Attached files
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EXCEL - IDEA: XBRL DOCUMENT - Escalera Resources Co. | Financial_Report.xls |
EX-32 - EXHIBIT 32 - Escalera Resources Co. | c18505exv32.htm |
EX-31.2 - EXHIBIT 31.2 - Escalera Resources Co. | c18505exv31w2.htm |
EX-31.1 - EXHIBIT 31.1 - Escalera Resources Co. | c18505exv31w1.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-33571
DOUBLE EAGLE PETROLEUM CO.
(Exact name of registrant as specified in its charter)
MARYLAND (State or other jurisdiction of incorporation or organization) |
83-0214692 (I.R.S. employer identification no.) |
1675 Broadway, Suite 2200, Denver, Colorado (Address of principal executive offices) |
80202 (Zip code) |
303-794-8445
(Registrants telephone number, including area code)
(Registrants telephone number, including area code)
None
(Former name, former address, and former fiscal year, if changed since last report)
(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 þ 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.
Large accelerated filer o | Accelerated filer o | Non-accelerated filer o (Do not check if a small reporting company) |
Small reporting company þ |
Indicate by checkmark 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 issuers classes of common stock, as of
the latest practicable date.
Class Common stock, $.10 par value |
Outstanding as of July 31, 2011 11,197,591 |
DOUBLE EAGLE PETROLEUM CO.
FORM 10-Q
TABLE OF CONTENTS
FORM 10-Q
TABLE OF CONTENTS
2
Table of Contents
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)
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 4,882 | $ | 2,605 | ||||
Cash held in escrow |
564 | 615 | ||||||
Accounts receivable |
5,646 | 5,396 | ||||||
Assets from price risk management |
5,291 | 9,622 | ||||||
Other current assets |
3,795 | 3,653 | ||||||
Total current assets |
20,178 | 21,891 | ||||||
Oil and gas properties and equipment, successful efforts method: |
||||||||
Developed properties |
192,307 | 188,143 | ||||||
Wells in progress |
3,683 | 4,039 | ||||||
Gas transportation pipeline |
5,465 | 5,465 | ||||||
Undeveloped properties |
3,000 | 3,062 | ||||||
Corporate and other assets |
2,001 | 1,982 | ||||||
206,456 | 202,691 | |||||||
Less accumulated depreciation, depletion and amortization |
(81,616 | ) | (72,226 | ) | ||||
Net properties and equipment |
124,840 | 130,465 | ||||||
Assets from price risk management |
397 | | ||||||
Other assets |
148 | 161 | ||||||
TOTAL ASSETS |
$ | 145,563 | $ | 152,517 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable and accrued expenses |
$ | 5,567 | $ | 10,830 | ||||
Accrued production taxes |
3,822 | 2,757 | ||||||
Capital lease obligations, current portion |
273 | 545 | ||||||
Other current liabilities |
128 | 282 | ||||||
Total current liabilities |
9,790 | 14,414 | ||||||
Line of credit |
32,000 | 32,000 | ||||||
Asset retirement obligation |
5,922 | 5,848 | ||||||
Deferred tax liability |
9,384 | 9,578 | ||||||
Total liabilities |
57,096 | 61,840 | ||||||
Preferred stock, $0.10 par value; 10,000,000 shares authorized;
1,610,000 shares issued and outstanding as of
June 30, 2011 and December 31, 2010 |
37,972 | 37,972 | ||||||
Stockholders equity: |
||||||||
Common stock, $0.10 par value; 50,000,000 shares authorized;
11,203,747 issued and 11,191,775 shares outstanding as of
June 30, 2011 and 11,165,305 issued and 11,155,080 outstanding
as of December 31, 2010, respectively |
1,118 | 1,116 | ||||||
Additional paid-in capital |
45,089 | 44,583 | ||||||
Retained earnings |
1,638 | 1,438 | ||||||
Accumulated other comprehensive income |
2,650 | 5,568 | ||||||
Total stockholders equity |
50,495 | 52,705 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
$ | 145,563 | $ | 152,517 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
3
Table of Contents
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues |
||||||||||||||||
Oil and gas sales |
$ | 11,393 | $ | 7,608 | 22,303 | $ | 18,657 | |||||||||
Transportation revenue |
1,221 | 1,401 | 2,453 | 2,889 | ||||||||||||
Price risk management activities, net |
2,068 | 103 | 929 | 7,925 | ||||||||||||
Other income, net |
210 | 280 | 305 | 357 | ||||||||||||
Total revenues |
14,892 | 9,392 | 25,990 | 29,828 | ||||||||||||
Costs and expenses |
||||||||||||||||
Production costs |
2,769 | 2,397 | 5,343 | 4,339 | ||||||||||||
Production taxes |
1,090 | 1,010 | 2,146 | 2,309 | ||||||||||||
Exploration expenses including dry hole costs |
120 | 28 | 172 | 66 | ||||||||||||
Pipeline operating costs |
1,020 | 971 | 2,001 | 2,119 | ||||||||||||
General and administrative |
1,362 | 1,392 | 2,920 | 2,925 | ||||||||||||
Impairment and abandonment of equipment
and properties |
| 80 | 73 | 80 | ||||||||||||
Depreciation, depletion and amortization |
4,718 | 4,530 | 9,391 | 9,070 | ||||||||||||
Total costs and expenses |
11,079 | 10,408 | 22,046 | 20,908 | ||||||||||||
Income (loss) from operations |
3,813 | (1,016 | ) | 3,944 | 8,920 | |||||||||||
Interest expense, net |
(257 | ) | (385 | ) | (644 | ) | (750 | ) | ||||||||
Income (loss) before income taxes |
3,556 | (1,401 | ) | 3,300 | 8,170 | |||||||||||
(Provision) benefit for deferred income taxes |
(1,342 | ) | 512 | (1,238 | ) | (2,945 | ) | |||||||||
NET INCOME (LOSS) |
$ | 2,214 | $ | (889 | ) | $ | 2,062 | $ | 5,225 | |||||||
Preferred stock dividends |
931 | 931 | 1,862 | 1,862 | ||||||||||||
Net income (loss) attributable to common stock |
$ | 1,283 | $ | (1,820 | ) | $ | 200 | $ | 3,363 | |||||||
Net income (loss) per common share: |
||||||||||||||||
Basic |
$ | 0.11 | $ | (0.16 | ) | $ | 0.02 | $ | 0.30 | |||||||
Diluted |
$ | 0.11 | $ | (0.16 | ) | $ | 0.02 | $ | 0.30 | |||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
11,189,472 | 11,116,476 | 11,182,021 | 11,111,092 | ||||||||||||
Diluted |
11,211,031 | 11,116,476 | 11,199,569 | 11,111,092 | ||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
4
Table of Contents
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of dollars)
(Unaudited)
Six months ended June 30, | ||||||||
2011 | 2010 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 2,062 | $ | 5,225 | ||||
Adjustments to reconcile net income to net cash from
operating activities: |
||||||||
Depreciation, depletion, amortization and accretion
of asset retirement obligation |
9,474 | 9,125 | ||||||
Abandonment of non-producing properties and leases |
73 | 80 | ||||||
Provision for deferred taxes |
1,238 | 2,945 | ||||||
Stock-based compensation expense |
525 | 496 | ||||||
Non-cash gain on transfer of asset retirement obligation to third party |
| (164 | ) | |||||
Change in fair value of derivative contracts |
(418 | ) | (6,482 | ) | ||||
Revenue from carried interest |
(117 | ) | (1,282 | ) | ||||
Gain on sale of producing property |
(141 | ) | (142 | ) | ||||
Changes in current assets and liabilities: |
||||||||
Decrease (Increase) in deposit held in escrow |
51 | (2 | ) | |||||
Decrease (Increase) in accounts receivable |
(250 | ) | 784 | |||||
Decrease (Increase) in other current assets |
271 | (728 | ) | |||||
Increase (Decrease) in accounts payable and accrued expenses |
(2,221 | ) | 196 | |||||
Increase in accrued production taxes |
1,065 | 667 | ||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES |
11,612 | 10,718 | ||||||
Cash flows from investing activities: |
||||||||
Payments to acquire producing properties and equipment, net |
(7,155 | ) | (6,652 | ) | ||||
Payments to acquire corporate and non-producing properties |
(30 | ) | (439 | ) | ||||
Sale of corporate assets |
| 7 | ||||||
NET CASH USED IN INVESTING ACTIVITIES |
(7,185 | ) | (7,084 | ) | ||||
Cash flows from financing activities: |
||||||||
Principal payments on capital lease obligations |
(272 | ) | (265 | ) | ||||
Issuance of stock under Company stock plans |
| 6 | ||||||
Tax withholdings related to net share settlement of
restricted stock awards |
(16 | ) | (3 | ) | ||||
Preferred stock dividends |
(1,862 | ) | (1,862 | ) | ||||
Net borrowings (repayments) on credit facility |
| (3,000 | ) | |||||
NET CASH USED IN FINANCING ACTIVITIES |
(2,150 | ) | (5,124 | ) | ||||
Change in cash and cash equivalents |
2,277 | (1,490 | ) | |||||
Cash and cash equivalents at beginning of period |
2,605 | 5,682 | ||||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
$ | 4,882 | $ | 4,192 | ||||
Supplemental disclosure of cash and non-cash transactions: |
||||||||
Cash paid for interest |
$ | 699 | $ | 824 | ||||
Interest capitalized |
$ | 64 | $ | 87 | ||||
Additions to developed properties included in current liabilities |
$ | 1,572 | $ | 4,128 |
The accompanying notes are an integral part of the consolidated financial statements.
5
Table of Contents
DOUBLE EAGLE PETROLEUM CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
1. | Summary of Significant Accounting Policies |
Basis of presentation |
The accompanying unaudited 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 audited 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. |
Certain amounts in the 2010 consolidated financial statements have been reclassified to conform
to the 2011 consolidated financial statement presentation. Such reclassifications had no effect
on net income. |
The accounting policies followed by the Company are set forth in Note 1 to the Companys
consolidated financial statements in the Annual Report on Form 10-K for the year ended December
31, 2010, 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,
2010 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). 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 Companys fee
related to gas gathering is also eliminated in consolidation. |
New accounting pronouncements |
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update No. 2011-04 (ASC 2011-04), an update to ASC Topic 820, Fair Value Measurements and
Disclosures. This update amends current guidance to achieve common fair value measurement and
disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The
update also includes instances where a particular principle or requirement for measuring fair
value or disclosing information about fair value measurements has changed. ASC Update 2011-04
is effective for interim and annual periods beginning after December 15, 2011. The adoption of
ASC Update 2011-04 is not expected to have a material impact on the Companys financial
position, results of operations or cash flows. |
In June 2011, the FASB issued Accounting Standards Update No. 2011-05 (ASC No. 2011-05), an
update to ASC Topic 220, Comprehensive Income. The update amends current guidance to require
companies to present total comprehensive income either in a single, continuous statement of
comprehensive income or in two separate, but consecutive, statements. Under the
single-statement approach, entities must include the components of net income, a total for net
income, the components of other comprehensive income and a total for comprehensive income.
Under the two-statement approach, entities must report an income statement and, immediately
following, a statement of other comprehensive income. Under both methods, entities must also
display adjustments for items reclassified from other comprehensive income to net income in both
net income and other comprehensive income. ASC Update 2011-05 is effective for interim and
annual periods beginning after December 15, 2011. The adoption of ASC Update 2011-05 will
affect the Companys financial statement presentation only, and will have no impact on the
Companys financial position, results of operations or cash flows. |
6
Table of Contents
2. | Earnings per share |
Basic earnings per share of common stock (EPS) is calculated by dividing net income (loss)
attributable to common stock by the weighted average number of shares of common stock
outstanding during the period. Diluted earnings per share incorporates the treasury stock
method, and is calculated by dividing net income (loss) attributable to common stock by the
weighted average number of shares of common stock and potential common stock equivalents
outstanding during the period, if dilutive. Potential common stock equivalents include
incremental shares of common stock issuable upon the exercise of stock options and employee
stock awards. Income attributable to common stock is calculated as net income less dividends
paid on the Series A Preferred Stock. The Company declared and paid cash dividends of $931 and
$1,862 ($.5781 per share) for each of the each of the three and six months ended June 30, 2011
and 2010. |
The following is the calculation of basic and diluted weighted average shares outstanding and
earnings per share of common stock for the periods indicated: |
For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income (loss) |
$ | 2,214 | $ | (889 | ) | $ | 2,062 | $ | 5,225 | |||||||
Preferred stock dividends |
931 | 931 | 1,862 | 1,862 | ||||||||||||
Income (loss) attributable to common stock |
$ | 1,283 | $ | (1,820 | ) | $ | 200 | $ | 3,363 | |||||||
Weighted average shares: |
||||||||||||||||
Weighted average shares basic |
11,189,472 | 11,116,476 | 11,182,021 | 11,111,092 | ||||||||||||
Dilution effect of stock options
outstanding at the end of period |
21,559 | | 17,548 | | ||||||||||||
Weighted average shares diluted |
11,211,031 | 11,116,476 | 11,199,569 | 11,111,092 | ||||||||||||
Income (loss) per common share: |
||||||||||||||||
Basic |
$ | 0.11 | $ | (0.16 | ) | $ | 0.02 | $ | 0.30 | |||||||
Diluted |
$ | 0.11 | $ | (0.16 | ) | $ | 0.02 | $ | 0.30 | |||||||
The following options and unvested restricted shares, which could be potentially dilutive
in future periods, were not included in the computation of diluted net income per share because
the effect would have been anti-dilutive for the periods indicated: |
For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Anti-dilutive shares |
32,109 | 82,360 | 37,918 | 93,529 | ||||||||||||
3. | Derivative Instruments |
The Companys primary market exposure is to adverse fluctuations in the prices of natural gas.
The Company uses derivative instruments, primarily forward contracts, costless collars and
swaps, to manage the price risk associated with its gas production, and the resulting impact on
cash flow, net income, and earnings per share. The Company does not use derivative instruments
for speculative purposes. |
The extent of the Companys risk management activities is controlled through policies and
procedures that involve senior management and were approved by the Companys Board of Directors.
Senior management is responsible for proposing hedge recommendations, execution of the approved
hedging plan, oversight of the risk management process including methodologies used for
valuation and risk measurement and presenting policy changes to the Board. The Companys Board
of Directors is responsible for approving risk management policies and for establishing the
Companys overall risk tolerance levels. The duration of the various derivative instruments
depends on senior managements view of market conditions, available contract prices and the
Companys operating strategy. Under the Companys credit agreement, the Company can hedge up to
90% of the projected proved developed producing reserves for the next 12 month period, and up to
80% of the projected proved developed producing reserves for the ensuing 24 month period. |
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 flows, the cash
flows from these instruments are classified as operating activities. |
7
Table of Contents
Derivative instruments expose the Company to counterparty credit risk. The Company enters into
these contracts with third parties and financial institutions that it considers to be
creditworthy. In addition, the Companys master netting agreements reduce credit risk by
permitting the Company to net settle for transactions with the same counterparty. |
As with most derivative instruments, the Companys derivative contracts contain provisions that
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 June 30, 2011, no party to any of the Companys
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 oil and gas sales on the consolidated statements of operations as
the contracts settle. As of June 30, 2011, the Company expected approximately $4,243 of
unrealized gains before taxes included in AOCI to be reclassified into oil and gas sales in one
year or less as the contracts settle. |
Mark to market hedging instruments |
Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are
recorded at fair value on the consolidated balance sheets and changes in fair value are
recognized in price risk management activities, net on the consolidated statements of
operations. Realized gains and losses resulting from the contract settlement of derivatives not
designated as cash flow hedges also are recorded within price risk management activities, net on
the consolidated statement of operations. |
The Company had the following commodity volumes under derivative contracts as of June 30, 2011: |
Contract Settlement Date | ||||||||||||
2011 | 2012 | 2013 | ||||||||||
Natural Gas forward purchase contracts: |
||||||||||||
Volume (MMcf) |
2,392 | 5,490 | 4,380 |
The table below contains a summary of all the Companys derivative positions reported on the
consolidated balance sheet as of June 30, 2011, presented gross of any master netting
arrangements: |
Derivatives designated as hedging | ||||||||
instruments under ASC 815 | Balance Sheet Location | Fair Value | ||||||
Assets |
||||||||
Commodity derivatives |
Assets from price risk management - current | $ | 4,243 | |||||
Total |
$ | 4,243 | ||||||
Derivatives not designated as hedging | ||||||||
instruments under ASC 815 | Balance Sheet Location | Fair Value | ||||||
Assets |
||||||||
Commodity derivatives |
Assets from price risk management - current | $ | 1,048 | |||||
Assets from price risk management - long term | $ | 397 | ||||||
Total |
$ | 1,445 | ||||||
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The before-tax effect of derivative instruments in cash flow hedging relationships on the
consolidated statements of operations for the three months and six months ended June 30, 2011
and 2010, related to the Companys commodity derivatives was as follows: |
Derivatives Designated as Cash Flow Hedging Instruments under ASC 815 |
Amount of Gain (Loss) Recognized in OCI 1 on Derivatives for the | ||||||||||||||||
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Commodity contracts |
$ | 128 | $ | 791 | $ | 242 | $ | 2,814 |
Location of Gain Reclassified | Amount of Gain Reclassified from AOCI into Income | |||||||||||||||
from AOCI into Income | Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(effective portion) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Oil and gas sales |
$ | 2,252 | $ | | $ | 4,594 | $ | |
Three and six months ended | ||||||||
2011 | 2010 | |||||||
Location of Gain Recognized in Income (Ineffective) Portion
and Amount Excluded from Effectiveness Testing |
N/A | N/A |
1 | Other comprehensive income (OCI). |
The before-tax effect of derivative instruments not designated as hedging instruments on the
consolidated statements of operations for the three and six months ended June 30, 2011 and 2010
was as follows: |
Amount of Gain Recognized in Income on Derivatives for the | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Unrealized gain (loss) on price risk management activities2 |
$ | 1,900 | $ | (1,563 | ) | $ | 418 | $ | 6,482 | |||||||
Realized gain (loss) on price risk management activities
2 |
168 | 1,666 | 511 | 1,443 | ||||||||||||
Total price risk management activites |
$ | 2,068 | $ | 103 | $ | 929 | $ | 7,925 | ||||||||
2 | Included in price risk management activities, net on the consolidated
statements of operations. |
Refer to Note 4 for additional information regarding the valuation of the Companys
derivative instruments. |
4. | Fair Value Accounting |
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: |
| Level 1 Quoted prices (unadjusted) for identical assets or liabilities in
active markets. |
| Level 2 Quoted prices for similar assets or liabilities in active markets;
quoted prices for identical or similar assets or liabilities in markets that are not
active; and model-derived valuations whose inputs or significant value drivers are
observable. |
| Level 3 Unobservable inputs that reflect the Companys own assumptions. |
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Table of Contents
The following table provides a summary of the fair values of assets and liabilities measured at
fair value on a recurring basis: |
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Assets |
||||||||||||||||
Derivative instruments -
Commodity forward contracts |
$ | | $ | 5,688 | $ | | $ | 5,688 | ||||||||
Total assets at fair value |
$ | | $ | 5,688 | $ | | $ | 5,688 | ||||||||
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 and six months ended June 30,
2011. |
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 Companys 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 June 30, 2011, the types of derivative instruments utilized by the Company included costless
collars and swaps. The natural gas derivative markets are highly active. Although the
Companys 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 Companys credit facility approximates fair value as it bears interest
at a floating rate. |
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
Companys 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
Companys 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
consolidated balance sheet at June 30, 2011. |
Concentration of credit risk |
Financial instruments that potentially subject the Company to credit risk consist of accounts
receivable and derivative financial instruments. Substantially all of the Companys receivables
are within the oil and gas industry, including the third party that markets most of the Companys natural gas. 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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The Company currently uses three counterparties for its derivative financial instruments. The
Company continually reviews the credit worthiness of its counterparties, which are generally
other energy companies or major financial institutions. In addition, the Company uses master
netting agreements which allow the Company, in the event of default, to elect early termination
of all contracts with the defaulting counterparty. If the Company chooses to elect early
termination, all asset and liability positions with the defaulting counterparty would be net
settled at the time of election. Net settlement refers to a process by which all transactions
between counterparties are resolved into a single amount owed by one party to the other. |
5. | Impairment of Long-Lived Assets |
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 did not record any proved property impairment expense in the three and six months ended
June 30, 2011 and 2010. The Company wrote off $0 and $73 in the three and six months ended June
30, 2011 and $80 and $80 in each of the three and six months ended June 30, 2010 related to
expired undeveloped leaseholds. |
6. | Compensation Plans |
The Company recognized stock-based compensation expense of $250 and $525 during the three and
six months ended June 30, 2011, respectively, as compared to $220 and $496 in the three and six
months ended June 30, 2010, respectively. |
Compensation expense related to stock options is calculated using the Black Scholes valuation
model. Expected volatilities are based on the historical volatility of Double Eagles common
stock over a period consistent with that of the expected terms of the options. The expected
terms of the options are estimated based on factors such as vesting periods, contractual
expiration dates, historical trends in the Companys common stock price and historical exercise
behavior. The risk-free rates for periods within the contractual life of the options are based
on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. |
A summary of stock option activity under the Companys various stock option plans as of June 30,
2011 and changes during the six months ended June 30, 2011 is presented below: |
Weighted- | ||||||||||||||||
Average | ||||||||||||||||
Weighted- | Remaining | |||||||||||||||
Average | Contractual | Aggregate | ||||||||||||||
Exercise | Term (in | Intrinsic | ||||||||||||||
Shares | Price | years) | Value | |||||||||||||
Options: |
||||||||||||||||
Outstanding at January 1, 2011 |
556,339 | $ | 12.94 | 4.4 | ||||||||||||
Granted |
26,659 | $ | 5.10 | |||||||||||||
Exercised |
(1,200 | ) | $ | 4.50 | ||||||||||||
Cancelled/expired |
(50,000 | ) | $ | 17.95 | ||||||||||||
Outstanding at June 30, 2011 |
531,798 | $ | 12.10 | 3.9 | $ | 575 | ||||||||||
Exercisable at June 30, 2011 |
296,363 | $ | 13.23 | 3.4 | $ | 186 | ||||||||||
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 June 30, 2011 and changes during the six months ended June 30,
2011 were as follows: |
Weighted- | ||||||||
Average | ||||||||
Grant Date | ||||||||
Shares | Fair Value | |||||||
Stock Awards: |
||||||||
Outstanding at January 1, 2011 |
83,304 | $ | 8.40 | |||||
Granted |
15,279 | $ | 5.73 | |||||
Vested |
(38,923 | ) | $ | 4.76 | ||||
Forfeited/returned |
| $ | | |||||
Nonvested at June 30, 2011 |
59,660 | $ | 10.10 | |||||
As part of the acquisition of Petrosearch in 2009, the Company assumed all outstanding warrants
to purchase common stock that had been issued by Petrosearch prior to the merger. At June 30,
2011, the Company had 8,660 warrants with an exercise price of $21.25 that expire December 2011.
The warrants had no intrinsic value at June 30, 2011. |
7. | Income Taxes |
Double Eagle is required to record income tax expense for financial reporting purpose. 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 June 30, 2011, 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. |
8. | Credit Facility |
At June 30, 2011, the Company had a $75 million revolving line of credit in place with a $60
million borrowing base. The credit facility is collateralized by the Companys oil and gas
producing properties. As of June 30, 2011, the balance outstanding on the credit facility of $32,000 has been used to fund the past three years of
development of the Catalina Unit and other non-operated projects in the Atlantic Rim, as well as
projects in the Pinedale Anticline. Any balance outstanding on the facility matures on January
31, 2013. |
Borrowings under the revolving line of credit bear interest at a daily rate equal to the greater
of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar LIBOR Rate plus 1%,
plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. The
interest rate on the facility at June 30, 2011 was 2.87%. For the three months ended June 30,
2011 and 2010, the Company incurred interest expense of $232 and $353, respectively, related to
the credit facility and $558 and $713 for the six months ended June 30, 2011 and 2010,
respectively. The Company capitalized interest costs of $29 and $37 for the three months ended
June 30, 2011 and 2010, respectively, and $64 and $87 for the six months ended June 30, 2011 and
2010, respectively. |
Under the facility, the Company is subject to both financial and non-financial covenants. The
financial covenants include maintaining (i) a current ratio, as defined in the agreement, of 1.0
to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization,
exploration and other non-cash items (EBITDAX) to interest plus dividends, of greater than 1.5
to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of June 30, 2011,
the Company was in compliance with all financial covenants. If the Company violates the
covenants, and is unable to negotiate a waiver or amendment thereof, the lender would have the
right to declare an event of default, terminate the remaining commitment and accelerate all
principal and interest outstanding. |
In July 2011, the Company entered into a $30 million fixed rate swap contract with a third party
as a hedge against the floating interest rate on its credit facility. Under the hedge contract
terms, the Company will effectively lock in the Eurodollar LIBOR portion of the interest
calculation at approximately 0.578% for a portion of its outstanding debt. The contract is
effective July 6, 2011 through December 31, 2012. |
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9. | Series A Cumulative Preferred Stock |
In 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A
Cumulative Preferred Stock (Series A Preferred Stock) at a price to the public of $25.00 per
share. |
Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the
Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The
Series A Preferred Stock does not have any stated maturity date and will not be subject to any
sinking fund or mandatory redemption provisions, except, under some circumstances, upon a change
of ownership or control. Except pursuant to the special redemption upon a change of ownership
or control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On
or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at its
option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus
accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The
shares of Series A Preferred Stock are classified outside of permanent equity on the
consolidated balance sheets due to the following redemption provision. Following a change of
ownership or control of the Company by a person or entity, other than by a Qualifying Public
Company, the Company will be required to redeem the Series A Preferred Stock within 90 days
after the date on which the change of ownership or control occurred for cash. In the event of
liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00
per share, plus all accrued and unpaid dividends, before any payments are made to the holders of
the Companys common stock. |
10. | Comprehensive Income (Loss) |
The components of comprehensive income (loss) were as follows: |
For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income (loss) attributable to common stock |
$ | 1,283 | $ | (1,820 | ) | $ | 200 | $ | 3,363 | |||||||
Change in derivative instrument
fair value, net of tax expense (benefit) 1 |
1,110 | 511 | 1,676 | 1,763 | ||||||||||||
Reclassification to earnings |
(2,252 | ) | | (4,594 | ) | | ||||||||||
Comprehensive income (loss) |
$ | 141 | $ | (1,309 | ) | $ | (2,718 | ) | $ | 5,126 | ||||||
(1) | The change in derivative instrument fair value is net of tax expense/(benefit)
totaling $(982) and $280 for the three months ended June 30, 2011 and 2010, respectively. The
change in derivative instrument fair value is net of tax expense/(benefit) totaling $(1,434) and
$1,051 for the six months ended June 30, 2011 and 2010, respectively. |
The components of accumulated other comprehensive income were as follows:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Net change in derivative instrument fair value, net
of tax expense of $1,593 and $3,027 |
$ | 2,650 | $ | 5,568 | ||||
Total accumulated other comprehensive gain, net |
$ | 2,650 | $ | 5,568 | ||||
11. | Cash Held in Escrow |
The Company has received deposits representing partial prepayments of the expected capital
expenditures from third party working interest owners in the Table Top Unit #1 exploration
project. The unexpended portion of the deposits at June 30, 2011 and December 31, 2010 totaled
$564 and $615, respectively. |
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12. | Contingencies |
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 Companys financial
condition or results of operations. |
On December 18, 2009, Tiberius Capital, LLC (Plaintiff), a stockholder of Petrosearch Energy
Corporation (Petrosearch) prior to the Companys acquisition (the Acquisition) of Petrosearch
pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a
claim in the District Court for the Southern District of New York against Petrosearch, the
Company, and the individuals who were officers and directors of Petrosearch prior to the
Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch
inappropriately denied dissenters rights of appraisal under the Nevada Revised Statutes to its
stockholders in connection with the Acquisition, that the defendants violated various sections of
the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants
caused other damages to the stockholders of Petrosearch. The plaintiff was seeking monetary
damage. On March 31, 2011, the District Court judge dismissed the case. The plaintiff filed a
notice of appeal on April 29, 2011, which preserves the plaintiffs right to appeal. |
13. | Subsequent Events |
In July 2011, the Company entered into a $30 million fixed rate swap contract with a third party
as a hedge against the floating interest rate on its credit facility. Under the contract terms,
the Company will effectively lock in the Eurodollar LIBOR portion of the interest calculation at
approximately 0.578% for a portion of its outstanding debt. The contract is effective July 6,
2011 through December 31, 2012. |
The Company has noted no additional events, other than noted above, that require recognition or
disclosure at June 30, 2011. |
ITEM 2. | MANAGEMENTS 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 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 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, 2010 and
the following factors:
| Changes in or compliance with laws and regulations, particularly those relating to
drilling, derivatives, taxation, safety and protection of the environment; |
| Our ability to obtain, or a decline in, oil or gas production, or a decline in oil or
gas prices; |
| Our ability to increase our natural gas and oil reserves; |
| Our ability to market and find reliable and economic transportation for our gas; |
| The changing political environment in which we operate; |
| Our ability and the ability and willingness of our partners to continue to develop the
Atlantic Rim project; |
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| The volumes of production from our oil and gas development properties, which may be
dependent upon issuance by federal and state governments, or agencies thereof, of
drilling, environmental and other permits, and the availability of specialized
contractors, work force, and equipment; |
| Our future capital requirements and availability of capital resources to fund capital
expenditures; |
| Our ability to maintain adequate liquidity in connection with low oil and gas prices; |
| Incorrect estimates of required capital expenditures; |
| The amount and timing of capital deployment in new investment opportunities; |
| Increases in the cost of drilling, completion and gas collection or other costs of
production and operations; |
| Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves
and actual future production rates and associated costs; |
| Our ability to successfully integrate and profitably operate any future acquisitions; |
| The actions of third party co-owners of interests in properties in which we also own an
interest; |
| The credit worthiness of third parties with which we enter into hedging and business
agreements with; |
| Weather, climate change and other natural phenomena; |
| General economic conditions, tax rates or policies, interest rates and inflation rates; |
| The volatility of our stock price; |
| Industry and market changes, including the impact of consolidations and changes in
competition; |
| The effect of accounting policies issued periodically by accounting standard-setting
bodies; |
| Our ability to remedy any deficiencies that may be identified in the review of our
internal controls; and |
| The outcome of any future litigation or similar disputes and the impact on any such
outcome or related settlements. |
We also may make material acquisitions or divestitures or enter into financing transactions. None
of these events can be predicted with certainty and the possibility of their occurring is not taken
into consideration in the forward-looking statements.
New factors that could cause actual results to differ materially from those described in
forward-looking statements emerge from time to time, and it is not possible for us to predict all
such factors, or the extent to which any such factor or combination of factors may cause actual
results to differ from those contained in any forward-looking statement. We assume no obligation to
update publicly any such forward-looking statements, whether as a result of new information, future
events, or otherwise.
Business Overview and Strategy
We are an independent energy company engaged in the exploration, development, production and sale
of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States.
We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. From 1995 to
2006, our common stock was publicly traded on the NASDAQ Capital Market under the symbol DBLE.
In December 2006, our common stock began trading on the NASDAQ Global Select Market under the same
symbol. Our Series A Cumulative Preferred Stock (Preferred Stock) was issued on the NASDAQ
Capital Market under the symbol DBLEP in July 2007 and began trading on the NASDAQ Global Select
Market in September 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 shareholder value by profitably growing our reserves,
production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas
development drilling; (ii) enhancement of existing production wells and field facilities on
operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the
development of tight sands gas wells at the Mesa Fields on the Pinedale Anticline; (iv) expansion
of our midstream business; (v) pursuit of high quality exploration and strategic development
projects with potential for providing long-term drilling inventories that generate high returns,
including the Niobrara formation in the Atlantic Rim and other properties in which we have
interests and (vi) selectively pursuing strategic acquisitions.
The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit
agreements between the working interest partners. Unitization is a type of sharing arrangement by
which owners of operating and non-operating working interests pool their property interests in a
producing area to form a single operating unit. Units are designed to improve efficiency and
economics of developing and producing an area. The share that each interest owner receives is
based upon the respective acreage contributed by each owner in the participating area (PA) that
surround the producing wells as a percentage of the entire acreage of the PA. The PA, and the
associated working interest, will change as more wells and acreage are added to the PA.
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OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that the amounts available under our $75 million credit facility ($60 million borrowing
base), combined with our net cash from operating activities, will provide us with sufficient funds
to meet future financial covenants, develop new reserves, maintain our current facilities, and
complete our 2011 capital expenditure program (see Capital Requirements on the following page).
Depending on the timing and amounts of future projects, we may be required to seek additional
sources of capital. We can provide no assurance that we will be able to do so on favorable terms
or at all. The Company currently has an effective Form S-3 shelf registration statement on file
with the SEC, which has $150 million of securities available for issuance and provides us the
ability to raise additional funds through private placements or registered offerings of equity. We
also may be required to secure additional debt.
Information about our financial position is presented in the following table:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Financial Position Summary |
||||||||
Cash and cash equivalents |
$ | 4,882 | $ | 2,605 | ||||
Working capital |
$ | 10,388 | $ | 7,477 | ||||
Balance outstanding on credit facility |
$ | 32,000 | $ | 32,000 | ||||
Stockholders equity and preferred stock |
$ | 88,467 | $ | 90,677 | ||||
Ratios |
||||||||
Debt to total capital ratio |
26.6 | % | 26.1 | % | ||||
Total debt to equity ratio |
63.4 | % | 60.7 | % |
During the six months ended June 30, 2011, our working capital increased to $10,388 compared to
$7,477 at December 31, 2010. The higher working capital is primarily the result of a decrease in
our accounts payable and accrued liabilities balances. Our accounts payable and accrued expense
balance was lower in 2011 due to the timing of drilling activity in the Pinedale Anticline and our year-end 2010 balance included additional capital billings related to a
PA adjustment at our non-operated Atlantic Rim properties. We also had greater cash and cash
equivalents on hand at June 30, 2011. This was offset somewhat by a decrease in our current assets
from price risk management due to the settlement of derivative contracts in the first six months of
2011 and higher production taxes.
Cash flow activities
The table below summarizes our cash flows for the six months ended June 30, 2011 and 2010,
respectively:
Six months ended June 30, | ||||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
Cash provided by (used in): |
||||||||
Operating activities |
$ | 11,612 | $ | 10,718 | ||||
Investing activities |
(7,185 | ) | (7,084 | ) | ||||
Financing activities |
(2,150 | ) | (5,124 | ) | ||||
Net change in cash |
$ | 2,277 | $ | (1,490 | ) | |||
During the six months ended June 30, 2011, net cash provided by operating activities was $11,612,
compared to $10,718 in the same prior-year period. The primary sources of cash during the six
months ended June 30, 2011 were $2,062 of net income, which was net of non-cash charges of $9,474
related to depreciation, depletion, and amortization expenses (DD&A) and accretion expense, and
non-cash stock-based compensation expense of $525. In addition, in the first six months of 2011,
we had an increase of $1,238 in the provision for deferred income taxes, which we do not expect to
have to pay in the near future due to our NOL carryforwards. We realized a higher natural gas
price in the first half of 2011, as compared to 2010 due to our hedging program. This additional
cash flow allowed us to use more cash to reduce our accounts payable and accrued expense balance in
the six months ended June 30, 2011.
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During the six months ended June 30, 2011, net cash used in investing activities was relatively
constant, totaling $7,185 in the six months ended June 30, 2011 and $7,084 in the same prior-year
period. Our capital expenditures in the first six months of 2011 primarily related to non-operated
drilling in the Pinedale Anticline.
During the six months ended June 30, 2011, we had net cash used by financing activities of $2,150,
as compared to $5,124 in the same prior-year period. In the first six months of 2011, we
maintained the current debt balance throughout the period, whereas in 2010, we repaid $3,000 of
the outstanding balance on credit facility. We expended cash in the first half of 2011 and 2010 to
make our quarterly dividend payments totaling $1,862 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
At June 30, 2011, we had a $75 million credit facility in place, with $60 million borrowing base.
The credit facility is collateralized by our oil and gas producing properties and other assets. As
of June 30, 2011, the outstanding balance on our credit facility was $32,000. The interest rate as
of June 30, 2011, calculated in accordance with the agreement, was 2.87%, compared to an interest
rate of 4.5% at June 30, 2010. For the three months ended June 30, 2011 and 2010, we incurred
interest expense of $232 and $353, respectively, related to the credit facility and $558 and $713
for the six months ended June 30, 2011 and 2010, respectively. We capitalized interest costs of
$29 and $37 for the three months ended June 30, 2011 and 2010, respectively, and $64 and $87 for
the six months ended June 30, 2011 and 2010, respectively.
In July 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge
against the floating interest rate on our credit facility. Under the hedge contract terms, we have
effectively locked in the Eurodollar LIBOR portion of the interest calculation at approximately
0.578% for a portion of our outstanding debt. Based upon our debt level at June 30, 2011, our
interest rate would be fixed at approximately 3.08% for a $30 million tranche of our outstanding
debt. The swap contract is effective July 6, 2011 through December 31, 2012.
We are subject to certain financial and non-financial covenants with respect to the above credit
facility, including requirements to maintain (i) a current ratio, as defined in the agreement, of
at least 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items
(EBITDAX) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to
EBITDAX ratio of less than 3.5 to 1.0. As of June 30, 2011, we were in compliance with all
covenants under the credit facility. If we violate any of the covenants, 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 April 1 and October 1, beginning October 1,
2011.
Capital Requirements
For 2011, we have budgeted approximately $30 million for our development and exploration programs,
which include our assets in the Atlantic Rim and Pinedale Anticline. We intend to drill in the
Atlantic Rim in the second half of 2011, with 14 coal bed methane (CBM) production wells within
the Catalina Unit. We expect to participate in approximately 16 new wells at the Mesa Units. We
also have allocated capital in our 2011 capital budget for one exploratory well into the Niobrara
formation in the Atlantic Rim. We are still waiting for permits for this well. We expect to fund
our 2011 capital expenditures with cash provided by operating activities and funds made available
through our credit facility. Our 2011 capital budget does not include the impact of potential
future exploration projects or possible acquisitions, which we continually evaluate.
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Contractual Obligations
The impact that our contractual obligations as of June 30, 2011 are expected to have on our
liquidity and cash flows in future periods is:
Less than | 1 - 3 | 3- 5 | More than | |||||||||||||||||
Total | one year | Years | Years | 5 Years | ||||||||||||||||
Credit facility (a) |
$ | 32,000 | $ | | $ | 32,000 | $ | | $ | | ||||||||||
Interest on credit facility (b) |
1,556 | 931 | 625 | | | |||||||||||||||
Capital leases |
376 | 376 | | | | |||||||||||||||
Operating leases |
5,539 | 2,491 | 2,890 | 158 | | |||||||||||||||
Total contractual cash
commitments |
$ | 39,471 | $ | 3,798 | $ | 35,515 | $ | 158 | $ | | ||||||||||
(a) | The amount listed reflects the balance outstanding as of June 30, 2011. Any balance
outstanding on our credit facility at January 31, 2013, will be due at that time. |
|
(b) | Assumes the interest rate on our credit facility is consistent with that of June 30,
2011. |
Off-Balance Sheet Arrangements
We do not participate in transactions that generate relationships with unconsolidated entities or
financial partnerships. Such entities are often referred to as structured finance or special
purpose entities (SPEs) or variable interest entities (VIEs). SPEs and VIEs can be established
for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or
limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any
of the periods presented.
RESULTS OF OPERATIONS
Three months ended June 30, 2011 compared to the three months ended June 30, 2010
Oil and gas sales volume and price comparisons
Three Months Ended June 30, | Percent | Percent | ||||||||||||||||||||||
2011 | 2010 | Volume | Price | |||||||||||||||||||||
Volume | Average Price | Volume | Average Price | Change | Change | |||||||||||||||||||
Product: |
||||||||||||||||||||||||
Gas (Mcf) |
2,278,019 | $ | 4.80 | 2,212,115 | $ | 3.99 | 3 | % | 20 | % | ||||||||||||||
Oil (Bbls) |
6,625 | $ | 93.50 | 5,892 | $ | 75.00 | 12 | % | 25 | % | ||||||||||||||
Mcfe |
2,317,769 | $ | 4.99 | 2,247,466 | $ | 4.13 | 3 | % | 21 | % |
For the three months ended June 30, 2011, oil and gas sales increased 50% to $11,393, as compared
to the three months ended June 30, 2010. The increase is largely attributed to cash we received
upon settlement of our cash flow hedge, totaling $2,252 for the three months ended June 30, 2011.
In addition, the average CIG market price, which is the index on which most of our gas volumes are
sold, rose 6% from the three months ended June 30, 2010 and production volumes increased 3%, both
of which also resulted in higher oil and gas sales.
Our average realized natural gas price increased 20% to $4.80 for the three months ended June 30,
2011, as compared to the three months ended June 30, 2010. We calculate our average realized
natural gas price by summing (1) production revenue received from third parties for the sale of our
gas, which is included within oil and gas sales on the consolidated statements of operations; (2)
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 within price
risk management activities, net on the consolidated statements of operations, totaling $168 and
$1,666, for the three months ended June 30, 2011 and 2010, respectively.
Our total net production increased 3% to 2,318 MMcfe for the quarter ended June 30, 2011 as
compared to 2,247 MMcfe for the three months ended June 30, 2010. We experienced an increase in
production volumes at the Sun Dog and Doty Mountain Units, which offset a production decline at the
Catalina Unit, as discussed below.
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During the three months ended June 30, 2011, our total average daily net production at the Atlantic
Rim increased 8% to 19,053 Mcfe, as compared to 17,565 Mcfe during the same prior-year period. Our
Atlantic Rim production comes from three operating units, the Catalina Unit, the Sun Dog Unit and
the Doty Mountain Unit. The Catalina Unit is operated by the Company.
| Average daily net production at our Catalina Unit decreased 8% to 13,431 Mcfe per day,
as compared to 14,531 Mcfe per day during the same prior-year period. The decrease is
largely the result of what management believes to be the normal production decline for
wells within the field. |
| Average daily net production at the Sun Dog and Doty Mountain Units increased 85% for
the three months ended June 30, 2011 to 5,622 Mcfe per day, as compared to 3,034 Mcfe per
day in the same prior-year period, largely due to our higher working interest in both
units. We purchased additional working interests in the Sun Dog and Doty Mountain Units
during the third quarter of 2010, which increased our working interest in the Sun Dog Unit
to 20.46% from 8.89%, and the Doty Mountain Unit to 18.00% from 16.5%. The increase is
also attributed in part to better production from certain Doty Mountain wells due to
fracture stimulation and additional water capacity at the Sun Dog Unit. |
Average daily net production in the Pinedale Anticline remained relatively constant quarter over
quarter, totaling 5,052 Mcfe for the three months ended June 30, 2011, as compared to 5,053 Mcfe in
the same prior-year period. The operator brought seven new wells on-line for production during the
quarter. The operator at the Mesa Units has informed us that it expects to complete 10 additional
wells over the next two quarters. In addition, the operator has indicated that it expects to begin
drilling 16 additional wells in 2011.
Transportation and gathering revenue
During the three months ended June 30, 2011, transportation and gathering revenue decreased 13% to
$1,221 from $1,401 for the three months ended June 30, 2010. 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 is due to the lower production volume at the Catalina Unit.
Price risk management activities, net
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $2,068 for
the three months ended June 30, 2011, as compared to a gain of $103 for the same prior-year period.
The net gain consisted of an unrealized non-cash gain of $1,900, which represents the change in
the fair value on our economic hedges at June 30, 2011, based on the expected future prices of the
related commodities, and a net realized gain of $168 related to the cash settlement of some of our
economic hedges.
Oil and gas production expenses and depreciation, depletion and amortization
Three Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
(in dollars per Mcfe) | ||||||||
Average price |
$ | 4.99 | $ | 4.13 | ||||
Production costs |
1.19 | 1.07 | ||||||
Production taxes |
0.47 | 0.45 | ||||||
Depletion and amortization |
1.99 | 1.97 | ||||||
Total operating costs |
3.65 | 3.49 | ||||||
Gross margin |
$ | 1.34 | $ | 0.64 | ||||
Gross margin percentage |
27 | % | 15 | % | ||||
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 period.
This calculation excludes certain gathering costs incurred by the Companys subsidiary, Eastern
Washakie Midstream LLC, which are eliminated in consolidation. During the three months ended June
30, 2011, well production costs increased 15% to $2,769, as compared to $2,397 during the same
prior-year period, and production costs in dollars per Mcfe increased 11%, or $0.12 to $1.19, as
compared to the same prior-year period. The increase in production costs was driven by additional
production costs from the Sun Dog and Doty Mountain Units resulting from our increased working
interests at these properties, which was purchased in July 2010. Because production from the Sun
Dog and Doty Mountain Units, which have historically yielded lower margins than many of our
properties, made up a larger percentage of our total production during the 2011 period, we also
experienced an increase in production costs on a per Mcfe basis. This increase in production costs
at the Sun Dog and Doty Mountain Units was partially offset by lower repair and maintenance costs
at the Catalina Unit.
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Depreciation, depletion, and amortization (DD&A) for the quarter ended June 30, 2011 increased 4%
to $4,718, as compared to $4,530 in the same prior-year period, and depletion and amortization
related to producing assets also increased 4% to $4,612 as compared to $4,428 in the same
prior-year period. The increase in DD&A expense was primarily driven by higher production volumes.
Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased
1%, or $0.02, to $1.99 as compared to the same prior-year period.
Pipeline operating costs
During the three months ended June 30, 2011, pipeline operating costs increased 5% to $1,020 from
$971 for the three months ended June 30, 2010.
General and administrative expenses
General and administrative expenses decreased 2% to $1,362 for the three months ended June 30,
2011, as compared to $1,392 for the three months ended June 30, 2010. During the second quarter of
2011, we recovered from our insurance company approximately $101 of legal fees related to
litigation resulting from our 2009 Petrosearch acquisition. This was offset by a $45 increase in
bad debt expense and a $27 increase in director fees due to the addition of one independent
director in the first quarter of 2011.
Income taxes
We recorded income tax expense of $1,342 during the three months ended June 30, 2011, as compared
to an income tax benefit of $512 during the same prior-year period. Our effective tax rate for the
three months ended June 30, 2011 was 37.55% compared to 36.0% for the second quarter of 2010. Our
effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent
income tax differences related to stock option expense as compared to net income and an increase in
non-deductible DD&A expense. Although we expect to continue to generate losses for federal income
tax reporting purposes, our operations have resulted in a deferred tax position required under
generally accepted accounting principles. We expect to recognize deferred income tax expense on
taxable income for the remainder of 2011 at an expected federal and state rate of approximately
35.2%.
Six months ended June 30, 2011 compared to the six months ended June 30, 2010
Oil and gas sales volume and price comparisons
Six Months Ended June 30, | Percent | Percent | ||||||||||||||||||||||
2011 | 2010 | Volume | Price | |||||||||||||||||||||
Volume | Average Price | Volume | Average Price | Change | Change | |||||||||||||||||||
Product: |
||||||||||||||||||||||||
Gas (Mcf) |
4,491,692 | $ | 4.82 | 4,412,125 | $ | 4.34 | 2 | % | 11 | % | ||||||||||||||
Oil (Bbls) |
13,390 | $ | 88.05 | 12,828 | $ | 73.07 | 4 | % | 21 | % | ||||||||||||||
Mcfe |
4,572,032 | $ | 4.99 | 4,489,091 | $ | 4.47 | 2 | % | 12 | % |
For the six months ended June 30, 2011, oil and gas sales increased 20% to $22,303, as
compared to $18,657 during the first six months of 2010. The increase is attributed to our hedging
program, which provided cash of $4,594 from the settlement of our cash flow hedges during the first
six months of 2011. In addition, we experienced a 2% increase in production volumes in the first
six months of 2011 as compared to the same prior-year period. These increases were offset by a 6%
decrease in the average CIG market price, which is the index on which most of our gas volumes are
sold.
Our average realized natural gas price increased 11% to $4.82 for six months ended June 30, 2011,
as compared to the first six months of 2010. Despite the decrease in the average CIG market price
during the 2011 period, we realized a higher natural gas price as a result of our hedging program.
In addition to the $4,594 of cash flow hedge settlements included in oil and gas sales noted above,
we also realized settlements on our economic hedges totaling $511 during the 2011 period. For the
six months ended June 30, 2010 our hedges accounted for a total of $1,443.
20
Table of Contents
Our total net production increased 2% to 4,572 MMcfe for the six months ended June 30, 2011
compared to 4,489 MMcfe for the same prior year period. We experienced an increase in production
volumes at the Sun Dog and Doty Mountain Units, which offset the production decline at the Catalina
Unit, as discussed below.
During the six months ended June 30, 2011, average daily net production at the Atlantic Rim
increased 5% to 18,830 Mcfe, as compared to 17,911 Mcfe during the same prior-year period, which is
further broken out below:
| Average daily net production at our Catalina Unit decreased 10% to 13,576 Mcfe per day,
as compared to 15,062 Mcfe per day during the first six months of 2010. The decrease is
largely the result of what management believes to be the normal production decline for
wells within the field. |
| Average daily net production at the Sun Dog and Doty Mountain Units increased 84% for
the six months ended June 30, 2011 to 5,254 Mcfe per day from 2,849 Mcfe per day in the
same prior-year period, largely due to our higher working interest in both units. We
purchased additional working interests in the Sun Dog and Doty Mountain Units during the
third quarter of 2010, which increased our working interest in the Sun Dog Unit to 20.46%
from 8.89% prior to the purchase, and the Doty Mountain Unit to 18.00% from 16.5% prior to
the purchase. The increase is also attributed in part to better production from certain
Doty Mountain wells due to fracture stimulation and additional water injection capacity at
the Sun Dog Unit. |
Average daily net production in the Pinedale Anticline was relatively constant for the six months
ended June 30, 2011, totaling 5,010 Mcfe per day, as compared to 5,034 Mcfe in the same prior-year
period. The operator brought an additional seven wells on-line throughout the second quarter of
2011. The operator at the Mesa Units has informed us that it expects to complete 10 additional
wells over the next two quarters. In addition, the operator has indicated that it expects to begin
drilling 16 more wells in 2011.
Transportation and gathering revenue
During the six months ended June 30, 2011, transportation and gathering revenue decreased 15% to
$2,453 from $2,889. 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 is due to the lower production
volume at the Catalina Unit.
Price risk management activities, net
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $929 for
the six months ended June 30, 2011, as compared to a gain of $7,925 for the six months ended June
30, 2010. The net gain consisted of an unrealized non-cash gain of $418, which represents the
change in the fair value on our economic hedges at June 30, 2011, based on the future expected
prices of the related commodities, and a net realized gain of $511 related to the cash settlement
of some of our economic hedges.
Oil and gas production expenses, and depreciation, depletion and amortization
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
(in dollars per Mcfe) | ||||||||
Average price |
$ | 4.99 | $ | 4.47 | ||||
Production costs |
1.17 | 0.97 | ||||||
Production taxes |
0.47 | 0.51 | ||||||
Depletion and amortization |
2.01 | 1.97 | ||||||
Total operating costs |
3.65 | 3.45 | ||||||
Gross margin |
$ | 1.34 | $ | 1.02 | ||||
Gross margin percentage |
27 | % | 23 | % | ||||
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During the six months ended June 30, 2011, well production costs increased 23% to $5,343, as
compared to $4,339 during the same prior-year period, and production costs in dollars per Mcfe
increased 21%, or $0.20 to $1.17, as compared to the same prior-year period. The increase in
production costs in total was driven by additional production costs from the Sun Dog and Doty
Mountain Units resulting from our increased working interests at these properties. In addition,
because production from the Sun Dog and Doty Mountain Units, which have historically yielded lower
margins than many of our properties, made up a larger percentage of our total production during the
2011 period, we experienced an increase in production costs on a per Mcfe basis.
DD&A increased 3% to $9,391 for the six months ended June 30, 2011, as compared to $9,097 for the
six months ended June 30, 2010, and depletion and amortization related to producing assets also
increased 4% to $9,180 as compared to $8,866 in the same prior-year period. The increase in DD&A
expense was primarily driven by higher production volumes. Expressed in dollars per Mcfe,
depletion and amortization related to producing assets increased 2%, or $0.04, to $2.01 as compared
to the same prior-year period.
Pipeline operating costs
During the six months ended June 30, 2011, pipeline operating costs decreased to $2,001 from $2,119
as compared to the same prior-year period.
General and administrative expenses
General and administrative expenses remained relatively constant period over period, totaling
$2,920 and $2,925 for the six months ended June 30, 2011 and 2010, respectively. During the second
quarter o f 2011, we recovered from our insurance company approximately $101 of legal fees related
to litigation resulting from our 2009 Petrosearch acquisition. In addition, we realized a $77
decrease in audit and tax fees, a $78 decrease in legal fees and a $49 decrease in our directors
and officers insurance as compared to the same prior year period. These decreases were offset by a $69 increase
related to our Board of Directors expense due to the expansion of our Board and expenses incurred
related to Board training and conferences, an increase in bank fees of $56 due to an increase in
the unused portion of our credit facility and in 2010 we had recovered an outstanding receivable
that had previously been written off totaling $155.
Income taxes
During the six months ended June 30, 2011, we recorded income tax expense of $1,238 compared to
income tax expense of $2,945 during the same prior-year period. Our effective tax rate for the six
months ended June 30, 2011 was 37.55% compared to 36.0% for the second quarter of 2010. Our
effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent
income tax differences related to stock option expense as compared to net income and an increase in
non-deductible DD&A expense. Although we expect to continue to generate losses for federal income
tax reporting purposes, our operations have resulted in a deferred tax position required under
generally accepted accounting principles. We expect to recognize deferred income tax expense on
taxable income for the remainder of 2011 at an expected federal and state rate of approximately
35.2%.
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Table of Contents
CONTRACTED VOLUMES
Changes in the market price of oil and natural gas can significantly affect our profitability and
cash flow. We have entered into various derivative instruments to mitigate the risk associated
with downward fluctuations in the natural gas price. Historically these derivative instruments
have consisted of fixed delivery contracts, swaps, options and costless collars. The duration and
size of our various derivative instruments varies, and depends on our view of market conditions,
available contract prices and our operating strategy.
Our outstanding derivative instruments as of June 30, 2011 are summarized below (volume and daily
production are expressed in Mcf):
Remaining | ||||||||||||||||||||
Contractual | Daily | Price | ||||||||||||||||||
Type of Contract | Volume | Production | Term | Price | Index (1) | |||||||||||||||
Fixed Price Swap |
1,472,000 | 8,000 | 01/11-12/11 | $7.07 | CIG | |||||||||||||||
Costless Collar |
155,000 | 5,000 | 08/09-07/11 | $4.50 floor | NYMEX | |||||||||||||||
$7.90 ceiling | ||||||||||||||||||||
Costless Collar |
765,000 | 5,000 | 12/09-11/11 | $4.50 floor | NYMEX | |||||||||||||||
$9.00 ceiling | ||||||||||||||||||||
Fixed Price Swap |
1,830,000 | 5,000 | 01/12-12/12 | $5.10 | NYMEX | |||||||||||||||
Fixed Price Swap |
3,660,000 | 10,000 | 01/12-12/12 | $5.05 | NYMEX | |||||||||||||||
Fixed Price Swap |
2,190,000 | 6,000 | 01/13-12/13 | $5.16 | NYMEX | |||||||||||||||
Costless Collar |
2,190,000 | 6,000 | 01/13-12/13 | $5.00 floor | NYMEX | |||||||||||||||
$5.35 ceiling | ||||||||||||||||||||
Total |
12,262,000 | |||||||||||||||||||
(1) | CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.
NYMEX refers to quoted prices on the New York Mercantile Exchange. |
Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional
discussion on the accounting treatment of our derivative contracts.
Subsequent to the end of the period ended June 30, 2011, we entered into a $30 million fixed rate
swap contract with a third party as a hedge against the floating interest rate on our credit
facility. which fixes the Eurodollar portion of our interest rate calculation at approximately
0.578%. The contract is in place through December 31, 2012.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for
the year ended December 31, 2010, and to the Notes to the Consolidated Financial Statements
included in Part I, Item 1 of this report.
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Commodity Price Risks
Our major market risk exposure is in the pricing applicable to our natural gas and oil production.
Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices
applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been
volatile and unpredictable for several years. The prices we receive for production depend on many
factors outside of our control. For the three months ended June 30, 2011, our income before income
taxes would have increased by $548 for each $0.50 increase per Mcf in natural gas prices and
decreased by $297 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 June 30,
2011.
The primary objective of our commodity price risk management policy is to preserve and enhance the
value of our equity 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 contract. These derivative instruments which have differing expiration
dates, are summarized in the table presented above under Contracted Volumes.
Interest Rate Risks
At June 30, 2011, we had a total of $32,000 outstanding under our $75 million credit facility ($60
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 average interest rate for the three months ended June 30, 2011,
calculated in accordance with the agreement, was 2.87%. Because the interest rate is variable and
reflects current market conditions, the carrying value approximates the fair value. Assuming no
change in the amount outstanding at June 30, 2011, the annual impact on interest expense for every
1.0% change in the average interest rate would be approximately $320 before taxes. Any balance
outstanding on the credit facility matures on January 31, 2013.
23
Table of Contents
In July 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge
against the floating interest rate on our credit facility. Under the hedge contract terms, we have
effectively locked in the Eurodollar LIBOR portion of the interest calculation at approximately
0.578% for a portion of our outstanding debt. Based upon our debt level at June 30, 2011, this
would result in a fixed interest rate of 3.08% for a $30 million tranche of our outstanding debt.
The contract is effective July 6, 2011 through December 31, 2012.
ITEM 4. | CONTROLS AND PROCEDURES |
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management, including our Chief
Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting
Officer), of the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief
Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting
Officer) have concluded that our disclosure controls and procedures are effective to ensure that
information we are required to disclose in reports that we file or submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms.
There has been no change in our internal control over financial reporting that occurred during the
quarter ended June 30, 2011 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, the Company is involved in various legal proceedings, including the matters
discussed below. These proceedings are subject to the uncertainties inherent in any litigation.
The Company is defending itself vigorously in all such matters, and while the ultimate outcome and
impact of any proceeding cannot be predicted with certainty, management believes that the
resolution of any proceeding will not have a material adverse effect on the Companys financial
condition or results of operations.
On December 18, 2009, Tiberius Capital, LLC (Plaintiff), a stockholder of Petrosearch Energy
Corporation (Petrosearch) prior to the Companys acquisition (the Acquisition) of Petrosearch
pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a
claim in the District Court for the Southern District of New York against Petrosearch, the Company,
and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied
dissenters rights of appraisal under the Nevada Revised Statutes to its stockholders in connection
with the Acquisition, that the defendants violated various sections of the Securities Act of 1933
and the Securities Exchange Act of 1934, and that the defendants caused other damages to the
stockholders of Petrosearch. The plaintiff was seeking monetary damage. On March 31, 2011, the
District Court judge dismissed the case. The plaintiff filed a notice of appeal on April 29, 2011,
which preserves the plaintiffs right to appeal.
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 2010 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we
incorporate by reference herein.
24
Table of Contents
ITEM 6. | EXHIBITS |
The following exhibits are filed as part of this report:
Exhibit | Description: | |||
3.1 | (a) | Articles of Incorporation of the Company (incorporated by reference
from Exhibit 3.1(a) of the Companys Annual Report on Form 10-KSB
for the year ended August 31, 2001). |
||
3.1 | (b) | Certificate of Correction of the Company (incorporated by reference
from Exhibit 3.1(b) of the Companys Annual Report on Form 10-KSB
for the year ended August 31, 2001). |
||
3.1 | (c) | Certificate of Correction of the Company (incorporated by reference
from Exhibit 3 of the Companys Quarterly Report on Form 10-QSB for
the quarter ended November 30, 2001). |
||
3.1 | (d) | Certificate of Correction to the Articles of Incorporation of the
Company (incorporated by reference from Exhibit 3.3 of the
Companys Current Report of Form 8-K dated June 29, 2007). |
||
3.1 | (e) | Articles of Amendment to the Articles of Incorporation of the
Company, filed with the Maryland Department of Assessments and
Taxation on June 26, 2007 (incorporated by reference from Exhibit
3.1 of the companys Current Report on Form 8-K dated June 29,
2007). |
||
3.1 | (f) | Articles Supplementary, (incorporated by reference from Exhibit 3.2
of the Companys Current Report of Form 8-K dated June 29, 2007). |
||
3.1 | (g) | Articles Supplementary of Junior Participating Preferred Stock,
Series B of the Company, dated as of August 21, 2007 (incorporated
by reference from Exhibit 3.1 of the Companys Current Report of
Form 8-K dated August 28, 2007). |
||
3.1 | (h) | Amendment to Bylaws, Revised Article II, Section 9 (incorporated
by reference from Exhibit 3.1 of the companys Current Report on
Form 8-K filed on March 5, 2010). |
||
3.2 | Second Amended and Restated Bylaws of the Company (incorporated by
reference from Exhibit 3.2 of the Companys Current Report on Form
8-K filed on June 11, 2007). |
|||
4.1 | (a) | Form of Warrant Agreement concerning Common Stock Purchase Warrants
(incorporated by reference from Exhibit 4.3 of the Amendment No. 1
to the Companys Registration Statement on Form SB-2 filed on
November 27, 1996, SEC Registration No. 333-14011). |
||
4.1 | (b) | Rights Agreement between the Company and Computershare Trust
Company, N.A. (incorporated herein by reference to the Companys
Current Report on Form 8-K filed on August 24, 2007) |
||
10.1 | (a) | Second Amendment to Amended and Restated Credit Agreement dated March 8,
2011 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al;
(incorporated by reference from Exhibit 10.1, of the Companys Current report of
Form 8-K dated March 10, 2011). |
25
Table of Contents
Exhibit | Description: | |||
31.1 | * | Certification of Principal Executive Officer and Chief Executive Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
||
31.2 | * | Certification of Principal Accounting Officer and Chief Financial Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
||
32 | * | Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to section
906 of the Sarbanes-Oxley Act of 2002. |
||
101.INS | ** | XBRL Instance Document |
||
101.SCH | ** | XBRL Taxonomy Extension Scheme Document |
||
101.CAL | ** | XBRL Taxonomy Extension Calculation Linkbase Document |
||
101.LAB | ** | XBRL Taxonomy Extension Label Linkbase Document |
||
101.PRE | ** | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed within this Form 10-Q. |
|
** | Pursuant to Rule 406T of Regulation S-T, these Interactive Data Files
are deemed not filed or part of a registration statement or prospectus
for purposes of Sections 11 or 12 of the Securities Act of 1933, as
amended, are deemed not filed for purposes of Section 18 of the
Securities Exchange Act of 1934, as amended, and otherwise are not
subject to the liability under these sections. |
26
Table of Contents
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.
DOUBLE EAGLE PETROLEUM CO. (Registrant) |
||||
Date: August 4, 2011 | By: | /s/ Richard D. Dole | ||
Richard D. Dole | ||||
Chief Executive Officer (Principal Executive Officer) |
||||
27
Table of Contents
EXHIBIT INDEX
Exhibit Number | Description: | |||
3.1 | (a) | Articles of Incorporation of the Company (incorporated by reference
from Exhibit 3.1(a) of the Companys Annual Report on Form 10-KSB
for the year ended August 31, 2001). |
||
3.1 | (b) | Certificate of Correction of the Company (incorporated by reference
from Exhibit 3.1(b) of the Companys Annual Report on Form 10-KSB
for the year ended August 31, 2001). |
||
3.1 | (c) | Certificate of Correction of the Company (incorporated by reference
from Exhibit 3 of the Companys Quarterly Report on Form 10-QSB for
the quarter ended November 30, 2001). |
||
3.1 | (d) | Certificate of Correction to the Articles of Incorporation of the
Company (incorporated by reference from Exhibit 3.3 of the
Companys Current Report of Form 8-K dated June 29, 2007). |
||
3.1 | (e) | Articles of Amendment to the Articles of Incorporation of the
Company, filed with the Maryland Department of Assessments and
Taxation on June 26, 2007 (incorporated by reference from Exhibit
3.1 of the companys Current Report on Form 8-K dated June 29,
2007). |
||
3.1 | (f) | Articles Supplementary, (incorporated by reference from Exhibit 3.2
of the Companys Current Report of Form 8-K dated June 29, 2007). |
||
3.1 | (g) | Articles Supplementary of Junior Participating Preferred Stock,
Series B of the Company, dated as of August 21, 2007 (incorporated
by reference from Exhibit 3.1 of the Companys Current Report of
Form 8-K dated August 28, 2007). |
||
3.1 | (h) | Amendment to Bylaws, Revised Article II, Section 9 (incorporated
by reference from Exhibit 3.1 of the companys Current Report on
Form 8-K filed on March 5, 2010). |
||
3.2 | Second Amended and Restated Bylaws of the Company (incorporated by
reference from Exhibit 3.2 of the Companys Current Report on Form
8-K filed on June 11, 2007). |
|||
4.1 | (a) | Form of Warrant Agreement concerning Common Stock Purchase Warrants
(incorporated by reference from Exhibit 4.3 of the Amendment No. 1
to the Companys Registration Statement on Form SB-2 filed on
November 27, 1996, SEC Registration No. 333-14011). |
||
4.1 | (b) | Rights Agreement between the Company and Computershare Trust
Company, N.A. (incorporated herein by reference to the Companys
Current Report on Form 8-K filed on August 24, 2007) |
||
10.1 | (a) | Second Amendment to Amended and Restated Credit Agreement dated March 8,
2011 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al;
(incorporated by reference from Exhibit 10.1, of the Companys Current report of
Form 8-K dated March 10, 2011). |
||
28
Table of Contents
Exhibit Number | Description: | |||
31.1 | * | Certification of Principal Executive Officer and Chief Executive Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
||
31.2 | * | Certification of Principal Accounting Officer and Chief Financial Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
||
32 | * | Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to section
906 of the Sarbanes-Oxley Act of 2002. |
||
101.INS** | XBRL Instance Document |
|||
101.SCH** | XBRL Taxonomy Extension Scheme Document |
|||
101.CAL** | XBRL Taxonomy Extension Calculation Linkbase Document |
|||
101.LAB** | XBRL Taxonomy Extension Label Linkbase Document |
|||
101.PRE** | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed within this Form 10-Q. |
|
** | Pursuant to Rule 406T of Regulation S-T, these Interactive Data Files
are deemed not filed or part of a registration statement or prospectus
for purposes of Sections 11 or 12 of the Securities Act of 1933, as
amended, are deemed not filed for purposes of Section 18 of the
Securities Exchange Act of 1934, as amended, and otherwise are not
subject to the liability under these sections. |
29