UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
OR
¨ 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 1-32414
W&T OFFSHORE, INC.
(Exact name of registrant as specified in its charter)
(IRS Employer
Identification Number)
Nine Greenway Plaza, Suite 300
Houston, Texas
(713) 626-8525
(Registrant’s telephone number, including area code)
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 ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company. Yes ¨ No þ
As of November 2, 2011, there were 74,461,440 shares outstanding of the registrant’s common stock, par value $0.00001.
W&T OFFSHORE, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PART I – FINANCIAL INFORMATION
Item 1.
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
PART II – OTHER INFORMATION
Item 1A.
Item 5.
Item 6.
SIGNATURE
EXHIBIT INDEX
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
Current assets:
Cash and cash equivalents
Receivables:
Oil and natural gas sales
Joint interest and other
Insurance
Total receivables
Deferred income taxes
Prepaid expenses and other assets
Total current assets
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $152,646 at September 30, 2011 and $65,419 at December 31, 2010 were excluded from amortization)
5,858,814
5,225,582
Furniture, fixtures and other
Total property and equipment
Less accumulated depreciation, depletion and amortization
Net property and equipment
Restricted deposits for asset retirement obligations
Other assets
Total assets
Current liabilities:
Accounts payable
Undistributed oil and natural gas proceeds
Asset retirement obligations
Accrued liabilities
Income taxes payable
Income taxes deferred – current portion
Total current liabilities
Long-term debt
Asset retirement obligations, less current portion
Other liabilities
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.00001 par value; 2,000,000 shares authorized; 0 issued at September 30, 2011 and December 31, 2010
—
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,332,969 issued and 74,463,796 outstanding at September 30, 2011; 77,343,520 issued and 74,474,347 outstanding at December 31, 2010
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Additional paid-in capital
Retained earnings
Treasury stock, at cost
Total shareholders’ equity
Total liabilities and shareholders’ equity
See Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Revenues
Operating costs and expenses:
Lease operating expenses
Production taxes
Gathering and transportation
Depreciation, depletion and amortization
Asset retirement obligation accretion
General and administrative expenses
Derivative (gain) loss
Total costs and expenses
Operating income
Interest expense:
Incurred
Capitalized
Loss on extinguishment of debt
Interest income
Income before income tax expense
Income tax expense
Net income
Basic and diluted earnings per common share
Dividends declared per common share
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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
Balances at December 31, 2010
Cash dividends
Share-based compensation
Restricted stock issued, net of forfeitures
Balances at September 30, 2011
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion
Amortization of debt issuance costs
Cash payments on derivative settlements
Changes in operating assets and liabilities:
Oil and natural gas receivables
Joint interest and other receivables
Insurance receivables
Income taxes
Accounts payable and accrued liabilities
Net cash provided by operating activities
Investing activities:
Acquisitions of property interests in oil and natural gas properties
Investment in oil and natural gas properties and equipment
Proceeds from sales of oil and natural gas properties and equipment
Purchases of furniture, fixtures and other
Net cash used in investing activities
Financing activities:
Issuance of 8.5% Senior Notes
Repurchase of 8.25% Senior Notes
Borrowings of long-term debt – revolving bank credit facility
Repayments of long-term debt – revolving bank credit facility
Repurchase premium and debt issuance costs
Dividends to shareholders
Net cash provided (used) in financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation
Operations. W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T” or the “Company,” is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and onshore Texas. The Company is active in the acquisition, exploitation, exploration and development of oil and natural gas properties. W&T has recently diversified its operations by expanding onshore in Texas.
Interim Financial Statements.The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.
Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.
Reclassifications. Certain reclassifications have been made to the prior periods’ financial statements to conform to the current presentation.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
2. Acquisitions
On August 10, 2011, we completed the acquisition of Shell Offshore Inc.’s (“Shell”) 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas processing plant (the “Fairway Properties”). The stated purchase price was $55.0 million, subject to certain adjustments, including adjustments from an effective date of September 1, 2010 until the closing date of August 10, 2011. Taking into account such adjustments, as of September 30, 2011, the cash purchase price component was $40.0 million. The decrease of $15.0 million primarily reflects net production cash flow, partially offset by plugging and abandonment costs incurred, from the effective date of September 1, 2010 to the closing date. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first quarter of 2012. We assumed the asset retirement obligations (“ARO”) associated with the properties and plant which we have currently estimated to be $7.8 million. We are finalizing our assessment of the fair values of the assets acquired and liabilities assumed. Therefore, the purchase price allocation as described in the following table is preliminary and is subject to change. The acquisition was funded from borrowings under our revolving bank credit facility.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the preliminary purchase price allocation for the acquisition of the Fairway Properties (in thousands):
Oil and natural gas properties and equipment
Asset retirement obligations – non-current
Total cash paid
On May 11, 2011, we completed the acquisition of approximately 21,900 gross acres (21,500 net acres) of oil and gas leasehold interests in the West Texas Permian Basin (the “Permian Basin Properties”) from Opal Resources LLC and Opal Resources Operating Company LLC (“Opal”). The stated purchase price was $366.3 million, subject to certain adjustments, including adjustments from an effective date of January 1, 2011 until the closing date of May 11, 2011. Taking into account such adjustments, as of September 30, 2011, the purchase price was $397.1 million. The increase of $30.8 million primarily reflects drilling costs in excess of cash flow from the effective date of January 1, 2011 to the closing date. Although further adjustments could occur to the purchase price, no further adjustments are expected at this time. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.
The following table presents the purchase price allocation for the acquisition of the Permian Basin Properties (in thousands):
Oil and natural gas properties and equipment (1)
Long-term liability
For the three months ended September 30, 2011, the Permian Basin Properties and the Fairway Properties accounted for $21.6 million of revenue, $8.8 million of direct operating expenses, $7.2 million of depreciation, depletion, amortization and accretion (“DD&A”) and $2.0 million of income taxes, resulting in $3.6 million of net income. For the nine months ended September 30, 2011, the Permian Basin Properties and the Fairway Properties accounted for $32.8 million of revenue, $10.7 million of direct operating expenses, $9.6 million of DD&A and $4.4 million of income taxes, resulting in $8.1 million of net income. Such amounts are for the period from each respective close date to September 30, 2011. The net income attributable to these properties does not reflect certain expenses, such as general and administrative expenses and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Permian Basin Properties and the Fairway Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. Expenses associated with acquisition activities and transition activities related to these acquisitions for the three and nine months ended September 30, 2011 were $0.8 million and $1.4 million, respectively, and are included in general and administrative expenses.
Pro forma financial statements have been prepared due to the Permian Basin Properties being significant. The Fairway Properties acquisition, which was not significant, was combined with the Permian Basin Properties to disclose the effect of both acquisitions. The unaudited pro forma financial information was computed as if these two acquisitions had been completed on January 1, 2010. The historical financial information is derived from the unaudited historical consolidated financial statements of W&T and the unaudited historical statements of the sellers.
The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Permian Basin Properties and the Fairway Properties. The pro forma financial information is not
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necessarily indicative of the results of operations had the purchase occurred on January 1, 2010. If the transactions had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than the sellers, realized sales prices may have been different and costs of operating the properties may have been different. The following table presents a summary of our pro forma condensed combined statements of income for the nine months ended September 30, 2011 and 2010 (in thousands except earnings per share):
Revenue
The purchase price of both acquisitions may be subject to further adjustments. For these pro forma financial statements, we assumed the transactions were financed with borrowings from the revolving bank credit facility because the cash and cash equivalents balances for the assumed acquisition date was less than the cash and cash equivalents on hand used on the actual closing dates of the two acquisitions. Also, we assumed that the revolving bank credit facility capacity would have been increased due to the increase in reserves.
The following adjustments were made in the preparation of the condensed combined statement of income:
During 2010, we closed on two acquisition transactions. The first closed on April 30, 2010. Through our wholly-owned subsidiary, W&T Energy VI, LLC (“Energy VI”), we acquired all of Total E&P USA’s (“Total”) interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the asset retirement obligations (“ARO”) for plugging and abandonment of the acquired interests. The adjusted purchase price was $121.3 million. The properties acquired from Total (the “Matterhorn/Virgo Properties”) are producing interests and include a 100% working interest in the Matterhorn field (Mississippi Canyon block 243) and a 64% working interest in the Virgo field (Viosca Knoll blocks 822 and 823). The second closed on November 4, 2010. Through Energy VI,
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we acquired all of Shell’s interests, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the ARO for plugging and abandonment of the acquired interests. The adjusted purchase price was $134.2 million. The properties acquired from Shell (the “Tahoe/Droshky Properties”) are producing interests and include a 70% working interest in the Tahoe field (Viosca Knoll 783), 100% working interest in the Southeast Tahoe field (Viosca Knoll 784) and a 6.25% of 8/8ths overriding royalty interest in the Droshky field (Green Canyon 244).
3. Hurricane Remediation and Insurance Claims
During the third quarter of 2008, Hurricane Ike and, to a much lesser extent, Hurricane Gustav caused property damage and disruptions to our exploration and production activities. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence to be satisfied by us before we could be indemnified for losses. In the fourth quarter of 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our facilities of marginal significance) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage we incurred as a result of Hurricane Gustav was below our retention amount.
Below is a summary of remediation costs and amounts approved for payments related to Hurricanes Ike and Gustav that were included in lease operating expense (in thousands), with bracketed amounts representing credits to expense:
Incurred and reversals of accruals
Plus amounts returned to insurers
Less amounts approved for payment by insurers
Included in lease operating expense
We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. Incurred expenses included revisions of previous estimates. Amounts in 2011 include return of reimbursements that were previously received by us related to prepayments based on preliminary estimates. See Note 4 for additional information about the impact of hurricane related items on our asset retirement obligations.
Below is a reconciliation of our insurance receivables from December 31, 2010 to September 30, 2011 (in thousands):
Balance, December 31, 2010
Costs approved under our insurance policies, net
Payments received, net
Balance, September 30, 2011
At September 30, 2011 and December 31, 2010, substantially all of the amounts in insurance receivables relate to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricane Ike. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricane Ike.
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4. Asset Retirement Obligations
Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. A summary of the changes to our asset retirement obligations is as follows (in thousands):
Liabilities settled
Accretion of discount
Liabilities assumed through acquisition
Liabilities incurred
Revisions of estimated liabilities due to Hurricane Ike
Revisions of estimated liabilities – all other
Less current portion
Long-term
5. Derivative Financial Instruments
Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. We do not enter into derivative instruments for speculative trading purposes. Our derivative instruments currently consist of commodity option contracts. We are exposed to credit loss in the event of nonperformance by the counterparties; however, we do not currently anticipate any of our counterparties being unable to fulfill their contractual obligations.
We account for derivative contracts in accordance with GAAP, which requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting criteria are met at the time we enter into a derivative contract. We have elected not to designate our commodity derivatives as hedging instruments. For additional information about fair value measurements, refer to Note 7.
Commodity Derivative: During 2010, we entered into commodity option contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 31, 2012. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. As of September 30, 2011, our open commodity derivatives were as follows:
Zero Cost Collars – Oil
Effective
Date
10/1/2011
1/1/2012
4/1/2012
7/1/2012
10/1/2012
At September 30, 2011, $4.4 million and $0.8 million were included in current assets and other long-term assets, respectively, related to our commodity derivative contracts. At December 31, 2010, $9.5 million and $5.4 million were included in accrued liabilities and other long-term liabilities, respectively, related to our commodity derivative contracts. Our
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derivative gain for the three months ended September 30, 2011 includes realized losses of $0.9 million and unrealized gains of $18.2 million related to our commodity derivatives. Our derivative gain for the nine months ended September 30, 2011 includes realized losses of $9.2 million and unrealized gains of $20.0 million related to our commodity derivatives. Our derivative loss for the three months ended September 30, 2010 includes a realized gain of $1.1 million and an unrealized loss of $5.9 million related to our commodity derivatives. Our derivative gain for the nine months ended September 30, 2010 includes realized and unrealized gains of $4.3 million and $4.5 million, respectively, related to our commodity derivatives.
Interest Rate Swap: Our interest rate swap contract with a fixed interest rate of 5.21% expired in August 2010. During the three months ended September 30, 2010, we recognized an unrealized gain of $1.0 million and a realized loss of $1.0 million for this contract. During the nine months ended September 30, 2010, we recognized an unrealized gain of $4.4 million and a realized loss of $4.7 million for this contract.
6. Long-Term Debt
On June 10, 2011, we issued $600 million of our senior notes at par with an interest rate of 8.5% and maturity date of June 15, 2019 (the “8.5% Senior Notes”). Interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011. The 8.5% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries. The restrictive covenants and redemption provisions of the 8.5% Senior Notes are substantially similar to the terms of the 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”). At September 30, 2011, the outstanding balance of our 8.5% Senior Notes was $600 million and was classified at their carrying value as long-term debt. The estimated annual effective interest rate on the 8.5% Senior Notes is 8.7% which includes amortization of debt issuance costs. At September 30, 2011, the estimated fair value of the 8.5% Senior Notes was approximately $579 million. For additional details about fair value measurements, refer to Note 7.
In June and July of 2011, we used a portion of the net proceeds from the issuance of the 8.5% Senior Notes to repurchase all of our 8.25% Senior Notes, which had a principal amount of $450 million. Costs of $22.0 million related to repurchasing the 8.25% Senior Notes, which included repurchase premiums and the unamortized debt issuance costs, are included in the statement of income within the line item classification, Loss on extinguishment of debt. At December 31, 2010, the outstanding balance of our 8.25% Senior Notes was $450 million and was classified at their carrying value as long-term debt. At December 31, 2010, the estimated fair value of the 8.25% Senior Notes was approximately $441 million. For additional details about fair value measurements, refer to Note 7.
On May 5, 2011, we entered into a Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) which provides a revolving bank credit facility with an initial borrowing base of $525 million. This is a secured facility that is collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaces the prior Third Amended and Restated Credit Agreement (the “Prior Credit Agreement”), which would have expired July 23, 2012. The pricing terms and restrictive covenants of the Credit Agreement are substantially similar to the terms of the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.
Pursuant to the Credit Agreement, the initial borrowing base was adjusted due to the following two items. First, the initial borrowing base was reduced by $37.5 million due to the issuance of the 8.5% Senior Notes of $600 million. Second, the borrowing base was increased by $50 million due to the consummation of the acquisition of the Fairway Properties in August 2011. After these two transactions, our borrowing base was $537.5 million as of September 30, 2011. In October 2011, the borrowing base was re-determined by our lenders and increased to $575 million.
The Credit Agreement contains covenants that restrict, among other things, the payment of cash dividends and share repurchases of up to $60 million per year, borrowings other than from the revolving bank credit facility, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders. Letters of credit may be issued up to $90 million, provided availability under the revolving bank credit facility
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exists. We are subject to various financial covenants calculated as of the last day of each fiscal quarter including a minimum current ratio and a maximum leverage ratio as such ratios are defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2011.
Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.00% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the applicable margin ranging from 1.00% to 1.75% plus the highest of the (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, and (c) LIBOR plus 1.0%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%. The estimated annual effective interest rate was 3.7% for the nine months ended September 30, 2011 for borrowings under the Credit Agreement and the Prior Credit Agreement and includes amortization of debt issuance costs, and excludes commitment fees and other costs.
Unamortized debt issuance costs of $0.7 million related to the Prior Credit Agreement were written off and are included in the statement of income within the line item classification, Loss on extinguishment of debt.
At September 30, 2011, we had $94 million in borrowings and $0.5 million in letters of credit outstanding under the revolving bank credit facility. At December 31, 2010, we had no borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility provided by the Prior Credit Agreement.
7. Fair Value Measurements
We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. As described in Note 5, our derivative financial instruments are reported in the balance sheet at fair value and changes in fair value are recognized currently in earnings.
The fair value of our senior notes is based on quoted prices. The market for our senior notes is not an active market; therefore the fair value is classified within Level 2. The senior notes are reported in the balance sheet at their carrying value and their fair value is reported in Note 6.
8. Share-Based Compensation and Cash-Based Incentive Compensation
In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders. As allowed by the Plan, in August 2010 and August 2011, the Company granted restricted stock units (“RSUs”) to certain of its employees and in January 2011, the Company granted restricted stock to one of its employees. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the Company achieving certain predetermined performance criteria. The RSUs vest at the end of a specified deferral period. Prior to 2010, the Company granted only restricted stock to its employees. In 2011 and in prior years, restricted stock was granted to the Company’s non-employee directors under the Director Compensation Plan. In addition to share-based compensation, the Company may grant its employees cash-based incentive awards, which are a short-term component of the Plan, and are based on the Company and the employee achieving certain predetermined performance criteria.
We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that actually vest.
At September 30, 2011, there were 2,157,482 shares of common stock available for award under the Plan and 568,783 shares of common stock available for award under the Directors Compensation Plan.
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Restricted Stock: The Company currently has unvested restricted shares outstanding issued to employees and non-employee directors. Restricted shares are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period. The holders of restricted shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares.
A summary of share activity related to restricted stock for the nine months ended September 30, 2011 is as follows:
Outstanding restricted shares, December 31, 2010
Granted
Vested
Forfeited
Outstanding restricted shares, September 30, 2011
At September 30, 2011, the composition of our restricted stock awards outstanding, by year granted, was as follows:
Employees – granted in:
2011
2009
Non-employee directors – granted in:
2010
Total
Vesting is expected to occur, less any forfeitures, as follows:
The grant date fair value of restricted stock granted during the nine months ended September 30, 2011 and 2010 was $0.5 million and $0.4 million, respectively. The fair value of the shares that vested during the nine months ended September 30, 2011 and 2010 was $0.6 million and $0.1 million, respectively.
Restricted Stock Units: During 2011, the Company awarded to certain employees RSUs that are 100% contingent upon meeting a specified performance requirement for the year 2011. If the performance requirement is achieved, the RSUs awarded in 2011 will earn dividend equivalents effective January 1, 2012 at the same rate as dividends paid on our common stock. During 2010, the Company awarded to certain employees RSUs that were 100% contingent upon meeting a specified performance requirement, which was achieved in 2010. Effective January 2011, RSUs awarded in 2010 earn dividend equivalents at the same rate as dividends paid on our common stock. RSUs awarded in both years are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.
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A summary of share activity related to RSUs for the nine months ended September 30, 2011 is as follows:
Outstanding RSUs, December 31, 2010
Outstanding RSUs, September 30, 2011 (1)
During the nine months ended September 30, 2011 and 2010, the fair value of RSUs granted was $14.2 million and $12.0 million, respectively. No vesting of RSUs occurred in either time period.
Share-Based Compensation: A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit for the three and nine months ended September 30, 2011 and 2010 is as follows (in thousands):
Share-based compensation expense from:
Restricted stock
Restricted stock units
Share-based compensation tax benefit:
Tax benefit computed at the statutory rate
Cash-based Incentive Compensation: As defined by the Plan, annual cash-based incentive awards may be granted to eligible employees. These awards are performance-based awards consisting of one or more business criteria and individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.
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Incentive Compensation: A summary of incentive compensation expense for the three and nine months ended September 30, 2011 and 2010 is as follows (in thousands):
Share-based compensation expense included in:
Lease operating expense
General and administrative
Total charged to operating income
Cash-based incentive compensation included in:
Total incentive compensation charged to operating income
As of September 30, 2011, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $1.1 million and $18.2 million, respectively. Unrecognized compensation expense will be recognized through April 2014 for restricted shares and November 2013 for RSUs.
9. Income Taxes
Income tax expense of $28.8 million and $68.8 million was recorded during the three and nine months ended September 30, 2011, respectively. Our effective tax rate for the three and nine months ended September 30, 2011 was 35.3% and 35.2%, respectively, which approximated the federal and state statutory rates. Income tax expense of $0.7 million and $7.8 million was recorded during the three and nine months ended September 30, 2010, respectively. Our effective tax rate for the three and nine months ended September 30, 2010 was 2.4% and 7.4%, respectively, and primarily reflects a reduction in our valuation allowance that was recorded in prior years.
Exclusive of interest, the amount of unrecognized tax benefit recorded in other liabilities as of September 30, 2011 and December 31, 2010 was $ 3.3 million and $3.6 million, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense and these amounts were immaterial for the nine months ended September 30, 2011 and 2010. The tax years from 2008 through 2010 remain open to examination by the applicable tax jurisdictions.
10. Earnings Per Share
The following table presents the calculation of basic earnings per common share for the three and nine months ended September 30, 2011 and 2010 (in thousands, except per share amounts):
Less portion allocated to nonvested shares
Net income allocated to common shares
Weighted average common shares outstanding
Shares excluded due to being anti-dilutive (weighted-average)
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11. Dividends
During the nine months ended September 30, 2011, we paid regular cash dividends of $0.04 per common share per quarter. During the nine months ended September 30, 2010, we paid regular cash dividends of $0.04, $0.03 and $0.03 per common share per quarter, respectively. On October 31, 2011, our board of directors declared a cash dividend of $0.04 per common share, payable on December 1, 2011 to shareholders of record on November 16, 2011.
12. Contingencies
The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the Environmental Protection Agency, is conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation. The United States Attorney’s Office has recently informed us that they are continuing with their investigation with the intent to seek a criminal disposition. We are not able at this time to estimate our potential exposure, if any, related to this matter.
We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
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13. Supplemental Guarantor Information
Our payment obligations under the 8.5% Senior Notes and the Credit Agreement (see Note 6) are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, Energy VI, which includes the operations of acquisitions closed in 2010 as described in Note 2, and W&T Energy VII, LLC which does not have any active operations, (together, the “Guarantor Subsidiaries”).
The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. and other consolidated subsidiaries (“Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Consolidated subsidiaries other than the Guarantor Subsidiaries are considered “minor” under applicable accounting rules of the SEC.
Condensed Consolidating Balance Sheet as of September 30, 2011
Deferred income tax
Deferred income taxes – current portion
Common stock
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Condensed Consolidating Balance Sheet as of December 31, 2010
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Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2011
Derivative (gain)
Earnings of affiliates
Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2011
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Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2010
Derivative loss
Income tax expense (benefit)
Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2010
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Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2011
Acquisition of property interest in oil and natural gas properties
Investment in subsidiary
Investment from parent
Net cash provided by (used in) financing activities
(Decrease) in cash and cash equivalents
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Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2010
Acquisition property interests in oil and natural gas properties
Increase in cash and cash equivalents
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Forward-Looking Statements
The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act, that involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Certain factors that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2010 and may be discussed or updated from time to time in subsequent reports filed with the SEC. We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.
Overview
We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and onshore Texas. We have grown through acquisitions, exploitation and exploration and currently hold working interests in approximately 67 producing properties or fields capable of production in federal and state waters. The majority of our daily production is currently derived from offshore wells we operate. In May 2011, we closed on the acquisition of the Permian Basin Properties as described below. After completing this acquisition and acquiring other leasehold interests, we now hold working interests in over 173,000 net acres onshore in Texas. Acquiring these onshore properties has diversified our business by having both significant offshore and onshore operations.
Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil and natural gas production and the price that we receive for such production. Our production volumes for the first nine months of 2011 was comprised of approximately 47% oil, condensate and natural gas liquids and 53% natural gas, determined using the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or natural gas liquids. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent (“Mcfe”) for oil and natural gas liquids may differ significantly from the price per Mcf for natural gas. For example, for the first nine months of 2011, our average realized price for oil and NGLs on a Mcfe basis was $15.51 compared to $4.34 per Mcf for natural gas. For the first nine months of 2011, our combined total production of oil, condensate, natural gas liquids and natural gas was approximately 14.9% higher on a Mcfe basis than during the same period in 2010.
During August 2011, we completed the acquisition of Shell’s 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas processing plant, with an effective date of September 1, 2010. Estimates of proved reserves as of June 30, 2011 were 54.5 billion cubic feet equivalent (“Bcfe”). The adjusted purchase price was comprised of $40.0 million of cash, which was funded through borrowings under our revolving bank credit facility, and we assumed the ARO associated with the properties and plant which we have currently estimated to be $7.8 million. We are finalizing our assessment of the fair values of the assets acquired and liabilities assumed. Therefore, the purchase price allocation is preliminary and is subject to change.
During May 2011, we completed the acquisition of approximately 21,900 gross acres (21,500 net acres) of oil and gas leasehold interests in the Permian Basin Properties from Opal. Including adjustments from an effective date of January 1, 2011, the adjusted purchase price was $397.1 million. Although further adjustments could occur to the purchase price, no further adjustments are expected at this time. We acquired estimated proved reserves of approximately 30 million barrels of oil equivalent (182 Bcfe) (using a 6 to 1 Mcf to barrel equivalency) as of December 31, 2010, comprised of approximately 91% oil and natural gas liquids and which are approximately 78% proved undeveloped. Capital expenditures associated with planned development activities for these properties from the closing date of May 11, 2011 to December 31, 2011 are currently estimated to be between $70 million and $80 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.
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During 2010, we closed on two major acquisitions. In April 2010, we acquired two deepwater properties from Total and in November 2010, we acquired three deepwater fields from Shell. These transactions are described in Financial Statements - Note 2 – Acquisitions under Part I, Item 1 of this Form 10-Q.
The third-party pipeline used by our Main Pass 108, 98 and 180 fields, which had been offline since June 2010, became operational on March 31, 2011. In the second quarter of 2011, we continued to increase production in this area. In September 2011, these fields produced approximately 44 MMcfe per day, made up of 33,083 Mcf of natural gas and 1,834 barrels of oil/NGLs per day.
Prices for oil have continued to be volatile in 2011. For the nine months ended September 30, 2011, our average realized sales price for oil and NGLs (unhedged) increased significantly over the comparable period in 2010. The majority of our oil production is priced using the posted spot price for West Texas Intermediate (“WTI”) as a base price plus a premium depending on the type of crude oil. WTI is frequently used to value domestically produced crude oil. Our offshore oil production, which is comprised of various crudes including Light Louisiana Sweet, Heavy Louisiana Sweet and Poseidon, started selling at a significant premium relative to WTI earlier this year. In 2011 compared to 2010, our realized oil sales price increased 33.5%, compared to a 22.8% increase in the posted spot price for WTI. Our crudes have better reflected the international oil market prices, as measured using Brent crude, which increased 44.6% for this time frame. Oil prices continue to be impacted by market fundamentals such as supply and demand and also by political events and disruptions throughout the world, including events in Greece, Japan, Africa and the Middle East. Long-term forecasts for oil demand, and therefore global oil prices, continue to be favorable in several key growing markets, specifically China and India.
The premiums received on our offshore oil production have been up to $24.00 per barrel for the nine months ended September 30, 2011. In comparison, the average premium spread between Light Louisiana Sweet crude and WTI crude was approximately $3.00 per barrel during 2010. We may continue to experience higher premiums to WTI crude in our future sales of offshore crude oil until such time as the causative factors are resolved. We cannot predict with any certainty how long such pricing conditions will last.
Natural gas prices are much more affected by domestic issues, such as supply, local demand issues and domestic economic conditions. The Henry Hub posted spot price for natural gas was $4.22 per MMBtu for the nine months ended September 30, 2011 representing a decrease of 7.5% from $4.56 per MMBtu for the same period in 2010. The price for natural gas in the nine months ended September 30, 2011 ranged from a low of $3.68 per MMBtu to a high of $4.92 per MMBtu and the range in the same period of 2010 was from $3.72 to $7.51 per MMBtu. During the nine months ended September 30, 2011, the average realized sales price of our natural gas (unhedged) decreased 8.6% from the comparable period of 2010. We are expecting continued weakness in natural gas prices unless demand for natural gas increases as a result of a strong economic recovery, drilling activity subsides dramatically or forced production shut-ins occur. There is also a risk that, as a result of successful exploration and development activities in the shale areas coupled with the availability of increasing amounts of liquefied natural gas, increased supplies of natural gas will offset or mitigate the impact of any natural gas shut-ins or demand increases resulting from improved economic conditions. According to industry sources, the rig count for horizontal drilling rigs, used primarily in the shale formation areas such as Louisiana, Arkansas, Texas, North Dakota and Pennsylvania, has reached or exceeded record levels. Further, such sources indicate that onshore natural gas producers have continued to drill in attempts to yield production sufficient to preserve existing leases. Seasonal weather conditions also impact the demand for and price of natural gas.
Revenue from our offshore production is highly dependent on pipelines owned by others to access markets for our products. To the extent that the price such pipelines charge us increases, our revenues from the sales of our products would go down or transportation costs would increase, the result of either would be a reduction in operating income. Certain pipelines have filed tariffs to increase the amounts they charge us and we believe that we have limited alternatives to use other pipelines.
Should prices decline for oil and natural gas in the future, it would negatively impact our future oil and natural gas revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, create issues with financial ratio compliance, and result in a reduction of the borrowing base associated with our credit agreement, depending on the severity of such declines. If those were to occur and were significant, it may limit the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry.
In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) issued a
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series of “Notices to Lessees” (“NTLs”), and other significant changes in regulations. In addition, the BOEMRE implemented a six-month moratorium on drilling activities which began in May 2010. There also continue to be many proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and spill. After the moratorium ended in 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, deepwater drilling permits have been issued, albeit at the slower and more measured pace than before the Deepwater Horizon event. The most significant regulatory changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. The permitting process is also slow and inconsistent for shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness. We have not experienced delays in obtaining permits related to our onshore operations.
In October 2011, the BOEMRE was split into three separate entities: the Office of National Resources Revenue (“ONRR”), which assumed the functions of the Minerals Revenue Management Program; the Bureau of Ocean Energy Management (“BOEM”), which is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way; and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for enforcement of safety and environmental regulations.
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Results of Operations
The following table sets forth selected financial data for the periods indicated (all values are net to our interest unless indicated otherwise):
Financial:
Revenues:
Oil and NGLs
Natural gas
Other
Total revenues
Interest expense, net of amounts capitalized
Loss on extinguishment of debt (1)
NM = percentage change not meaningful
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The following table sets forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):
Operating:
Net sales:
Natural gas (Bcf)
Oil and NGLs (MMBbls)
Total natural gas and oil (Bcfe) (1)
Total natural gas and oil (MMBoe) (1)
Average daily equivalent sales (MMcfe/d)
Average realized sales prices (Unhedged):
Natural gas ($/Mcf)
Oil and NGLs($/Bbl)
Natural gas equivalent ($/Mcfe)
Average realized sales prices (Hedged):
Oil and NGLs ($/Bbl)
Average per Mcfe ($/Mcfe):
Production costs
Total number of offshore wells drilled (gross)
Total number of onshore wells drilled (gross)
Total number of offshore productive wells drilled (gross)
Total number of onshore productive wells drilled (gross)
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Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010
Revenues. Total revenues increased $75.8 million, or 44.7%, to $245.4 million for the three months ended September 30, 2011, as compared to the same period in 2010. Oil and NGL revenues increased $57.6 million, natural gas revenues increased $13.9 million and other revenues increased $4.3 million. The oil and NGL revenue increase was attributable to a 32.9% increase in the average realized sales price to $90.84 per barrel for the three months ended September 30, 2011 from $68.35 per barrel for the same period in 2010, combined with an increase of 11.1% in sales volumes. The sales volume increase for oil and NGL is primarily attributable to increases associated with properties acquired in 2011 and 2010. The increase in natural gas revenue resulted from a 34.9% increase in sales volumes, partially offset by a 4.5% decrease in the average realized natural gas sales price. For the three months ended September 30, 2011, the natural gas average realized sales price was $4.27 per Mcf compared to $4.47 per Mcf for the same period in 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Other revenue changed primarily due to a disallowance of $4.7 million by the BOEMRE of royalty relief for transportation of deepwater production through our subsea pipeline system that was recorded in the three months ended September 30, 2010.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $24.5 million to $58.9 million for the three months ended September 30, 2011 compared to the same period in 2010. On a per Mcfe basis, lease operating expenses increased to $2.22 per Mcfe during the three months ended September 30, 2011 compared to $1.59 per Mcfe during the same period in 2010. On a component basis, base lease operating expenses, hurricane remediation costs net of insurance claims, workover costs, insurance premiums and facility expenses increased $10.1 million, $6.6 million, $4.3 million, $2.1 million and $1.4 million, respectively. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties, increased processing fees associated with our Daniel Boone field production and expenses billed to a third party in 2010 related to a divestiture that did not occur in 2011. Hurricane remediation costs net of insurance claims increased due to higher reimbursements received in the 2010 period. Workover costs increased primarily due to work performed at our new Permian Basin Properties. The increase in insurance premiums resulted primarily from higher premiums on our insurance policies covering well control and hurricane damage which incorporates additional acquired properties. The increase in facility expenses is primarily attributable to work performed at the Fairway Properties.
Production taxes. Production taxes increased to $1.1 million for the three months ended September 30, 2011 compared to $0.3 million in the prior year primarily due to the Permian Basin Properties operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.
Gathering and transportation costs. Gathering and transportation costs were basically flat for the quarter compared to the prior year.
Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.19 per Mcfe for the three months ended September 30, 2011 from $3.48 per Mcfe in the prior year. On a nominal basis, DD&A increased to $84.5 million for the three months ended September, 2011 from $75.3 million in the prior year. The decrease to DD&A on a per Mcfe basis was primarily due to increases in proved reserves while DD&A on a nominal basis increased due to higher production volumes.
General and administrative expenses (“G&A”). G&A expenses increased to $18.1 million for the three months ended September 30, 2011 from $13.4 million for the prior year primarily due to higher incentive compensation as a result of improved financial and operational performance, and expanded activities onshore and offshore. In addition, costs associated with acquisition activities, transition service fees paid to the sellers of the acquired properties, litigation settlements and accruals and increased professional fees resulted in higher G&A. On a per Mcfe basis, G&A was $0.68 per Mcfe for the three months ended September 30, 2011, compared to $0.62 per Mcfe for the same period in 2010.
Derivative (gain)/loss. For the three months ended September 30, 2011, our derivative gain of $17.3 million related to a change in the fair value of our commodity derivatives as a result of changes in crude oil prices. For the comparable period of 2010, our derivative loss of $4.8 million related to a loss from our commodity derivatives as a result of changes in crude oil and natural gas prices. For additional details about our derivatives, refer to Financial Statements – Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.
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Interest expense. Interest expense incurred increased to $14.7 million for the three months ended September 30, 2011 from $10.5 million for the same period in 2010. During 2011, the amounts outstanding for our senior notes increased to $600 million from $450 million and the senior note annual interest rate increased to 8.5% from 8.25%. In addition, average borrowings on our revolving bank credit facility increased. During the three months ended September 30 of 2011 and 2010, $3.2 million and $1.3 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties which increased with the Permian Basin Properties acquisition. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.
Loss on extinguishment of debt. The loss on extinguishment of debt of $2.0 million was attributable to the redemption of the remaining outstanding balance of $43.9 million of the 8.25% Senior Notes. The amount expensed included the call premium paid to the remaining note holders pursuant to the terms of the note and to write off the balance of unamortized debt issuance costs related to the 8.25% Senior Notes. For additional information about our long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.
Income tax expense. Income tax expense increased to $28.8 million for the three months ended September 30, 2011 compared to $0.7 million for the same period of 2010. Our effective tax rate for the three months ended September 30, 2011 was 35.3%, which approximates the federal and state statutory rates. Our effective tax rate for the three months ended September 30, 2010 was 2.4% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.
Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010
Revenues. Total revenues increased $190.3 million, or 36.7%, to $709.1 million for the nine months ended September 30, 2011, as compared to the same period in 2010. Oil and NGL revenues increased $170.8 million, natural gas revenues increased $14.7 million and other revenues increased $4.8 million. The oil and NGL revenue increase was attributable to a 33.5% increase in the average realized sales price to $93.08 per barrel for the nine months ended September 30, 2011 from $69.73 per barrel for the same period in 2010, combined with an increase of 9.4% in sales volumes. The sales volume increase for oil and NGL is primarily attributable to increases associated with properties acquired in 2011 and 2010. The increase in natural gas revenue resulted from a 19.8% increase in sales volumes, partially offset by an 8.6% decrease in the average realized natural gas sales price to $4.34 per Mcf for the nine months ended September 30, 2011 from $4.75 per Mcf for the same period in 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Other revenue changed primarily due to a disallowance of $4.7 million by the BOEMRE of royalty relief for transportation of deepwater production through our subsea pipeline system that was recorded in the three months ended September 30, 2010.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $37.7 million to $159.9 million in the nine months ended September 30, 2011 compared to the same period in 2010. On a per Mcfe basis, lease operating expenses increased to $2.16 per Mcfe during the nine months ended September 30, 2011 compared to $1.90 per Mcfe during the same period of 2010. On a component basis, base lease operating expenses, hurricane remediation costs net of insurance claims, facility expenses and workover costs increased $15.3 million, $11.5 million, $11.0 million, and $2.3 million, respectively. As a partial offset, insurance premiums decreased $2.5 million. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties, increased processing fees associated with our Daniel Boone field production and expenses billed to a third party in 2010 related to a divestiture that did not occur in 2011. Hurricane remediation costs net of insurance claims increased primarily due to higher reimbursements received in the 2010 period. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platforms. Workover costs increased due to work performed at our new Permian Basin Properties and expenses at the Main Pass 108 field, partially offset by projects in 2010 that did not occur in 2011. The decrease in insurance premiums resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage that cover the policy period June 1, 2010 to June 1, 2011. Our premiums increased effective with the June 1, 2011 renewal.
Production taxes. Production taxes increased to $2.2 million for the nine months ended September 30, 2011 compared to $0.8 million in the same period of 2010 primarily due to the Permian Basin Properties operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.
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Gathering and transportation costs. Gathering and transportation costs were basically flat for the nine months ended September 30, 2011 compared to the same period in 2010.
Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.27 per Mcfe for the nine months ended September 30, 2011 from $3.42 per Mcfe for the same period in 2010. On a nominal basis, DD&A increased to $241.9 million for the nine months ended September 30, 2011 from $220.5 million in the same period in 2010. The decrease to DD&A on a per Mcfe basis was primarily due to increases in proved reserves while DD&A on a nominal basis increased due to higher production volumes.
General and administrative expenses. General and administrative expenses increased to $54.2 million for the nine months ended September 30, 2011 from $38.1 million for the same period in 2010, primarily due to higher incentive compensation as a result of improved financial and operational performance, and expanded activities onshore and offshore. In addition, costs associated with acquisition activities, surety premiums, transition service fees paid to the sellers of the acquired properties, and litigation settlements and accruals resulted in higher G&A. Also, there were administration fees earned in 2010 related to an asset disposition and no such fees were earned in 2011. On a per Mcfe basis, G&A was $0.73 per Mcfe for the nine months ended September 30, 2011, compared to $0.59 per Mcfe for the same period in 2010.
Derivative (gain)/loss. For the nine months ended September 30, 2011, our derivative gain of $10.8 million related entirely to a change in the fair value of our commodity derivatives as a result of the changes in crude oil prices. For the nine months ended September 30, 2010, our derivative gain of $8.5 million related to a gain from our commodity derivatives of $8.8 million and a loss of $0.3 million related to our interest rate swap. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 5 – Derivative Financial Instrumentsunder Part I, Item 1 of this Form 10-Q.
Interest expense. Interest expense incurred increased to $36.9 million for the nine months ended September 30, 2011 from $32.3 million for the same period in 2010. During 2011, the amounts outstanding for our senior notes increased to $600 million from $450 million and the senior note annual interest rate increased to 8.5% from 8.25%. During the nine months ended September 30 of 2011 and 2010, $6.7 million and $4.1 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties which increased with the Permian Basin Properties acquisition. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.
Loss on extinguishment of debt. The loss on extinguishment of debt of $22.7 million was attributable primarily to the repurchase of the $450 million outstanding of our 8.25% Senior Notes. The repurchase of the 8.25% Senior Notes was funded with a portion of the proceeds from the issuance of the 8.5% Senior Notes. The call premiums, unamortized debt issuance costs and other related expenses totaled $22.0 million. In addition, the previous revolving bank credit facility was replaced resulting in the write off of unamortized debt issuance costs of $0.7 million. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.
Income tax expense. Income tax expense increased to $68.8 million for the nine months ended September 30, 2011 compared to $7.8 million for the same period of 2010. Our effective tax rate for the nine months ended September 30, 2011 was 35.2%, which approximates the federal and state statutory rates. Our effective tax rate for the nine months ended September 30, 2010 was 7.4% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings and make related interest payments. We have funded our capital expenditures, including acquisitions, with cash on hand, cash provided by operations, securities offerings and bank borrowings. These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.
Cash flow and working capital. Net cash provided by operating activities for the nine months ended September 30, 2011 was $396.1 million, compared to $392.9 million for the same period in 2010. The 2010 period included income tax refunds of $99.8 million primarily related to the Worker, Homeowner and Business Assistance Act of 2009 that allowed us to carry back losses to previously closed years, while the 2011 period included tax payments of $25.3 million. Otherwise, cash flow from operating activities increased $128 million due to substantially improved operating results. Our combined average realized sales price was 17.9% higher than the comparable 2010 period and our combined total production of oil, NGLs and natural gas during the nine months ended September 30, 2011 was 14.9% higher than the comparable 2010 period.
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Net cash used in investing activities during the nine months ended September 30, 2011 and 2010 were $620.1 million and $243.1 million, respectively, which primarily represents our investments in oil and natural gas properties. Major acquisitions consisted of the cash portion of the Permian Basin Properties ($394.6 million) and the Fairway Properties ($40.0 million) purchased in 2011 and the Matterhorn/Virgo Properties ($116.6 million) purchased in 2010. In addition, investments in other oil and natural gas properties and equipment were $185.2 million in the nine months ended September 30, 2011 compared to $127.4 million in the nine months ended September 30, 2010 with the increase primarily related to the Permian Basin Properties. There were minimal proceeds from sales of assets in the nine months ended September 30, 2011 and proceeds from asset sales were $1.3 million for the same period in 2010.
Net cash provided by financing activities was $203.1 million during the nine months ended September 30, 2011. Funds were provided through net borrowings on the revolving bank credit facility of $94 million and issuance of $600 million of 8.5% Senior Notes and partially offset by the repurchase of $450 million of the 8.25% Senior Notes, repurchase premium and debt issuance costs of $32.0 million and the payment of dividends of $8.9 million. See Financial Statements – Note 6 – Long-Term Debtunder Part I, Item 1 of this Form 10-Q for additional information on the senior notes transactions. Net cash used in financing activities during the nine months ended September 30, 2010 was $7.5 million which reflects dividend payments during the period.
At September 30, 2011, we had a cash balance of $7.7 million and $443.0 million of undrawn capacity available under the revolving bank credit facility which had a borrowing base of $537.5 million as of this date.
Credit agreement and long-term debt. At September 30, 2011, there was $94 million outstanding under our revolving bank credit facility compared to zero at December 31, 2010. At September 30, 2011, there was $600 million of our 8.5% Senior Notes outstanding and at December 31, 2010 there was $450 million outstanding of our 8.25% Senior Notes. We believe that cash provided by operations, borrowings available under our revolving bank credit facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements.
On May 5, 2011, we entered into the Credit Agreement which provides a revolving bank credit facility with an initial borrowing base of $525 million collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaced the Prior Credit Agreement, which would have expired July 23, 2012. Fees and transactions costs related to the Credit Agreement were approximately $5.9 million. The terms of the Credit Agreement are substantially similar to the terms of the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base redetermination set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the size of our revolving bank credit facility. The borrowing base was re-determined in October 2011 and was increased to $575 million.
The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2011. During the nine months ended September 30, 2011, borrowings outstanding on the revolving bank credit facility increased to $300 million primarily to fund the acquisition of the Permian Basin Properties, which also included funding from cash on hand. These borrowings were subsequently reduced to $94 million as of September 30, 2011, primarily by utilizing funds received from the senior note transactions described below and net cash from operations, partially offset by capital expenditures. Letters of credit outstanding as of September 30, 2011 were $0.5 million.
On June 10, 2011, we issued $600 million of 8.5% Senior Notes and used a portion of the net proceeds to repurchase the $450 million outstanding of our 8.25% Senior Notes. The net cash provided by these senior notes transactions, which includes initial purchaser fees, redemption premiums and other transactions costs, was $123.9 million. These transactions extended the maturity date of our long-term debt and we used the net proceeds to pay down a portion of amounts outstanding under the revolving bank credit facility. The 8.5% Senior Notes mature on June 15, 2019. Interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011. For additional information about our credit agreement and long-term debt, refer toFinancial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.
Derivatives. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. As of September 30, 2011, our outstanding derivative instruments consisted of commodity option contracts
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relating to approximately 0.4 MMBbls and 1.1 MMBbls of our anticipated oil production for the balance of 2011 and the full year of 2012, respectively. For additional details about our derivatives, refer to Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.
Hurricane Remediation and Insurance Claims. During the third quarter of 2008, Hurricane Ike, and to a much lesser extent Hurricane Gustav, caused property damage and disruptions to our exploration and production activities. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our marginal facilities) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence. In 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. The damage we incurred as a result of Hurricane Gustav was below our retention amount.
We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis.
In the nine months ended September 30, 2011 and 2010, we received cash of $18.9 million and $46.9 million, respectively, from our insurance carrier related to Hurricane Ike claims. We have recorded $1.7 million receivables as of September 30, 2011 for claims submitted and approved for payment as of this date. As of September 30, 2011, we have recorded in ARO an estimate of $57.1 million for additional costs to be incurred related to Hurricane Ike and we estimate that this work will be completed by the end of 2013. We expect to receive reimbursement for a portion of these costs from our insurance carrier once the costs are incurred, claims are processed and payments are approved, but cannot estimate the amount of reimbursement to be received at this time. Should necessary expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied by our insurance carrier for other reasons, we expect that our available cash on hand, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet these future cash needs.
For a discussion of our hurricane remediation costs related to lease operating expenses incurred during the nine months ended September 30, 2011 and 2010, refer to Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part I, Item 1 of this Form 10-Q. Lease operating expenses will be offset in future periods to the extent that these costs incurred are approved for payment under our insurance policies.
We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico. The current policy limits for well control and hurricane damage (defined as named windstorm in our policies) are up to $100 million and $120 million, respectively, and the policies are effective until June 1, 2012. We carry an additional $100 million of well control coverage effective until June 1, 2012 on certain wells at our Mahogany, Matterhorn, Virgo, Tahoe and SE Tahoe fields. A retention amount of $5 million for well control events and $37.5 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Certain properties we have deemed as non-core are not covered for hurricane damage; however, properties representing approximately 96% of our present value of estimated future net revenues discounted at 10% (“PV-10”) at December 31, 2010 are covered under our insurance policies for hurricane damage. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.
Our general and excess liability policy, which is effective until May 1, 2012, provides for $250 million of liability coverage for bodily injury and property damage, including liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility (“OSFR”) requirement under the Oil Pollution Act (“OPA”), we are required to evidence $150 million of financial responsibility to the BSEE. We qualify to self-insure for $35 million of this amount and the remaining $115 million is covered by insurance. We may only collect proceeds under this OSFR policy after our well control, hurricane damage and excess liability policies have been exhausted.
The premiums for the above policies were $30 million compared to $22 million for the policies that expired in May and June of 2011. Although we have not been informed otherwise, in the future, our insurers may not continue to offer this type and level of coverage to us, or our costs may increase substantially as a result of increased premiums and the increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have a claim, the insurance companies will not pay our claim. However, we are not
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aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims. We do not carry business interruption insurance.
Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for acquisitions, exploration, development and other leasehold costs:
Acquisition of Permian Basin Properties
Acquisition of Fairway Properties
Acquisition of Matterhorn/Virgo Properties
Exploration (1)
Development (1)
Seismic, capitalized interest, other leasehold costs
Acquisitions and investments in oil and gas property/equipment
The following table presents our exploration and development capital expenditures by geography:
Conventional shelf
Deepwater
Deep shelf
Onshore
Exploration and development capital expenditures
Our 2011 capital expenditures were financed by cash flow from operating activities, cash on hand and additional borrowings. Our 2010 capital expenditures were financed by cash flow from operating activities and cash on hand.
During the nine months ended September 20, 2011, we participated in the drilling of 31 onshore wells and 4 offshore wells, all except one of which were successful. Of the successful onshore wells, nine onshore wells were exploration wells and 21 onshore wells were development wells, with one being in South Texas, one in East Texas and the others in the Permian Basin of West Texas. One onshore well in South Texas was unsuccessful. All of the offshore wells were successful and were drilled on the conventional shelf. One offshore well was an exploration well and the other three were development wells.
During the nine months ended September 30, 2010, we participated in the drilling of five offshore wells, four of which were successful. Of these successful wells, all four were on the conventional shelf with three being exploration wells and one a development well. We also participated in the drilling of two onshore wells, both of which were unsuccessful.
Our onshore acreage has increased during the nine months ended September 30, 2011 from approximately 5,000 net acres to approximately 173,000 net acres with the increases primarily from acreage acquired in East Texas and from the Permian Basin Properties acquisition.
Our total capital expenditure budget for 2011 is $310 million, which excludes acquisitions. Although there has been considerable shuffling of wells and focus areas since the original budget was prepared, we believe that the $310 million continues to be a reasonable estimate of our capital expenditures, excluding acquisitions, for 2011. The budget includes amounts for drilling and evaluation of wells, well completions, facilities capital, recompletions, seismic and leasehold items. Our 2011 capital budget is subject to change as conditions warrant and our budget is sufficiently flexible such that most any change can be made without incurring any contractor breakage or commitment fees.
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Capital expenditures associated with development activities for the Permian Basin Properties acquired in May 2011 from the closing date of May 11, 2011 to December 31, 2011 are currently estimated between $70 million and $80 million and are included in the total annual capital expenditure budget described above. For additional information on this acquisition, please see Financial Statements - Note 2 – Acquisitions under Part I, Item 1 of this Form 10-Q.
We intend to continue to pursue acquisitions and joint venture opportunities in the future. We are constantly evaluating attractive new opportunities and expect to continue to complement our drilling and exploitation projects with acquisitions providing acceptable rates of return. We anticipate funding our 2011 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving bank credit facility, issuance of our 8.5% Senior Notes, additional long-term debt, or other financings, if and when funds are needed.
Income taxes. During the nine months ended September 30, 2011, we made tax payments of $25.3 million. For the nine months ended September 30, 2010, we received a refund of approximately $99.8 million and made a payment of $4.0 million. For the year 2011 based on current projections, we expect substantially all of our income taxes will be deferred and only minimal payments are expected primarily related to alternative minimum tax. Income tax payments are affected by many factors, with the primary factors being operating results, drilling activity, and plugging and abandonment activity. To the extent that there are variances to our projections, our estimates of income tax payments could increase in the fourth quarter of 2011 or the first quarter of 2012 related to the 2011 tax year.
Dividends. During the nine months ended September 30, 2011, we paid regular cash dividends of $0.04 per common share per quarter. During the nine months ended September 30, 2010, we paid regular cash dividends of $0.04, $0.03 and $0.03 per common share per quarter, respectively. On October 31, 2011, our board of directors declared a cash dividend of $0.04 per common share, payable on December 1, 2011 to shareholders of record on November 16, 2011.
Contractual obligations. Major changes in contractual obligations from those disclosed in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 are as follows: 1) asset retirement obligations as disclosed in Financial Statements - Note 4 – Asset Retirement Obligations under Part I, Item 1 of this Form 10-Q; 2) additions of principal and interest related to our 8.5% Senior Notes and reductions of principal and interest related to our 8.25% Senior Notes principal as disclosed in Financial Statements - Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q; 3) drilling rig contracts with terms of six months or less have commitments of $16.5 million as of September 30, 2011; 4) additional operating lease of $12.3 million for an 11 year office lease; and 5) derivative contracts as disclosed in Financial Statements - Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.
Critical Accounting Policies
Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2010. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Form 10-Q.
Recent Accounting Pronouncements
None.
Information about market risks for the nine months ended September 30, 2011 did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2010. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2010.
Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil and natural gas, which fluctuate widely. In the past, oil and natural gas price declines and volatility have negatively affected our revenues, net cash provided by operating activities and profitability. We have entered into a limited number of commodity option contracts to help manage a portion of our exposure to commodity price risk from sales of oil during the fiscal years ending December 31, 2011 and 2012. As of September 30, 2011 our derivative instruments outstanding consisted of commodity option contracts relating to approximately 0.4 MMBbls and 1.1 MMBbls of our anticipated production for the balance of 2011 and year 2012, respectively. While these contracts are intended to reduce the effects of volatile oil prices, they may also limit future income if oil prices were to rise substantially over the price established by the
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hedge. Currently, we do not have any commodity option contracts for natural gas. We do not enter into derivative instruments for speculative trading purposes. For additional details about our commodity derivatives, refer to Financial Statements – Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.
Interest Rate Risk. We currently do not have any derivative instruments related to interest rates. As of September 30, 2011, we had $94 million of floating rate debt outstanding. Borrowings on our revolving bank credit facility are subject to interest rate risk.
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of September 30, 2011 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
During the quarter ended September 30, 2011, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Please see the risk factor entitled “The Company is responding to a federal grand jury investigation that could result in penalties and additional operating restrictions” under Part II, Item 1A, Risk Factors of this Form 10-Q, for information concerning governmental proceedings.
Carefully consider the risk factors set forth below, as well as the risk factors included under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, together with all of the other information included in this document, in the Company’s Annual Report on Form 10-K and in the Company’s other public filings, press releases and discussions with Company management.
The Company is responding to a federal grand jury investigation that could result in penalties and additional operating restrictions.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations. We utilize hydraulic fracturing techniques in connection with developing our recently acquired Permian Basin Properties and other properties. The process involves the injection of water, sand and small amounts of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The federal Environmental Protection Agency (“EPA”), however, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act’s (the “SDWA”) Underground Injection Control Program and has begun the process of
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drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel fuel. In addition, a number of federal agencies are analyzing a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Legislation also has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including states in which we operate. For example, on June 17, 2011, Texas signed into law a bill that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and the public. The disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based upon allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In addition, disclosure of proprietary chemical formulas or disclosure of any chemicals used in such formulas to the public could diminish the value of those formulas and could result in competitive harm to us. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.
On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development activities may be unsuccessful for many reasons, including adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages, geological issues and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not assure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.
Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, involve a variety of operating risks, including:
fires;
explosions;
blow-outs and surface cratering;
uncontrollable flows of natural gas, oil and formation water;
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natural disasters, such as tropical storms, hurricanes and other adverse weather conditions;
inability to obtain insurance at reasonable rates;
failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;
pipe, cement, subsea well or pipeline failures;
casing collapses or failures;
mechanical difficulties, such as lost or stuck oil field drilling and service tools;
abnormally pressured formations or rock compaction; and
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering naturally occurring radioactive materials, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
clean-up responsibilities;
regulatory investigation and penalties;
suspension of our operations;
repairs required to resume operations; and
loss of reserves.
Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate funds available for exploration, exploitation and acquisitions or result in the loss of property and equipment.
None
The exhibits to this report are listed in the Exhibit Index.
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Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 3, 2011.
/s/ JOHN D. GIBBONS
Senior Vice President, Chief Financial Officer
and Chief Accounting Officer, duly authorized to
sign on behalf of the registrant
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ExhibitNumber
Description
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