends:
In the event of liquidation, the holders of the Series A Preferred Stock will have the right to
receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to
the holders of the Company’s common stock.
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The components of comprehensive income (loss) were as follows:
The components of accumulated other comprehensive income were as follows:
The Company has received deposits representing partial prepayments of the expected capital
expenditures from third party working interest owners in the Table Top Unit #1 exploration
project. The unexpended portion of the deposits at September 30, 2010 and December 31, 2009
totaled $614 and $611, respectively.
Legal proceedings
From time to time, the Company is involved in various legal proceedings, including the matters
discussed below. These proceedings are subject to the uncertainties inherent in any litigation.
The Company is defending itself vigorously in all such matters, and while the ultimate outcome
and impact of any proceeding cannot be predicted with certainty, management believes that the
resolution of any proceeding will not have a material adverse effect on the Company’s financial
condition or results of operations.
The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District
Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants that own working
interests in the Madden Deep Unit. The Company and the other plaintiffs in the case asserted
that, under the gas balancing agreement, they were entitled to receive either monetary damages or
their respective shares of the natural gas produced from the Madden Deep Unit over at least the
period February 1, 2002 through June 30, 2007. In the third quarter of 2010, the Company signed
a settlement agreement with many of the defendants in the lawsuit, in which the Company received
cash proceeds of approximately $4,061. Prior to the settlement, the Company had not recognized
any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. For the
period from November 1, 2006 through June 30, 2007, the Company had recognized the sales and had
recorded a related account receivable of $292, net of allowance for uncollectible amounts. As
such, the Company recorded $3,841 within proceeds from Madden Deep settlement on the consolidated
statements of operations for the three and nine months ended September 30, 2010. Sulfur sales
are not subject to a gas balancing agreement, and, accordingly, the Company received the proceeds
for its share of sulfur sales dating back to February 2002 and has continued to receive its
respective share on an on-going basis.
On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch prior to
the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between
Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the U.S. District
Court of New York against Petrosearch, the Company, and the individuals who were officers and
directors of Petrosearch prior to the Acquisition. In general, the claims against the Company
and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under
the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the
defendants violated various sections of the Securities Act of 1933 and the Securities Exchange
Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch.
The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and
intends to defend this case vigorously.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and
its subsidiaries, as a consolidated entity, unless the context suggests otherwise. Unless the
context suggests otherwise, the amounts set forth in Part I and Part II herein are in thousands,
except units of production, ratios, share or per share amounts.
FORWARD-LOOKING STATEMENTS
This Quarterly Report 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 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 our Annual Report on Form 10-K for the year ended December 31, 2009.
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.
Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the
State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on
the NASDAQ Capital Market under the symbol “DBLE”. On December 15, 2006, our common shares began
trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock (“Preferred
Stock”) was issued on the NASDAQ Capital Market, under the symbol “DBLEP” on July 3, 2007. It
began trading under the symbol “DBLEP” on the NASDAQ Global Select Market on September 30, 2007.
Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone
number (303) 794-8445. Our website is www.dble.com.
Our objective is to increase long-term stockholder value by implementing our corporate strategy of
economically growing our reserves and production through the development of our existing core
properties, partnering on selective exploration projects, and pursuing strategic acquisitions that
expand or complement our existing operations. Our operations are currently focused on two core
properties located in southwestern Wyoming, where we have coal bed methane reserves and production
in the Atlantic Rim area of the Eastern Washakie Basin, and tight sands gas reserves and production
in the Pinedale Anticline. The operations in the Pinedale Anticline and Atlantic Rim operate under
federal exploratory unit agreements between the working interest partners. Unitization is a type
of sharing arrangement by which owners of operating and non-operating working interests pool their
property interests in a producing area to form a single operating unit. Units are designed to
improve efficiency and economics of developing and producing an area. The share that each interest
owner receives is based upon the respective acreage contributed by each owner in the participating
area (“PA”) that surround the producing wells as a percentage of the entire acreage of the PA.
This PA, and the associated working interest, will change as more wells and acreage are added to
the PA.
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Following are summary comments of our activities and performance in several key areas during the
three and nine months ended September 30, 2010:
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OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to continue our long-term
strategic plan, including our 2010 capital program (see “Capital Requirements” below). We intend to
use capital resources made available from future operating cash flow and through our $75 million
credit facility ($55 million borrowing availability), to fund our long-term strategic plan. We may
also find it necessary in the future to raise additional funds through private placements or
registered offerings of equity or debt. Although we believe that we would be able to secure
additional financing if required, we can provide no assurance that we will be able to do so or what
the terms of any additional financing would be.
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Information about our financial position is presented in the following table:
During the nine months ended September 30, 2010, our working capital increased to $12,265 compared
to negative working capital of $(4,067) at December 31, 2009. The higher working capital is
primarily the result of an increase in the fair value of our derivative contracts expected to
settle within one year. Based on changes in the expected commodity prices, certain derivative
contracts moved from a current liability position at December 31, 2009 to a current asset position
at September 30, 2010. In addition, our accounts payable and accrued liabilities balance decreased
$6,064 from December 31, 2009, primarily due to a slowdown in work-over and drilling activity at
our non-operated properties and due to timing of payments to vendors.
Cash flow activities
The table below summarizes our cash flows for the nine months ended September 30, 2010 and 2009,
respectively:
During the nine months ended September 30, 2010, net cash provided by operating activities was
$21,251, compared to $19,474 in the same prior-year period. The primary sources of cash during the
nine months ended September 30, 2010 were $8,087 of net income, which was net of non-cash charges
of $13,862 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion
expense, and non-cash share-based compensation expense of $726. In addition, in the nine months
ended September 30, 2010, we had an increase of $4,489 in the provision for deferred income taxes.
These increases were partially offset by the non-cash gain on derivative contracts of $8,030.
During the nine months ended September 30, 2010, net cash used in investing activities was $20,063,
as compared to $22,560 in the same prior-year period. Drilling activity slowed significantly in
2009 and the first nine months of 2010, and as a result, our cash outflow related to capital
expenditures also decreased as compared to the prior year. The capital expenditures in the first
nine months of 2010 primarily related to non-operated drilling in the Pinedale Anticline, whereas
in the first nine months of 2009, we had significant cash expenditures related to the 2008 drilling
programs in the Atlantic Rim and Pinedale Anticline. In addition, during the third quarter of
2010, we completed an acquisition of assets in the Atlantic Rim for a total cost of approximately
$8,417, subject to closing adjustments. The effective date of the acquisition was January 1, 2010.
We paid out total cash of approximately $7,761, which was net of revenue, expense and capital
costs incurred from the effective date through the closing date. Refer to Note 9 in the Notes to
the Consolidated Financial Statements for additional details regarding the asset acquisition.
During the nine months ended September 30, 2010, we had net cash used by financing activities of
$3,187, as compared to net cash provided by financing activities of $6,161 in the same prior-year
period. In the first quarter of 2009, we had significant draws on our credit facility to fund
costs incurred in the drilling program in the fourth quarter of 2008. In contrast, we have no
draws on our credit facility in 2010 due to increased operating cash flow and slower drilling and
workover activity. We also expended a total of $2,792 for the first, second and third quarter
dividend payments. We expect to continue to pay dividends on a quarterly basis on the Series A
Preferred Stock at a rate of $931 per quarter.
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Off-Balance Sheet Arrangements
We do not participate in transactions that generate relationships with unconsolidated entities or
financial partnerships.
From time to time, we enter into contracts that might be construed as off-balance sheet obligations
but are normal in the day-to-day course of business in the oil and gas industry. Those contracts
are the derivative instruments discussed in “Contracted Volumes” below. We do not believe we will
be affected by these contracts materially differently than other similar companies in the energy
industry.
Credit Facility
As of September 30, 2010, the Company had a $75 million credit facility in place, with borrowing
availability of $55 million, collateralized by our oil and gas properties and other assets. Any
balance outstanding on the Credit Facility matures January 31, 2013. The interest rate on the
Credit Facility varies based on prevailing market rates and our level of outstanding borrowings,
with a minimum floor rate of 4.5%.
As of September 30, 2010, the outstanding balance on our Credit Facility was $34.0 million. The
interest rate, calculated in accordance with the agreement, was 4.5% as of September 30, 2010 and
2009.
We incurred interest expense related to the Credit Facility of $405 and $476 for the three months
ended September 30, 2010 and 2009, respectively, and $1,118 and $1,403 for the nine months ended
September 30, 2010 and 2009, respectively. The Company capitalized interest costs of $37 and $260
for the three months ended September 30, 2010 and 2009, respectively, and $124 and $903 for the
nine months ended September 30, 2010 and 2009, respectively.
We are subject to certain financial and non-financial covenants with respect to the Credit
Facility, including requirements to maintain (i) a current ratio, as defined in the credit
agreement, of at least 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation,
depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus
dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to
1.0. As of September 30, 2010, we were in compliance with all covenants under the Credit 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 borrowing base is subject to redetermination each June 15 and December 15. As of June 15,
2010, our lenders reaffirmed our borrowing base.
Capital Requirements
Our initial capital budget for 2010 was approximately $15-$20 million for drilling up to eight
wells within the Catalina Unit, and ongoing non-operated development programs on the Pinedale
Anticline and within the Sun Dog and Doty Mountain Units. While the total capital expenditures for
2010 are expected to still fall within the previously disclosed range, we have shifted the funding
from drilling new wells within the Catalina Unit to the purchase of existing assets within the
Atlantic Rim, which was completed in the third quarter of 2010. The 2010 budget does not include
the impact of any potential future exploration projects, or ongoing exploration or development
activities or potential acquisitions. We expect to fund our 2010 capital expenditures with cash
provided by operating activities and funds made available through our credit facility. We may find
it necessary in the future to raise additional funds through private placements or registered
offerings of equity or debt securities.
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Contractual Obligations
Our contractual obligations as of September 30, 2010 are:
RESULTS OF OPERATIONS
Three Months Ended September 30, 2010 Compared to the Three Months Ended September 30, 2009
Oil and gas sales volume and price comparisons
Our average gas price realized for the three months ended September 30, 2010 is calculated by
summing 1) production revenue received from third parties for sale of our gas, which is included in
the oil and gas sales line item on the consolidated statements of operations; 2) settlement of our
cash flow hedges included within oil and gas sales on the consolidated statement of operations; and
3) realized gain/(loss) on our economic hedges, which is included in our price risk management
activities line on the consolidated statement of operations, totaling $1,715 and $422, for the
three months ended September 30, 2010 and 2009, respectively. This amount is divided by the total
Mcfe volume for the periods.
For the three months ended September 30, 2010, total net production increased 2% to 2,341 MMcfe, as
compared to the three months ended September 30, 2009. The increase was primarily due to higher
production volumes at the Sun Dog Unit, and the additional working interest that the Company
acquired in the third quarter of 2010.
During the three months ended September 30, 2010, our total average daily net production at
the Atlantic Rim increased 7% to 18,802 Mcfe, as compared to 17,585 Mcfe during the same prior-year
period. Average daily net production at our Catalina Unit decreased 9% to 13,978 Mcfe, as compared
to 15,391 Mcfe during the three months ended September 30, 2009. The decrease is primarily the
result of the continuation of our well-enhancement program, which began in the third quarter of
2009. This program requires individual wells to be off-line for short periods of time while the
well is worked-over. The decrease is also the result of what management believes to be the normal
production decline for wells within this field. Average daily production, net to our interest, at
the Sun Dog and Doty Mountain units increased 120% to 4,824 Mcfe, as compared to average daily net
production of 2,194 during the same prior-year period. The increase was primarily the result of
the additional compression capacity that was added at the Doty Mountain Unit in the first quarter
of 2010 and the well stimulations that were performed within in the Sun Dog Unit, coupled with the
additional working interest purchased in the third quarter of 2010. Our working interest in the
Sun Dog Unit increased to 21.54% from 8.89% prior to the acquisition, and the Doty Mountain Unit
increased to 18.00% from 16.5% prior to the acquisition. The operator of the Sun Dog and Doty
Mountain units has informed us that it is in the process of performing workovers on 36 wells and
plans to add additional injection capacity in the Sun Dog Unit.
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Average daily net production in the Pinedale Anticline decreased 1% during the three months ended
September 30, 2010, to 5,338 Mcfe, as compared to 5,384 Mcfe in the same prior-year period. The
operator of the Mesa Units brought an additional 12 wells on-line during the second and third
quarters of 2010, although this did not result in an overall increase in production. Management
believes that the production decline is due to the operator managing the production flow from the
field due to the low gas prices in the Rocky Mountain region. The operator at the Mesa Units has
informed us that it is in process of drilling approximately nine additional wells.
During the three months ended September 30, 2010, the average daily net production at the Madden
Unit decreased to 513 Mcfe compared to 597 Mcfe in the same prior-year period. A fire at the Lost
Cabin gas plant shut the plant down for approximately 15 days in 2010, resulting in lower
production volumes.
During the three months ended September 30, 2010, net oil and gas sales decreased 21% to $7,601, as
compared to $9,669 during the same prior year period. The change in oil and gas sales was
primarily driven by our lower realized gas price during the period. Our average realized gas price
for the three months ended September 30, 2010 decreased 10%, to $3.86 from $4.27 for the three
months ended September 30, 2009. Although the average CIG index price was approximately 23% higher
during the three months ended September 30, 2010 as compared to the same prior year period, our
realized gas price was lower in 2010 due to the strength of the hedges we had in place during 2009.
During the three months ended September 30, 2009, our derivative instrument settlements totaled
$4,177, of which $3,754 was classified as oil and gas sales on the consolidated statement of
operations. In comparison, during the three months ended September 30, 2010, our derivative
instrument settlements totaled $1,715, but were classified as price risk management activities on
the consolidated statements of operations due to the accounting treatment of these instruments.
Transportation and gathering revenue
During the three months ended September 30, 2010, transportation and gathering revenue decreased 9%
to $1,349 from $1,489 for the three months ended September 30, 2009. The Company receives fees for
gathering and transporting third-party gas through our intrastate gas pipeline, which connects the
Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc.
The decrease in revenue is due to the decrease in production volumes at the Catalina Unit
discussed above.
Price risk management activities
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $3,263 for
the three months ended September 30, 2010, as compared to a loss of $(378) during the same prior
year period. The net gain on price risk management activities during the period consisted of an
unrealized non-cash gain of $1,548, which represents a change in the fair value of our
mark-to-market derivative instruments from December 31, 2009 to September 30, 2010, and a net
realized gain of $1,715 related to the settlements of certain of our economic hedges.
Proceeds from Madden Deep settlement
During the three months ended September 30, 2010, we reached a settlement with many of the
defendants in the lawsuit brought by the Company through which we sought to recover either monetary
damages or our respective share of natural gas produced by out interest in the Madden Deep Unit
during the period February 1, 2002 through June 30, 2007. As part of the settlement, the Company
received cash proceeds of $4,061. Prior to the litigation settlement, we had not recognized any
amount of sales proceeds related to natural gas from the Madden Deep Unit for the period February
1, 2002 through October 30, 2006. For the period from November 1, 2006 through June 30, 2007, the
Company had recognized the sales and had recorded a related account receivable of $292, net of
allowance for uncollectible amounts. As such, the Company recorded income of $3,841 upon the
settlement within proceeds from Madden Deep settlement on the consolidated statements of operations
during the three months ended September 30, 2010.
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Oil and gas production expenses, production taxes, depreciation, depletion and amortization
Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as
stated on the consolidated statements of operations, by total production volumes during the
periods. This calculation excludes certain gathering costs incurred by the Company’s subsidiary,
Eastern Washakie Midstream, which are eliminated in consolidation. During the three months ended
September 30, 2010, well production costs increased 46% to $2,828, as compared to $1,934 during the
same prior-year period, and production costs in dollars per Mcfe increased 44%, or $0.37, to $1.21,
as compared to the same prior-year period. The increase in production costs in total, and on a per
Mcfe basis, was primarily due to higher workover costs related to the well enhancement program at
the Catalina Unit, and higher transportation costs at the Sun Dog Unit and Doty Mountain Units,
where the gas compressors are fueled by natural gas, instead of electric power. The transportation
expense increases as the spot natural gas prices rise.
During the three months ended September 30, 2010, production taxes increased 34% to $1,180, as
compared to $879 in the three months ended September 30, 2009, and production taxes, on a dollars
per Mcfe basis, increased 32%, or $0.12 to $0.50, as compared to the same prior-year period. We are
required to pay taxes on the proceeds received upon the sale of our gas to counterparties. During
the three months ended September 30, 2010, we realized more revenue from the physical sale of gas
to counterparties at spot prices, which resulted in an overall increase in production taxes, as
well as an increase of production taxes expressed on a dollars per Mcfe basis.
Depreciation, depletion, and amortization (“DD&A”) remained consistent, totaling $4,701 and $4,681
in the three months ended September 30, 2010 and 2009, respectively, and depletion and amortization
related to producing assets totaled $4,598 and $4,578 in the three months ended September 30, 2010
and 2009, respectively. Expressed in dollars per Mcfe, depletion and amortization related to
producing assets decreased 2%, or $0.03, to $1.96, as compared to the same prior-year period.
Pipeline operating costs
During the three months ended September 30, 2010, pipeline operating costs decreased 4% to $987
from $1,032 for the three months ended September 30, 2009.
General and administrative expenses
General and administrative expenses decreased 2% to $1,540 for the three months ended September 30,
2010, as compared to $1,579 for the three months ended September 30, 2009. General and
administrative expenses were lower in the three months ended September 30, 2010 due primarily to
$131 of transaction costs that were incurred in the third quarter of 2009 related to the
acquisition of Petrosearch Energy Corporation, which did not recur in 2010. In addition,
share-based compensation and salary and salary-related expenses decreased by approximately $71 and
$125, respectively, due to the termination of two executive officers that terminated during the
second quarter of 2010. These decreases were partially offset by an increase in non-merger related
legal expenses, professional consulting fees, and bank fees.
Income taxes
We recorded an income tax expense of $1,586 during the three months ended September 30, 2010,
as compared to an income tax benefit of $40 during the same prior-year period. Our effective tax
rate for the third quarter of 2010 was 35.9% compared to 40.2% for
the third quarter of 2009. The
rate was lower in the 2010 period due to a reduction in permanent income tax differences related to
stock option expense and higher projected net income. Although we expect to continue to generate
losses for federal income tax reporting purposes, our operations have resulted in a deferred tax
position required under generally accepted accounting principles. We expect to recognize deferred
income tax expense on taxable income for the remainder of 2010 at an expected federal and
state rate of approximately 35.0%.
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Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009
Oil and gas sales volume and price comparisons
Our average gas price realized for the nine months ended September 30, 2010 is calculated by
summing 1) production revenue received from third parties for sale of our gas, which is included in
the oil and gas sales line item on the consolidated statements of operations, 2) settlement of our
cash flow hedges included within oil and gas sales on the consolidated statement of operations and
3) realized gain/loss on our economic hedges, which is included in our price risk management
activities line on the consolidated statements of operations, totaling $3,158 and $3,348, for the
nine months ended September 30, 2010 and 2009, respectively. This amount is divided by the total
Mcfe volume for the periods.
For the nine months ended September 30, 2010, total net production decreased 2% to 6,830 MMcfe, as
compared to the nine months ended September 30, 2009. The decrease is primarily due to lower
production volumes at the Catalina Unit and Mesa Units, as discussed below.
During the nine months ended September 30, 2010, average daily net production at the Atlantic Rim
decreased 1% to 18,211 Mcfe, as compared to 18,368 Mcfe during the same prior-year period. The
decrease in Atlantic Rim production was driven by lower production volumes at the Catalina Unit,
where the average daily net production decreased 10% to 14,697 Mcfe, as compared to 16,415 Mcfe
during the same period of 2009. The decrease is primarily the result the continuation of our
well-enhancement program, which began in the third quarter of 2009, throughout the first nine
months of 2010. This program requires individual wells to be off-line for short periods of time
while the well is worked-over. The decrease is also the result of what management believes to be
the normal production decline for wells within this field. Finally, the Catalina field also
experienced several power outages during the second quarter of 2010 and the Southern Star pipeline
was shut down for maintenance for several days in April 2010, both of which temporarily halted
production. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units
increased 80% to 3,514 Mcfe, as compared to average daily net production of 1,953 Mcfe during the
same prior-year period. The increase was primarily the result of the additional compression
capacity that was added at the Doty Mountain Unit in the first quarter of 2010 and the well
stimulations that were performed within in the Sun Dog Unit, coupled with our purchase of
additional working interest in the Sun Dog and Doty Mountain Units in the third quarter of 2010.
Our working interest in the Sun Dog Unit increased to 21.54% from 8.89% prior to the acquisition,
and the Doty Mountain Unit increased to 18.00% from 16.5% prior to the acquisition.
Average daily net production in the Pinedale Anticline decreased 8% during the nine months ended
September 30, 2010, to 5,137 Mcfe, as compared to 5,559 Mcfe in the same prior-year period. The
operator of the Mesa Units brought an additional 12 wells on-line during the second and third
quarters of 2010, although this did not result in an overall increase in production. Management
believes that the production decline is due to the operator managing the production flow from the
field due to the low gas prices in the Rocky Mountain region.
During the nine months ended September 30, 2010, the average daily net production at the Madden
Unit increased 42% to 709 Mcfe, as compared to 500 Mcfe in the same prior-year period. The
increase was primarily due to a one-time gas balancing adjustment in the second quarter of 2010.
The gas balancing adjustment was offset by lost production time for a 15-day span due to a fire at
the Lost Cabin gas plant.
For the nine months ended September 30, 2010, oil and gas sales decreased 14% to $26,258, as
compared to the same prior-year period. The decline in oil and gas sales was due in part to the
decrease in production volumes discussed above. In addition, during the nine months ended
September 30, 2010, our average realized gas price decreased 13%, to $4.18 from $4.83 during the
nine months ended September 30, 2009. Although the average CIG index price was approximately 43%
higher during the nine months ended September 30, 2010, our realized gas price was lower in 2010
due to the strength of our hedges in 2009. During the nine months ended September 30, 2009, our
derivative instrument settlements totaled $16,513, of which $13,164 was classified as oil and gas
sales on the consolidated statement of operations. In comparison, in 2010, our derivative
instrument settlements totaled $3,158, but were classified as price risk management activities on
the consolidated statement of operations due to the accounting treatment of these instruments.
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Transportation and gathering revenue
During the nine months ended September 30, 2010, transportation and gathering revenue decreased 9%
to $4,238 from $4,659. 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. The decrease in revenue was driven by lower pipeline
throughput from the Catalina Unit.
Price risk management activities
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $11,188
for the nine months ended September 30, 2010, as compared to a loss of $3,670 for the nine months
ended September 30, 2009. This net gain for the 2010 period consists of a net realized gain of
$3,158 related to the settlement of our economic hedges, and an unrealized gain of $8,030 which
represents the change in fair value of our outstanding mark-to-market derivative instruments from
December 31, 2009 to September 30, 2010.
Proceeds from Madden Deep settlement
During the three months ended September 30, 2010, we reached a settlement with many of the
defendants in the lawsuit brought by the Company through which we sought to recover payment for
natural gas produced by our interest in the Madden Deep Unit during the period February 1, 2002
through June 30, 2007. As part of the settlement, the Company received cash proceeds of $4,061.
Prior to the litigation settlement, we had not recognized any amount of sales proceeds related to
natural gas from the Madden Deep Unit for the period February 1, 2002 through October 30, 2006.
For the period from November 1, 2006 through June 30, 2007, the Company had recognized the sales
and had recorded a related account receivable of $292, net of allowance for uncollectible amounts.
As such, the Company recorded income of $3,841 upon the settlement within Proceeds from Madden Deep
settlement on the consolidated statements of operations during the nine months ended September 30,
2010.
Oil and gas production expenses, production taxes, depreciation, depletion and amortization
During the nine months ended September 30, 2010, well production costs increased 29% to $7,167, as
compared to $5,535 during the same prior-year period, and production costs in dollars per Mcfe
increased 33%, or $0.26 to $1.05, as compared to the same 2009 period. A number of factors
contributed to the increase in both the total production costs and production costs on a per Mcfe
basis, including higher workover costs related to the well enhancement program at the Catalina
Unit, higher transportation expense at the Sun Dog and Doty Mountain units, an increase in the
number of producing wells at the Mesa Units, and production costs added from the Petrosearch
properties, which were only partially included in the results for the first nine months of 2009.
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During the nine months ended September 30, 2010, production taxes increased 38% to $3,489, as
compared to $2,521 in the nine months ended September 30, 2009, and production taxes, on a dollars
per Mcfe basis, increased 42%, or $0.15 to $0.51, as compared to the same prior-year period. We are
required to pay taxes on the proceeds received upon the sale of our gas to counterparties. As the
gas market prices rise, less of our revenue is related to cash received from the settlement of the
financial derivative instruments we have in place; rather it is generated by the cash received for
the physical sale of our gas in the open market. The decrease in cash received from derivative
settlements in 2010 resulted in an overall increase in production taxes, as well as an increase of
production taxes expressed on a dollars per Mcfe basis.
DD&A remained consistent, totaling $13,771 and $13,778 in the nine months ended September 30, 2010
and 2009, respectively, and depletion and amortization related to producing assets totaled $13,464
and $13,456 in the nine months ended September 30, 2010 and 2009, respectively. Expressed in
dollars per Mcfe, depletion and amortization related to producing assets increased 2%, or $0.04, to
$1.97, as compared to the same prior-year period.
Pipeline operating costs
During the nine months ended September 30, 2010, pipeline operating costs increased to $3,106 from
$2,686 for the nine months ended September 30, 2009. The Catalina Unit expanded from 47 producing
wells to 67 producing wells during the first quarter of 2009. As a result of this expansion, our
power and fuel costs increased. The 2010 pipeline operating costs reflect a full nine months of
the increased power and fuel charges. In addition, we incurred consulting costs related to
refiguring our compressor units. Lastly, the 2009 expenses were net of a vendor credit we received
for compressor downtime, which lowered the pipeline operating costs for the period.
General and administrative expenses
General and administrative expenses decreased 5% to $4,465 for the nine months ended September 30,
2010, as compared to $4,680 for the nine months ended September 30, 2009. General and
administrative expenses were lower during the nine months ended September 30, 2010, primarily due
to transaction costs of $513 that resulted from the Petrosearch acquisition in 2009, which did not
recur in 2010. In addition, share-based compensation expense decreased by $345 in the 2010 period
primarily due to the timing of our 2009 executive bonus payout, which was paid at the end of 2009,
instead of the first quarter of 2010, as had occurred in the prior year and stock forfeitures
related to two executive terminations in the second quarter of 2010. These decreases were
partially offset by a $156 increase in non-merger related legal costs, a $65 increase due to the
Petrosearch building leases assumed in the merger in August 2009, a $109 increase in bank fees
related to the unused portion of our credit facility, and higher audit and tax fees of
approximately $74.
Income taxes
During the nine months ended September 30, 2010, we recorded income tax expense of $4,531 compared
to income tax expense of $481 during the same prior-year period. Our effective tax rate for the
nine months ended September 30, 2010 was 35.9% compared to 40.2% for the same period of 2009. The
rate was lower in the 2010 period due to a reduction in permanent income tax differences related to
stock option expense and higher projected net income. Although we expect to continue to generate
losses for federal income tax reporting purposes, our operations have resulted in a deferred tax
position required under generally accepted accounting principles. We expect to recognize deferred
income tax expense on taxable income for the remainder of 2010 at an expected federal and state
rate of approximately 35.0%.
CONTRACTED VOLUMES
Changes in the market price of oil and natural gas can significantly affect our profitability and
cash flow. We have entered into various derivative instruments to mitigate the risk associated
with downward fluctuations in the natural gas price. Historically these derivative instruments
have consisted of fixed delivery contracts, swaps, options and costless collars. The duration and
size of our various derivative instruments varies, and depends on our view of market conditions,
available contract prices and our operating strategy.
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Our outstanding derivative instruments as of September 30, 2010 are summarized below (volume and
daily production are expressed in Mcf):
Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional
discussion on the accounting treatment of our derivative contracts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for
the year ended December 31, 2009, and to the Notes to the Consolidated Financial Statements
included in Part I, Item 1 of this report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risks
Our major market risk exposure is in the pricing applicable to our natural gas and oil production.
Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices
applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been
volatile and unpredictable for several years. For the three months ended
September 30, 2010, our income before income taxes would have increased by
$392 for each $0.50 increase per Mcf in natural gas prices and decreased by
$254 for each $0.50 decrease per Mcf in natural gas prices due to the
contracted volumes discussed above. Our income taxes would have increased $6
for each $1.00 change per Bbl in crude oil prices for the three months ended
September 30, 2010.
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 Double Eagle at the time we enter into the
contract. These derivative instruments which have differing expiration dates, are summarized in
the table presented above under Item 2, “Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Contracted Volumes.”
Interest Rate Risks
At September 30, 2010, we had a total of $34.0 million outstanding under our $75 million Credit
Facility ($55 million borrowing availability). We pay interest on outstanding borrowings under our
Credit Facility at interest rates that fluctuate based upon changes in our levels of outstanding
debt and the prevailing market rates. The minimum interest rate is 4.5%. As the interest rate is
variable and reflective of current market conditions, the carrying value approximates the fair
value. Assuming no change in the amount outstanding at September 30, 2010, the annual impact on
interest expense for every 1.0% change in the average interest rate would be approximately $340
before taxes. As of September 30, 2010, the interest rate on the Credit Facility, calculated in
accordance with the agreement, was 4.5%. Any balance outstanding on the Credit Facility matures on
January 31, 2013.
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ITEM 4. CONTROLS AND PROCEDURES
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 Accounting
Officer), of the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief
Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting
Officer) have concluded that our disclosure controls and procedures are effective to ensure that
information we are required to disclose in reports that we file or submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods
specified in SEC rules and forms.
There has been no change in our internal control over financial reporting that occurred during the
quarter ended September 30, 2010 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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.
The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court
of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests
in the Madden Deep Unit. The Company and the other plaintiffs in the case asserted that, under the
gas balancing agreement, they were entitled to receive either monetary damages or their respective
shares of the natural gas produced from the Madden Deep Unit over at least the period February 1,
2002 through June 30, 2007. In the third quarter of 2010, the Company signed a settlement
agreement with many of the defendants in the lawsuit, in which the Company received cash proceeds
of approximately $4,061. Prior to the settlement, the Company had not recognized any amount of
sales proceeds for the period February 1, 2002 through October 30, 2006. For the period from
November 1, 2006 through June 30, 2007, the Company had recognized the sales and had recorded a
related account receivable of $292, net of allowance for uncollectible amounts. As such, the
Company recorded $3,841 within proceeds from Madden Deep settlement on the consolidated statements
of operations during the three and nine months ended September 30, 2010. Sulfur sales are not
subject to a gas balancing agreement, and, accordingly, the Company received the proceeds for its
share of sulfur sales dating back to February 2002 and has continued to receive its respective
share on an on-going basis.
ITEM 1A. RISK FACTORS
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of
our 2009 Annual Report on Form 10-K for the year ended December 31, 2009.
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ITEM 6. EXHIBITS
The following exhibits are filed as part of this report:
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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EXHIBIT INDEX
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