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UNITED STATESSECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
Form 10-Q
Commission File Number: 001-35380
Laredo Petroleum Holdings, Inc. (Exact Name of Registrant as Specified in Its Charter)
(918) 513-4570 (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 ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
Number of shares of registrant's common stock outstanding as of August 7, 2012: 128,231,994
TABLE OF CONTENTS
Cautionary Statement Regarding Forward-Looking Statements
Part I
Item 1.
Consolidated Financial Statements (Unaudited)
Consolidated balance sheets as of June 30, 2012 and December 31, 2011
Consolidated statements of operations for the three and six months ended June 30, 2012 and 2011
Consolidated statement of stockholders' equity for the six months ended June 30, 2012
Consolidated statements of cash flows for the six months ended June 30, 2012 and 2011
Condensed notes to the consolidated financial statements
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
Legal Proceedings
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Defaults Upon Senior Securities
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
Signatures
Exhibit Index
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:
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These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Quarterly Report on Form 10-Q, under "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 and under "Part II, Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.
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PART I
Item 1. Consolidated Financial Statements (Unaudited)
Laredo Petroleum Holdings, Inc. Consolidated balance sheets (in thousands, except share data) (Unaudited)
Assets
Current assets:
Cash and cash equivalents
Accounts receivable, net
Derivative financial instruments
Deferred income taxes
Other current assets
Total current assets
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties
Unproved properties not being amortized
Pipeline and gas gathering assets
Other fixed assets
Less accumulated depreciation, depletion, amortization and impairment
Net property and equipment
Deferred loan costs, net
Other assets, net
Total assets
Liabilities and stockholders' equity
Current liabilities:
Accounts payable
Undistributed revenue and royalties
Accrued capital expenditures
Accrued compensation and benefits
Accrued interest payable
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations
Other noncurrent liabilities
Total liabilities
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at June 30, 2012 and December 31, 2011
Common stock, $0.01 par value, 450,000,000 shares authorized, and 128,296,239 and 127,617,391 issued, net of treasury, at June 30, 2012 and December 31, 2011, respectively
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost, 7,609 common shares at June 30, 2012 and December 31, 2011
Total stockholders' equity
Total liabilities and stockholders' equity
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Laredo Petroleum Holdings, Inc. Consolidated statements of operations (in thousands, except per share data) (Unaudited)
Revenues:
Oil and natural gas sales
Natural gas transportation and treating
Total revenues
Costs and expenses:
Lease operating expenses
Production and ad valorem taxes
Drilling and production
General and administrative (including non-cash stock-based compensation of $2,588 and $557 for the three months ended June 30, 2012 and 2011, respectively, and $4,835 and $876 for the six months ended June 30, 2012 and 2011, respectively)
Accretion of asset retirement obligations
Depreciation, depletion and amortization
Impairment expense
Total costs and expenses
Operating income
Non-operating income (expense):
Realized and unrealized gain (loss):
Commodity derivative financial instruments, net
Interest rate derivatives, net
Interest expense
Interest and other income
Write-off of deferred loan costs
Loss on disposal of assets
Non-operating income (expense), net
Income before income taxes
Income tax expense:
Deferred
Total income tax expense
Net income
Net income per common share:
Basic
Diluted
Weighted average common shares outstanding:
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Laredo Petroleum Holdings, Inc. Consolidated statement of stockholders' equity (in thousands) (Unaudited)
Balance, December 31, 2011
Restricted stock awards
Restricted stock forfeitures
Stock-based compensation
Balance, June 30, 2012
The accompanying notes are an integral part of this unaudited consolidated financial statement.
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Laredo Petroleum Holdings, Inc. Consolidated statements of cash flows (in thousands) (Unaudited)
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense
Non-cash stock-based compensation
Unrealized (gain) loss on derivative financial instruments, net
Premiums paid for derivative financial instruments
Amortization of premiums paid for derivative financial instruments
Amortization of deferred loan costs
Amortization of October 2011 Notes premium
Amortization of other assets
(Increase) decrease in accounts receivable
(Increase) decrease in other current assets
Increase (decrease) in accounts payable
Increase (decrease) in undistributed revenues and royalties
Increase (decrease) in accrued compensation and benefits
Increase (decrease) in other accrued liabilities
Increase (decrease) in other noncurrent liabilities
Net cash provided by operating activities
Cash flows from investing activities:
Capital expenditures:
Oil and natural gas properties
Proceeds from other fixed asset disposals
Net cash used in investing activities
Cash flows from financing activities:
Borrowings on revolving credit facilities
Payments on revolving credit facilities
Payments on term loan
Issuance of 2019 Notes
Issuance of 2022 Notes
Payments for loan costs
Net cash provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosure of cash flow information:
Cash paid during the period:
Interest, net of $505 and zero, respectively, of capitalized interest for the six months ended June 30, 2012 and 2011, respectively
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Laredo Petroleum Holdings, Inc. Condensed notes to the consolidated financial statements (Unaudited)
A—Organization
Laredo Petroleum Holdings, Inc. ("Laredo Holdings") together with its subsidiaries, is an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties in the Permian and Mid-Continent regions of the United States. Laredo Holdings was incorporated pursuant to the laws of the State of Delaware on August 12, 2011 for the purposes of a Corporate Reorganization (as defined below) and the initial public offering of its common stock (the "IPO") on December 20, 2011. As a holding company, Laredo Holdings' management operations are conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo"), a Delaware corporation, and Laredo's subsidiaries, Laredo Petroleum Texas, LLC ("Laredo Texas"), a Texas limited liability company, Laredo Gas Services, LLC ("Laredo Gas"), a Delaware limited liability company, and Laredo Petroleum—Dallas, Inc. ("Laredo Dallas"), a Delaware corporation.
On July 1, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, and Laredo completed the acquisition of Broad Oak Energy, Inc., a Delaware corporation ("Broad Oak"), for a combination of equity and cash. Prior to the acquisition, Broad Oak was owned by its management and Warburg Pincus Private Equity, L.P. ("Warburg Pincus IX"). On July 19, 2011, Broad Oak's name was changed to Laredo Petroleum—Dallas, Inc.
On December 19, 2011, immediately prior to the IPO, Laredo LLC merged with and into Laredo Holdings, with Laredo Holdings being the surviving entity. Warburg Pincus IX and other affiliates of Warburg Pincus LLC were majority owners of Laredo LLC and are of Laredo Holdings. The preferred units and certain series of restricted units of Laredo LLC were exchanged into shares of common stock of Laredo Holdings based on the pre-offering equity value of such units (the "Corporate Reorganization"). The common stock has one vote per share and a par value of $0.01 per share.
In these notes, the "Company," when used in the present tense, prospectively or for historical periods since December 19, 2011, refers to Laredo Holdings, Laredo and its subsidiaries collectively, and for historical periods prior to December 19, 2011 refers to Laredo LLC, Laredo and its subsidiaries collectively, unless the context indicates otherwise.
B—Basis of presentation and significant accounting policies
1. Basis of presentation
The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The Broad Oak acquisition discussed in Note A was accounted for in a manner similar to a pooling of interests. The historical financial statements present the assets and liabilities of Laredo Holdings and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The Company operates oil and natural gas properties as one business segment, which explores for, develops and produces oil and natural gas.
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Laredo Petroleum Holdings, Inc.
Condensed notes to the consolidated financial statements (Continued)
(Unaudited)
B—Basis of presentation and significant accounting policies (Continued)
The accompanying consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2011 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position at June 30, 2012, the results of operations for the three and six months ended June 30, 2012 and 2011 and cash flows for the six months ended June 30, 2012 and 2011. All such adjustments are of a normal recurring nature.
Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in Laredo Holdings' Annual Report on Form 10-K for the year ended December 31, 2011 (the "2011 Annual Report").
2. Use of estimates in the preparation of interim unaudited consolidated financial statements
The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions 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 period. Although management believes these estimates are reasonable, actual results could differ from these estimates. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.
Significant estimates include, but are not limited to, estimates of the Company's reserves of oil and natural gas, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, stock-based compensation, deferred income taxes and fair values of commodity, interest rate derivatives and commodity deferred premiums. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
3. Accounts receivable
The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.
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Amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners and as the operator in the majority of its wells the ability to realize the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances over 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.
Accounts receivable consist of the following components as of June 30, 2012 and December 31, 2011:
Joint operations(1)
Other
Total, net
4. Derivative financial instruments
The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are primarily in the form of collars, swaps, puts and basis swaps. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.
Derivative instruments are recorded at fair value and are included on the unaudited consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivative instruments by counterparty in the accompanying unaudited consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.
The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Realized and unrealized gains and losses on derivatives are included in cash flows from operating activities (see Note F).
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5. Other current liabilities
Other current liabilities consist of the following components as of June 30, 2012 and December 31, 2011:
Lease operating expense payable
Prepaid drilling liability
Production taxes payable
Deferred income taxes payable
Current portion of asset retirement obligations
Other accrued liabilities
Total other current liabilities
6. Property and equipment
The following table sets forth the Company's property and equipment as of June 30, 2012 and December 31, 2011:
Proved oil and natural gas properties
Less accumulated depletion and impairment
Proved oil and natural gas properties, net
Less accumulated depreciation
Pipeline and gas gathering assets, net
Less accumulated depreciation and amortization
Other fixed assets, net
Total property and equipment, net
For the three months ended June 30, 2012 and 2011, depletion expense was $20.70 per barrel of oil equivalent ("BOE") and $20.11 per BOE, respectively. For the six months ended June 30, 2012 and 2011, depletion expense was $20.20 per BOE and $18.44 per BOE, respectively.
7. Deferred loan costs
Loan origination fees are stated at cost, net of amortization, which are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $10.5 million and $0.4 million of deferred loan costs in the three months ended June 30,
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2012 and 2011, respectively, and $10.5 million and $10.6 million in the six months ended June 30, 2012 and 2011, respectively. The Company had total deferred loan costs of $31.7 million and $23.5 million, net of accumulated amortization of $6.7 million and $4.4 million, as of June 30, 2012 and December 31, 2011, respectively.
During the six months ended June 30, 2011, the Company wrote off approximately $3.2 million in deferred loan costs as a result of the retirement of debt and changes in the borrowing base of the Senior Secured Credit Facility (as defined in Note C). No deferred loan costs were written off in the six months ended June 30, 2012.
Future amortization expense of deferred loan costs at June 30, 2012 is as follows:
Remaining 2012
2013
2014
2015
2016
Thereafter
Total
8. Asset retirement obligations
Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through the depletion of the asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. See Note G for fair value disclosures related to the Company's asset retirement obligations.
The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates are reasonably determinable.
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The following reconciles the Company's asset retirement obligations liability as of June 30, 2012 and December 31, 2011:
Liability at beginning of period
Liabilities added due to acquisitions, drilling and other
Accretion expense
Liabilities settled upon plugging and abandonment
Revision of estimates
Liability at end of period
9. Fair value measurements
The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, undistributed revenue and royalties, and other accrued liabilities approximate their fair values. See Note C for fair value disclosures related to the Company's debt obligations. The Company carries its derivative financial instruments at fair value. See Note F and Note G for details regarding the fair value of the Company's derivative financial instruments.
10. Compensation awards
For stock-based compensation awards, compensation expense is recognized in "General and adminstrative" in the Company's unaudited consolidated statements of operations over the awards' vesting periods based on their grant date fair value. The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. See Note D for further discussion of the restricted stock awards and restricted stock option awards.
For performance unit awards issued to management with a combination of market and service vesting criteria, a Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of the awards at the date of grant and to re-measure the fair value at the end of each reporting period until settlement in accordance with GAAP. Due to the relatively short trading history for the Company's stock, the volatility criteria utilized in the Monte Carlo simulation is based on the volatilities of a group of peer companies that have been determined to be most representative of the Company's expected volatility. These awards are accounted for as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense for each period for these awards is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. Compensation expense for these awards amounted to $0.5 million and $1.0 million in the three and six months ended June 30, 2012, respectively, and is recognized in "General and administrative" in the Company's unaudited consolidated statements of operations and the corresponding liability is included in "Other
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noncurrent liabilities" in the June 30, 2012 unaudited consolidated balance sheet. As there are inherent uncertainties related to the factors and the Company's judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the member of management.
11. Impairment of long-lived assets
Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. During the three and six months ended June 30, 2011, the Company recorded a $0.04 million and a $0.2 million write-down of materials and supplies, respectively. Other than the aforementioned write-downs, for the three and six months ended June 30, 2012 and 2011, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.
12. Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed at June 30, 2012 or December 31, 2011.
13. Business combinations
Acquisitions are accounted for under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.
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14. Related party transactions
The following table summarizes the net oil and natural gas sales (oil and natural gas sales less production taxes) received from the Company's related party and is included in the unaudited consolidated statements of operations for the periods presented:
Net oil and natural gas sales(1)
The following table summarizes the amounts included in oil and natural gas sales receivable in the unaudited consolidated balance sheets for the periods presented:
Oil and natural gas sales receivable(1)
C—Debt
1. Interest expense
The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2012 and 2011:
Cash payments for interest
Amortization and write-off of deferred loan costs and other adjustments
Change in accrued interest
Interest costs incurred
Less capitalized interest
Total interest expense
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C—Debt (Continued)
The following table presents the weighted average interest rates and the weighted average outstanding debt balances for the three and six months ended June 30, 2012 and 2011:
Senior Secured Credit Facility
2019 Notes
2022 Notes
Term Loan(1)
Broad Oak Credit Facility(2)
2. 2022 Notes
On April 27, 2012, Laredo completed an offering of $500 million in aggregate principal amount of 73/8% senior unsecured notes due 2022 (the "2022 Notes"). The 2022 Notes will mature on May 1, 2022 and bear an interest rate of 73/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The 2022 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by Laredo Holdings and its subsidiaries, with the exception of Laredo (collectively, the "Guarantors"). The net proceeds from the 2022 Notes (i) were used to pay in full $280.0 million outstanding under Laredo's revolving Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), and (ii) will be used for general working capital purposes.
The 2022 Notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 Indenture"), among Laredo, Wells Fargo Bank, National Association, as trustee, and the Guarantors. The 2012 Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under the 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 Indenture.
Laredo will have the option to redeem the 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the redemption prices (expressed as percentages of principal amount) of 103.688% for the twelve-month period beginning on May 1, 2017, 102.458% for the twelve-month period beginning
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on May 1, 2018, 101.229% for the twelve-month period beginning on May 1, 2019 and 100.000% for the twelve-month period beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest to, but not including, the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before May 1, 2015, Laredo may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.375% of the principal amount of the 2022 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2012 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Laredo may also be required to make an offer to purchase the 2022 Notes upon a change of control triggering event. In addition, if a change of control occurs prior to May 1, 2013, Laredo may redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the 2022 Notes redeemed, plus any accrued and unpaid interest, if any, to the date of redemption.
In connection with the issuance of the 2022 Notes, Laredo and the Guarantors entered into a registration rights agreement with the initial purchasers of the 2022 Notes on April 27, 2012, pursuant to which Laredo and the Guarantors filed with the Securities and Exchange Commission ("SEC") a registration statement that became effective with respect to an offer to exchange the 2022 Notes for substantially identical notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) that are registered under the Securities Act of 1933, as amended (the "Securities Act"). The offer to exchange the 2022 Notes for substantially identical notes registered under the Securities Act commenced on July 2, 2012 and was consummated on August 1, 2012 with all notes exchanged.
3. 2019 Notes
On January 20, 2011, Laredo completed an offering of $350 million 91/2% Senior Notes due 2019 (the "January Notes") and on October 19, 2011, Laredo completed an offering of an additional $200 million 91/2% Senior Notes due 2019 (the "October 2011 Notes" and together with the January Notes, the "2019 Notes"). The 2019 Notes will mature on February 15, 2019 and bear an interest rate of 9.5% per annum payable semi-annually, in cash, in arrears on February 15 and August 15 of each year. The 2019 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by the Guarantors.
In connection with the issuance of the 2019 Notes, Laredo and the Guarantors entered into registration rights agreements with the initial purchasers of the 2019 Notes, pursuant to which Laredo and the Guarantors filed with the SEC a registration statement that became effective with respect to an offer to exchange the 2019 Notes for substantially identical notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) registered under the Securities Act. The offer to exchange the 2019 Notes for substantially identical notes registered under the Securities Act was consummated on January 13, 2012 with all notes exchanged.
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4. Senior secured credit facility
The Senior Secured Credit Facility, which matures July 1, 2016, had a borrowing base of $785.0 million with no amounts outstanding at June 30, 2012. It contains both financial and non-financial covenants that the Company was in compliance with at June 30, 2012.
Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. At June 30, 2012, Laredo had one letter of credit outstanding totaling $0.03 million under the Senior Secured Credit Facility.
5. Fair value of debt
The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amount and fair value of the Company's debt instruments at June 30, 2012 and December 31, 2011:
2019 Notes(1)
Senior Secured Credit Facility(2)
Total value of debt
At June 30, 2012 and December 31, 2011, the fair value of the debt outstanding on the 2019 Notes and the 2022 Notes was determined using the June 30, 2012 and December 31, 2011 quoted market price (Level 1), respectively, and the fair value of the outstanding debt at December 31, 2011 on the Senior Secured Credit Facility was estimated utilizing pricing models for similar instruments (Level 2). See Note G for information about fair value hierarchy levels.
D—Stock-based compensation
In November 2011, the Board of Directors of Laredo Holdings and its stockholders approved a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of stock options, restricted stock awards and other awards. The LTIP provides for the issuance of 10.0 million shares.
The Company recognizes the fair value of stock-based payments to employees and directors as a charge against earnings. The Company recognizes stock-based payment expense over the requisite service period. Laredo Holdings' stock-based payment awards are accounted for as equity instruments.
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D—Stock-based compensation (Continued)
Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations.
All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. Restricted stock awards converted in the Corporate Reorganization vested 20% at the grant date and then vest 20% annually thereafter. The restricted stock awards granted under the LTIP vest 33%, 33% and 34% per year beginning on the first anniversary date of the grant. The following table reflects the outstanding restricted stock awards for the six months ended June 30, 2012:
Outstanding at December 31, 2011
Granted
Forfeited
Vested
Outstanding at June 30, 2012
Restricted stock option awards
Restricted stock options granted under the LTIP vest and are exercisable in four equal installments on each of the first four anniversaries of the date of the grant. The following table reflects the stock option award activity for the six months ended June 30, 2012:
Vested and exercisable at end of period
The Company used the Black-Scholes option pricing model to determine the fair value of restricted stock options and is recognizing the associated expense on a straight-line basis over the four year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, and the associated volatility. There were no restricted stock options granted during the three months ended June 30, 2012.
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The assumptions used to estimate the fair value of restricted stock options granted on February 3, 2012 are as follows:
Risk-free interest rate(1)
Expected option life(2)
Expected volatility(3)
Fair value per option
E—Income taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
The Company is subject to corporate income taxes and the Texas margin tax. Income tax expense for the three and six months ended June 30, 2012 and 2011 consisted of the following:
Current taxes
Federal
State
Deferred taxes
Income tax expense
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E—Income taxes (Continued)
Income tax expense differed from amounts computed by applying the federal income tax rate of 34% to pre-tax income from operations as a result of the following:
Income tax expense computed by applying the statutory rate
State income tax, net of federal tax benefit and increase in valuation allowance
Income from non-taxable entity
Non-deductible compensation
Change in valuation allowance
Other items
Significant components of the Company's deferred tax assets as of June 30, 2012 and December 31, 2011 are as follows:
Oil and natural gas properties and equipment
Net operating loss carry-forward
Valuation allowance
Net deferred tax asset
Net deferred tax assets and liabilities were classified in the unaudited consolidated balance sheets as follows as of June 30, 2012 and December 31, 2011:
Deferred tax asset
Deferred tax liability
Net deferred tax assets
The Company had federal net operating loss carry-forwards totaling approximately $527.3 million and state net operating loss carry-forwards totaling approximately $180.9 million at June 30, 2012. These carry-forwards begin expiring in 2026. The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. At June 30, 2012, a $0.6 million valuation allowance was recorded against the state of Louisiana deferred tax asset and a $0.03 million valuation allowance was recorded against the Company's charitable contribution carry-forward. The Company believes the federal and state of Oklahoma net operating loss carry-forwards
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are fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded at June 30, 2012 and the Company's ability to capitalize intangible drilling costs, rather than expensing these costs, in order to prevent an operating loss carry-forward from expiring unused.
The Company's income tax returns for the years 2008 through 2011 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma, Texas and Louisiana which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carryovers typically does not begin to run until the year the attribute is utilized in a tax return. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the six months ended June 30, 2012.
F—Derivative financial instruments
1. Commodity derivatives
The Company engages in derivative transactions such as collars, swaps, puts and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its oil and natural gas production. As of June 30, 2012, the Company had 54 open derivative contracts with financial institutions, none of which were designated as hedges for accounting purposes, which extend from July 2012 to December 2015. The contracts are recorded at fair value on the balance sheet and any realized and unrealized gains and losses are recognized in current year earnings.
Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.
Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
Each put transaction has an established floor price. The Company pays the counterparty a premium in order to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.
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F—Derivative financial instruments (Continued)
Each basis swap transaction has an established fixed differential between the NYMEX gas futures and West Texas WAHA ("WAHA") index gas price. When the NYMEX futures settlement price less the fixed WAHA differential is greater than the actual WAHA price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the difference between the NYMEX futures settlement price less the fixed WAHA differential is less than the actual WAHA price, the Company pays the counterparty an amount equal to the difference multiplied by the hedged contract volume.
During the six months ended June 30, 2012, the Company entered into additional commodity contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
Oil (volumes in Bbls):
Price collar
Put
Natural gas (volumes in MMBtu):
Swap
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The following table summarizes open positions as of June 30, 2012, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:
Oil Positions:
Puts:
Hedged volume (Bbls)
Weighted average price ($/Bbl)
Swaps:
Collars:
Weighted average floor price ($/Bbl)
Weighted average ceiling price ($/Bbl)
Natural Gas Positions:
Hedged volume (MMBtu)
Weighted average price ($/MMBtu)
Weighted average floor price ($/MMBtu)
Weighted average ceiling price ($/MMBtu)
Basis swaps(1):
2. Interest rate derivatives
The Company is exposed to market risk for changes in interest rates related to its Senior Secured Credit Facility. Interest rate derivative agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparties the difference,
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and conversely, the counterparties are required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.
The following presents the settlement terms of the interest rate derivatives at June 30, 2012:
Notional amount
Fixed rate
Cap rate
3. Balance sheet presentation
The Company's oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis in "Derivative financial instruments" in the unaudited consolidated balance sheets.
The following summarizes the fair value of derivatives outstanding on a gross basis as of:
Assets:
Commodity derivatives:
Oil derivatives
Natural gas derivatives
Interest rate derivatives
Liabilities:
Oil derivatives(1)
Natural gas derivatives(2)
By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of
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the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that are also lenders in the Senior Secured Credit Facility and meet the Company's minimum credit quality standard, or have a guarantee from an affiliate that meets the Company's minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis. In accordance with the Company's standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated at June 30, 2012.
4. Gain (loss) on derivatives
Gains and losses on derivatives are reported on the unaudited consolidated statements of operations in the respective "Realized and unrealized gain (loss)" amounts. Realized gains (losses) represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are non-cash items.
The following represents the Company's reported gains and losses on derivative instruments for the three and six months ended June 30, 2012 and 2011:
Realized gains (losses):
Commodity derivatives
Unrealized gains (losses):
Total gains (losses):
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G—Fair value measurements
The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value. The fair value of derivative financial instruments is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three and six months ended June 30, 2012 and 2011.
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G—Fair value measurements (Continued)
Fair value measurement on a recurring basis
The following presents the Company's fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at June 30, 2012 and December 31, 2011.
As of June 30, 2012:
Deferred premiums
As of December 31, 2011:
These items are included in "Derivative financial instruments" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of commodity derivatives include the NYMEX natural gas and crude oil prices, appropriate risk adjusted discount rates and other relevant data. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of interest rate swaps include the interest rate curves, appropriate risk adjusted discount rates and other relevant data.
The Company's deferred premiums associated with its commodity derivative contracts are categorized in Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 2.06% to 3.56%) and then amortizing the change in net present value into interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation the net present value of each deferred premium is not adjusted, therefore significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new deal containing a deferred premium entered into; however the valuation for the deals already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore on a quarterly basis, the valuation is compared to counterparty valuations and third party valuation of the deferred premiums
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for reasonableness. A summary of the changes in assets classified as Level 3 measurements for the three and six months ended June 30, 2012 and 2011 are as follows:
Balance of Level 3 at beginning of period(1)
Realized and unrealized gains included in earnings
Amortization of deferred premiums
Total purchases and settlements:
Purchases
Settlements
Balance of Level 3 at end of period
Change in unrealized losses attributed to earnings relating to derivatives still held at end of period
Balance of Level 3 at beginning of period
Realized and unrealized gains (losses) included in earnings
Change in unrealized gains attributed to earnings relating to derivatives still held at end of period
Fair value measurement on a nonrecurring basis
The Company accounts for additions to its asset retirement obligation (see Note B.8) and the impairment of long-lived assets (see Note B.11), if any, at fair value on a nonrecurring basis in
26
accordance with GAAP. For purposes of fair value measurement, it was determined that the impairment of long-lived assets and the additions to the asset retirement obligation are classified as Level 3 based on the use of internally developed cash flow models. No impairments of long-lived assets were recorded in the six months ended June 30, 2012.
Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement, and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.
Asset retirement obligations. The accounting policies for asset retirement obligations are discussed in Note B.8, including a reconciliation of the Company's asset retirement obligation. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience; (ii) estimated remaining life per well based on the reserve life per well; (iii) future inflation factors; and (iv) the Company's average credit adjusted risk free rate.
Impairment of oil and natural gas properties. The accounting policies for impairment of oil and natural gas properties are discussed in the audited consolidated financial statements and notes thereto included in the 2011 Annual Report. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data.
H—Credit risk
The Company's oil and natural gas sales are to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the properties operated by the Company. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.
The Company uses derivative instruments to hedge its exposure to oil and natural gas price volatility and its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivative instruments are subject to counterparty netting under agreements governing such derivatives and therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Note F for additional information regarding the Company's derivative instruments.
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I—Commitments and contingencies
1. Lease commitments
The Company leases equipment and office space under operating leases expiring on various dates through 2016. Minimum annual lease commitments at June 30, 2012 and for the calendar years following are as follows:
The following table presents rent expense for the three and six months ended June 30, 2012 and 2011.
Rent expense
The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments.
2. Litigation
The Company may be involved in legal proceedings or is subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity.
3. Drilling contracts
The Company has committed to several short-term drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant penalties to the third party should the Company cease drilling efforts. These penalties could significantly impact the Company's financial statements upon contract termination. These commitments are not recorded in the accompanying unaudited consolidated balance sheets. Future commitments as of June 30, 2012 are $35.8 million. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2012.
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I—Commitments and contingencies (Continued)
4. Federal and state regulations
Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable state and federal regulations and these regulations will not have a material adverse impact on the financial position or results of operations of the Company. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations.
J—Defined contribution plans
The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt.
The following table presents total contributions to the plans for the three and six months ended June 30, 2012 and 2011.
Contributions
K—Net income per share
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards. The effect of the Company's outstanding options to purchase 549,446 shares of common stock at $24.11 per share were excluded from the calculation of diluted earnings per share for the three and six months ended June 30, 2012 because the exercise price of those options was greater than the average market price during the period, and therefore the inclusion of these outstanding options would have been anti-dilutive. The following is the calculation of basic and
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K—Net income per share (Continued)
diluted weighted average shares outstanding and net income per share for the three and six months ended June 30, 2012:
Income (numerator):
Net income—basic and diluted
Weighted average shares (denominator):
Weighted average shares—basic
Non-vested restricted stock
Weighted average shares—diluted
Net income per share:
L—Recently issued accounting standards
In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2011-11, Disclosures about Offsetting Assets and Liabilities, to improve reporting and transparency of offsetting (netting) assets and liabilities and the related effects on the financial statements. This ASU is effective for fiscal years and interim periods within those years beginning on or after January 1, 2013. The Company does not expect the adoption of this ASU to have a material effect on its consolidated financial statements.
M—Subsidiary guarantees
Laredo Holdings and all of Laredo's wholly-owned subsidiaries (Laredo Gas, Laredo Texas and Laredo Dallas, collectively, the "Subsidiary Guarantors") have fully and unconditionally guaranteed the 2019 Notes, the 2022 Notes and the Senior Secured Credit Facility. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheet as of June 30, 2012 and audited condensed consolidating balance sheet as of December 31, 2011, unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2012 and 2011, and unaudited condensed consolidating statements of cash flows for the six months ended June 30, 2012 and 2011, present financial information for Laredo Holdings as the parent of Laredo on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Subsidiary Guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. All deferred income taxes are recorded on Laredo's statements of financial position, as Laredo's subsidiaries are flow-through entities for income tax purposes. Prior to the Broad Oak acquisition on July 1, 2011, both Laredo and Laredo
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M—Subsidiary guarantees (Continued)
Dallas were separate taxable entities and deferred income taxes for the Company are recorded separately. The Subsidiary Guarantors are not restricted from making distributions to Laredo.
Condensed consolidating balance sheet June 30, 2012 (unaudited)
Accounts receivable
Total oil and natural gas properties, net
Total pipeline and gas gathering assets, net
Total other fixed assets, net
Investment in subsidiaries
Total other long-term assets
Other long-term liabilities
Stockholders' equity
31
Condensed consolidating balance sheet December 31, 2011 (audited)
Condensed consolidating statement of operations For the three months ended June 30, 2012 (unaudited)
Total operating revenues
Total operating costs and expenses
Income (loss) from operations
Interest income (expense), net
Other, net
Income (loss) from operations before income tax
Net income (loss)
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Condensed consolidating statement of operations For the three months ended June 30, 2011 (unaudited)
Income from operations
Income from operations before income tax
Condensed consolidating statement of operations For the six months ended June 30, 2012 (unaudited)
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Condensed consolidating statement of operations For the six months ended June 30, 2011 (unaudited)
Condensed consolidating statement of cash flows For the six months ended June 30, 2012 (unaudited)
Net cash flows provided by (used in) operating activities
Net cash flows provided by used in investing activities
Net cash flows provided by financing activities
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
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Condensed consolidating statement of cash flows For the six months ended June 30, 2011 (unaudited)
Net cash flows provided by operating activities
Net cash flows used in investing activities
N—Subsequent events
1. Acquisition
On July 12, 2012, the Company completed the acquisition of additional working interest in certain oil and natural gas properties located in Glasscock County, TX for a contract price of $20.5 million from a private company, subject to certain purchase price adjustments. The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date.
2. New derivative contracts
Subsequent to June 30, 2012, the Company entered into additional commodity contracts, with approximately $4.2 million in deferred premiums associated. The following table summarizes information about these new commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
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O—Supplementary information
Costs incurred in oil and natural gas property acquisition, exploration and development activities(1)
Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the three and six months ended June 30, 2012 and 2011:
Property acquisition costs:
Proved
Unproved
Exploration
Development costs
Total costs incurred
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report on Form 10-Q as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011 (the "2011 Annual Report"). The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements."
Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report on Form 10-Q, references in this Quarterly Report on Form 10-Q to "Laredo," "we," "us," "our" or similar terms refer to Laredo Petroleum, LLC together with its subsidiaries for periods prior to the Corporate Reorganization, and to Laredo Petroleum Holdings, Inc. together with its subsidiaries for periods after the Corporate Reorganization, unless the context otherwise indicates or requires. For more information regarding the Corporate Reorganization and IPO, see Note A to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.
Overview
We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties in the Permian and Mid-Continent regions of the United States. Laredo was founded in October 2006 to explore, develop and operate oil and natural gas properties and has grown rapidly through its drilling program and by making strategic acquisitions and joint ventures. On July 1, 2011, we completed the acquisition of Broad Oak Energy, Inc. ("Broad Oak"), whereby Broad Oak became a wholly-owned subsidiary of Laredo Petroleum, Inc., and its name was changed to Laredo Petroleum—Dallas, Inc. This acquisition was considered a combination of entities under common control and the historical and financial operating data presented herein are shown on a consolidated basis. In December 2011, we completed the Corporate Reorganization and IPO.
Our financial and operating performance for the three months ended June 30, 2012 included the following:
Our financial and operating performance for the six months ended June 30, 2012 included the following:
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Core areas of operations
Our activities are primarily focused in the Wolfberry and deeper horizons of the Permian Basin in West Texas and the Anadarko Granite Wash in the Texas Panhandle and Western Oklahoma. The oil and liquids-rich Permian Basin and the liquids-rich Anadarko Granite Wash are characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and significant initial production rates. As of June 30, 2012, we had an interest in 1,291 gross producing wells.
Additionally, as of June 30, 2012, we have accumulated 404,276 net acres. Through December 31, 2011, we had identified over 6,000 gross potential drilling locations on our existing acreage. We intend to continue to explore and develop this large acreage position to increase our cash flow, production and reserves through continued vertical and horizontal drilling programs.
Pricing
Our results of operations are heavily influenced by commodity prices. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and natural gas reserves.
The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months ended June 30, 2012 and June 30, 2011 used to value our reserves were $92.17 per Bbl for oil and $3.01 per MMBtu for natural gas, and $86.60 per Bbl for oil and $4.00 per MMBtu for natural gas, respectively. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price.
We have entered into a number of commodity derivatives, which have allowed us to offset a portion of the changes caused by price fluctuations on our oil and natural gas production as discussed in "—Hedging" below.
Sources of our revenue
Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include the effects of derivatives. For the three months ended June 30, 2012, our revenues are comprised of sales of approximately 71% oil, 28% natural gas and 1% for transportation and treating. For the six months ended June 30, 2012, our revenues are comprised of sales of approximately 70% oil, 29% natural gas and 1% for transportation and treating. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Hedging
Due to the inherent volatility in oil and natural gas prices, we use commodity derivative instruments, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and natural gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of
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variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives using an independent third party valuation and recognize an unrealized gain or loss. During the three and six months ended June 30, 2012, we recognized unrealized gains on our commodity derivatives of $19.4 million and $15.3 million, respectively, and during the three and six months ended June 30, 2011, we recognized an unrealized gain of $20.0 million and an unrealized loss of $8.7 million on our commodity derivatives, respectively, based on market price fluctuations compared to prices in our commodity derivative contracts.
Subsequent to June 30, 2012, we entered into 15 additional derivative contracts to hedge the price risk associated with approximately 8,760,000 MMBtu, 11,160,000 MMBtu and 15,480,000 MMBtu of our natural gas production for the twelve months ending December 31, 2013, 2014 and 2015, respectively. These derivative contracts have associated deferred premiums totaling approximately $4.2 million. See Note N to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding these derivative contracts.
Our hedged positions as of June 30, 2012 are as follows:
Oil(1)
Total volume hedged with ceiling price (Bbls)
Total volume hedged with floor price (Bbls)
Natural Gas(2)
Total volume hedged with ceiling price (MMBtu)
Weighted average ceiling price(3) ($/MMBtu)
Total volume hedged with floor price (MMBtu)
Weighted average floor price(3) ($/MMBtu)
Natural Gas basis swaps (MMbtu)
Total volume hedged(4) (MMBtu)
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settlement. At June 30, 2012, we had 200,000 MMBtu for the remainder of 2012 and 500,000 MMBtu for 2013 in basis swaps that did not have corresponding volumes hedged with a NYMEX index price. As such, the weighted average price of the basis differential attributable to these volumes has not been included in the weighted average ceiling and floor prices presented above as these basis contracts are not expected to settle based on our June 30, 2012 hedge positions.
Results of operations
The following table sets forth information regarding production, average sales prices and average costs per BOE for the three and six months ended June 30, 2012 and 2011:
Production data:
Oil and condensate (MBbl)
Natural gas (MMcf)
Oil equivalents (MBOE)(1)(2)
Average daily production (BOE/d)
% Oil and condensate
Average sales prices:
Oil and condensate, realized(3) ($/Bbl)
Natural gas, realized(3) ($/Mcf)
Oil equivalents, realized ($/BOE)
Oil and condensate, hedged(4) ($/Bbl)
Natural gas, hedged(4) ($/Mcf)
Oil equivalents, hedged ($/BOE)
Average costs per BOE:
General and administrative(5)
DD&A
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Three months ended June 30, 2012 as compared to the three months ended June 30, 2011
The following table sets forth selected operating data for the three months ended June 30, 2012 compared to the three months ended June 30, 2011:
Revenues
Oil
Natural gas
Costs and expenses
General and administrative (including non-cash stock-based compensation of $2,588 and $557 for the three months ended June 30, 2012 and 2011, respectively)
Non-operating income, net
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Oil and natural gas revenues. Our oil and natural gas revenues increased by approximately $8.8 million, or 7%, to $139.6 million during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 8,304 BOE/D, or 36%, during the three months ended June 30, 2012 as compared to the same period in 2011. The total increase in revenue of approximately $8.8 million for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 is attributable to higher oil and natural gas production volumes, which were offset by declining market prices for oil and natural gas for the three months ended June 30, 2012. Production increased by 356 MBbls for oil and 2,398 MMcf for natural gas for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. The net dollar effect of the decrease in prices of approximately $42.1 million (calculated as the change in period-to-period average prices times current quarter production volumes for oil and natural gas) and the net dollar effect of the increase in production of approximately $50.9 million (calculated as the increase in period-to-period volumes for oil and natural gas times the prior period average prices) are shown below.
Effect of changes in price:
Total revenues due to change in price
Effect of changes in volumes:
Total revenues due to change in volumes
Rounding differences
Total change in revenues
Lease operating expenses. Lease operating expenses, which include workover expenses, increased to $15.7 million for the three months ended June 30, 2012 from $10.2 million for the three months ended June 30, 2011, an increase of approximately 54%. The increase was primarily due to an increase in drilling activity, which resulted in additional producing wells during the second quarter of 2012 compared to the second quarter of 2011. The increase in well count also led to increases in routine repairs and maintenance. On a per-BOE basis, lease operating expenses increased in total to $5.48 per BOE for the three months ended June 30, 2012 from $4.85 per BOE for the three months ended June 30, 2011.
Production and ad valorem taxes. Production and ad valorem taxes decreased to approximately $7.3 million for the three months ended June 30, 2012 from $7.9 million for the three months ended
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June 30, 2011, a decrease of $0.6 million. This decrease was primarily due to the decrease in market prices for oil and natural gas, which was offset by a significant increase in production for the second quarter of 2012 as compared to the same period in 2011. The average realized prices excluding derivatives for the three months ended June 30, 2012 were $85.45 per Bbl for oil and $3.95 per Mcf for natural gas as compared to $98.53 per Bbl for oil and $6.60 per Mcf for natural gas for the three months ended June 30, 2011.
General and administrative ("G&A"). G&A expense increased to approximately $14.4 million for the three months ended June 30, 2012 from $10.5 million for the same period in 2011, an increase of $3.9 million, or 37%. Increases in salaries, benefits and bonuses accounted for approximately $2.1 million of the increase due to an increase in the number of employees as we continue to grow our business. Professional fees decreased by approximately $0.9 million due largely to fees incurred for the Broad Oak acquisition during the second quarter of 2011.
Additionally, stock-based compensation increased by approximately $2.0 million to $2.6 million for the three months ended June 30, 2012 as compared to the same period in 2011 due to the issuance of 776,711 restricted stock awards and 602,948 non-qualified stock options during 2012. The fair value of the restricted stock awards issued during the first and second quarters of 2012 was calculated based on the value of our stock price on the date of grant in accordance with the applicable generally accepted accounting principles in the United States of America ("GAAP") and is being recognized on a straight-line basis over the three year requisite service period of the awards. The fair value of our non-qualified restricted stock options was determined using a Black-Scholes valuation model in accordance with applicable GAAP accounting and is being recognized on a straight-line basis over the four year requisite service period of the awards. The issuance of our cash-settled performance unit liability awards in February 2012, which are revalued at the end of each reporting period using a Monte Carlo simulation, accounted for approximately $0.5 million of the total change for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011.
On a per-BOE basis, G&A expense increased to $5.05 per BOE during the three months ended June 30, 2012 from $5.01 per BOE for the three months ended June 30, 2011. Excluding non-cash, stock-based compensation, G&A expense per BOE was $4.14 and $4.75 for the three months ended June 30, 2012 and 2011, respectively.
See Notes B and D to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding our stock and performance based compensation.
Depreciation, depletion and amortization ("DD&A"). DD&A increased to approximately $60.7 million for the three months ended June 30, 2012 from $43.4 million for the same period in 2011, an increase of $17.3 million, or 40%. The following table provides components of our DD&A expense for the three months ended June 30, 2012 and 2011.
Depletion of proved oil and natural gas properties
Depreciation of pipeline assets
Depreciation of other property and equipment
Total DD&A
Depletion of proved oil and natural gas properties per BOE
DD&A per BOE
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The increase in depletion of proved oil and natural gas properties of $16.9 million and the increase in the depletion rate of $0.59 per BOE resulted primarily from (i) increased net book value on new reserves added, (ii) higher total production levels, and (iii) increased capitalized costs for new wells completed in 2012.
Impairment expense. Impairment expense decreased to zero for the three months ended June 30, 2012 from $0.04 million for the three months ended June 30, 2011. Impairment expense incurred in the first three months of 2011 was to reflect our materials and supplies inventory at the lower of cost or market value calculated as of June 30, 2011. It was determined at June 30, 2012 that a lower of cost or market adjustment was not needed for materials and supplies.
We evaluate the impairment of our oil and natural gas properties on a quarterly basis according to the full cost method prescribed by the SEC. If the carrying amount exceeds the calculated full cost ceiling, we reduce the carrying amount of the oil and natural gas properties to the calculated full cost ceiling amount, which is determined to be the estimated fair value. At June 30, 2012 and 2011, it was determined that our oil and natural gas properties were not impaired.
Commodity derivative financial instruments. Due to the inherent volatility in oil and natural gas prices, we use commodity derivative instruments, including puts, swaps, collars and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and natural gas production. At each period end, we estimate the fair value of our commodity derivatives using a valuation prepared by an independent third party and recognize an unrealized gain or loss. We have not elected hedge accounting on these derivatives, and therefore, the unrealized gains and losses on open positions are reflected in current earnings. For the three months ended June 30, 2012 and 2011, our commodity derivatives resulted in a realized gain of $9.1 million and a realized loss of $1.6 million, respectively. For the three months ended June 30, 2012 and 2011, our commodity derivatives resulted in unrealized gains of $19.4 million and $20.0 million, respectively. At June 30, 2012, we had 18 commodity derivatives contracts with associated deferred premiums totaling approximately $27.5 million. The estimated fair value of our total deferred premiums was approximately $23.6 million at June 30, 2012. The fair market value of these premiums is deducted from our unrealized gain or loss at each period end.
Interest expense and realized and unrealized gains and losses on interest rate swaps. Interest expense increased to approximately $21.7 million for the three months ended June 30, 2012 from $11.7 million for the three months ended June 30, 2011, largely due to the issuance of (i) $200.0 million in 91/2% senior unsecured notes due 2019 in October of 2011 in addition to the previously outstanding $350.0 million 91/2% senior unsecured notes due in 2019 (collectively, the "2019 senior unsecured notes"), and (ii) $500.0 million in 73/8% senior unsecured notes due 2022 ("2022 senior unsecured notes") in April of 2012 as shown in the table below.
Senior secured credit facility
2019 senior unsecured notes
2022 senior unsecured notes
Broad Oak credit facility(1)
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We have entered into certain variable-to-fixed interest rate swaps that hedge our exposure to interest rate variations on our variable interest rate debt. At June 30, 2012, we had interest rate swaps outstanding for a notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% and terms expiring through September 2013. At June 30, 2011, we had interest rate swaps outstanding for a notional amount of $260.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring through September 2013. We realized losses on interest rate swaps of $0.8 million and $1.3 million for the three months ended June 30, 2012 and 2011, respectively. Additionally, we recorded unrealized gains on interest rate swaps of $0.8 million and $0.3 million for the three months ended June 30, 2012 and 2011, respectively. At June 30, 2012, the estimated fair value of our interest rate swaps was in a net liability position of $0.4 million compared to $2.0 million at December 31, 2011.
Income tax expense. We recorded a deferred income tax expense of $17.4 million for the three months ended June 30, 2012, compared to a deferred income tax expense of $23.1 million for the three months ended June 30, 2011. The estimated annual effective tax rate was 36% for each of the three months ended June 30, 2012 and 2011. Our effective tax rate is based on our estimated annual permanent tax differences and estimated annual pre-tax book income. Our estimates involve assumptions we believe to be reasonable at the time of the estimation.
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Six months ended June 30, 2012 as compared to the six months ended June 30, 2011
The following table sets forth selected operating data for the six months ended June 30, 2012 compared to the six months ended June 30, 2011:
General and administrative (including non-cash stock-based compensation of $4,835 and $876 for the six months ended June 30, 2012 and 2011, respectively)
Non-operating expense, net
Oil and natural gas revenues. Our oil and natural gas revenues increased by approximately $52.0 million, or 22%, to $288.6 million during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 7,620 BOE/D during the six months ended June 30, 2012 as compared to the same period in 2011. The total increase in revenue of approximately $52.0 million is largely attributable to higher oil and natural gas production volumes for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Production increased by 714 MBbls for oil and 4,168 MMcf for natural gas for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. The net dollar effect of the decrease in prices of approximately $41.5 million (calculated as the change in period-to-period average prices times current year-to-date production volumes for oil and natural gas) and the net dollar effect of the increase in production of approximately $93.6 million (calculated as the increase in
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period-to-period volumes for oil and natural gas times the prior period average prices) are shown below.
Lease operating expenses. Lease operating expenses, which include workover expenses, increased to $30.6 million for the six months ended June 30, 2012 from $18.1 million for the six months ended June 30, 2011, an increase of approximately 69%. The increase was primarily due to an increase in drilling activity, which resulted in additional producing wells during the first six months of 2012 compared to the same period in 2011. The increase in well count also led to increases in routine repairs and maintenance. Additionally, a portion of the increase is due to approximately $1.1 million in additional workover expenses incurred during the first six months of 2012 as compared to the same period in 2011 resulting largely from costs incurred for the workover of one well. This workover is not indicative of costs typically incurred for workovers and was fully completed in the first quarter of 2012.
On a per-BOE basis, lease operating expenses increased in total to $5.67 per BOE for the six months ended June 30, 2012 from $4.53 per BOE for the six months ended June 30, 2011. Excluding the one-time workover expense noted above, lease operating expense per BOE at June 30, 2012 was $5.44 per BOE.
Production and ad valorem taxes. Production and ad valorem taxes increased to approximately $16.2 million for the six months ended June 30, 2012 from $15.0 million for the six months ended June 30, 2011, an increase of $1.2 million. This increase was primarily due to the significant increase in production of approximately 1,409 MBOE, or 35%, for the first six months of 2012 as compared to the same period in 2011.
Drilling and production. Drilling and production costs increased to approximately $1.8 million for the six months ended June 30, 2012 from $0.7 million for the six months ended June 30, 2011 as a result of increased maintenance costs related to the increase in drilling during the first six months of 2012 as compared to the same period in 2011.
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General and administrative ("G&A"). G&A expense increased to approximately $31.9 million for the six months ended June 30, 2012 from $19.8 million for the six months ended June 30, 2011, an increase of $12.1 million, or 61%. Increases in salaries, benefits and bonuses accounted for approximately $6.3 million of the increase due to the payment of performance bonuses totaling $2.0 million in February 2012 as well as an increase in the number of employees as we continue to grow our business.
Additionally, stock-based compensation increased by approximately $4.0 million to $4.8 million for the first six months of 2012 as compared to the same period in 2011 due to the issuance of 776,711 restricted stock awards and 602,948 non-qualified stock options during 2012. The fair value of the restricted stock awards issued during the first and second quarters of 2012 was calculated based on the value of our stock price on the date of grant in accordance with GAAP and is being recognized on a straight-line basis over the three year requisite service period of the awards. The fair value of our non-qualified restricted stock options was determined using a Black-Scholes valuation model in accordance with applicable GAAP accounting and is being recognized on a straight-line basis over the four year requisite service period of the awards. The issuance of our cash-settled performance unit liability awards in February 2012, which are revalued at the end of each reporting period using a Monte Carlo simulation, accounted for approximately $1.0 million of the total change for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011.
On a per-BOE basis, G&A expense increased to $5.91 per BOE during the six months ended June 30, 2012 from $4.95 per BOE for the six months ended June 30, 2011. Excluding non-cash, stock-based compensation, G&A expense per BOE was $5.02 and $4.73 for the six months ended June 30, 2012 and 2011, respectively.
Depreciation, depletion and amortization ("DD&A"). DD&A increased to approximately $112.2 million for the six months ended June 30, 2012 from $75.9 million for the six months ended June 30, 2011, an increase of $36.3 million, or 48%. The following table provides components of our DD&A expense for the six months ended June 30, 2012 and 2011.
The increase in depletion of proved oil and natural gas properties of $35.5 million and the increase in the depletion rate of $1.76 per BOE resulted primarily from (i) increased net book value on new reserves added, (ii) higher total production levels and (iii) increased capitalized costs for new wells completed in 2012.
Impairment expense. Impairment expense decreased to zero for the six months ended June 30, 2012 from $0.2 million for the six months ended June 30, 2011. Impairment expense incurred in the first six months of 2011 was to reflect our materials and supplies inventory at the lower of cost or
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market value calculated as of June 30, 2011. It was determined at June 30, 2012 that a lower of cost or market value adjustment was not needed for materials and supplies.
Commodity derivative financial instruments. Due to the inherent volatility in oil and natural gas prices, we use commodity derivative instruments, including puts, swaps, collars and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and natural gas production. At each period end, we estimate the fair value of our commodity derivatives using a valuation prepared by an independent third party and recognize an unrealized gain or loss. We have not elected hedge accounting on these derivatives, and therefore, the unrealized gains and losses on open positions are reflected in current earnings. For the six months ended June 30, 2012 and 2011, our commodity derivatives resulted in a realized gain of $13.8 million and a realized loss of $0.9 million, respectively. For the six months ended June 30, 2012 and 2011, our commodity derivatives resulted in an unrealized gain of $15.3 million and an unrealized loss of $8.7 million, respectively. At June 30, 2012, we had 18 commodity derivatives contracts with associated deferred premiums totaling approximately $27.5 million. The estimated fair value of our total deferred premiums was approximately $23.6 million at June 30, 2012. The fair market value of these premiums is deducted from our unrealized gain or loss at each period end.
Interest expense and realized and unrealized gains and losses on interest rate swaps. Interest expense increased to approximately $36.4 million for the six months ended June 30, 2012 from $22.3 million for the six months ended June 30, 2011, largely due to the issuance of our 2019 senior unsecured notes in January and October of 2011 as well as the issuance of our 2022 senior unsecured notes in April of 2012 as shown in the table below.
Term loan(1)
Broad Oak credit facility(2)
We have entered into certain variable-to-fixed interest rate swaps that hedge our exposure to interest rate variations on our variable interest rate debt. At June 30, 2012, we had interest rate swaps outstanding for a notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% and terms expiring through September 2013. At June 30, 2011, we had interest rate swaps outstanding for a notional amount of $260.0 million with fixed pay rates ranging from 1.11% to 3.41% and terms expiring through September 2013. We realized losses on interest rate swaps of $1.9 million and
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$2.6 million for the six months ended June 30, 2012 and 2011, respectively. Additionally, we recorded unrealized gains on interest rate swaps of $1.6 million and $1.5 million for the six months ended June 30, 2012 and June 30, 2011, respectively. At June 30, 2012, the estimated fair value of our interest rate swaps was in a net liability position of $0.4 million compared to $2.0 million at December 31, 2011.
Income tax expense. We recorded a deferred income tax expense of $32.2 million for the six months ended June 30, 2012, compared to a deferred income tax expense of $25.7 million for the six months ended June 30, 2011. The estimated annual effective tax rate was 36% for each of the six months ended June 30, 2012 and 2011. Our effective tax rate is based on our estimated annual permanent tax differences and estimated annual pre-tax book income. Our estimates involve assumptions we believe to be reasonable at the time of the estimation.
Liquidity and capital resources
Since our IPO, our primary sources of liquidity have been cash flows from operations, borrowings under our senior secured credit facility and proceeds from our senior unsecured notes. Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us, which resources we cannot assure you will be available to us or their terms. We believe that we have sufficient liquidity available to us from cash flows from operations and under our senior secured credit facility as well as the remaining proceeds from the April 2012 offering of the 2022 senior unsecured notes for our planned exploration and development activities. In addition, our hedge positions currently provide relative certainty on a majority of our cash flows from operations through 2012 even with the general decline in the prices of natural gas.
At June 30, 2012, we had no debt outstanding and approximately $0.03 million of outstanding letters of credit under our senior secured credit facility. Additionally, we had $1.05 billion of outstanding senior unsecured notes, excluding the remaining premium of $1.9 million received on the October 2011 offering of our 2019 senior unsecured notes. We had approximately $785.0 million available for borrowings under our senior secured credit facility and $146.5 million in cash on hand for total available liquidity of approximately $931.5 million at June 30, 2012. We believe such availability as well as cash flows from operations provide us with the ability to implement our planned exploration and development activities.
As of August 7, 2012, we had no outstanding debt under our senior secured credit facility, approximately $785.0 million available for borrowings and approximately $47.8 million in cash on hand.
We expect that, in the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.
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Cash flows
Our cash flows for the six months ended June 30, 2012 and 2011 are as follows:
Net increase (decrease) in cash
Cash flows provided by operating activities
Net cash provided by operating activities was $199.8 million and $162.1 million for the six months ended June 30, 2012 and 2011, respectively. The increase of $37.7 million was largely due to increases in revenue due to increased production.
Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels and the volatility of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
Cash flows used in investing activities
We used cash flows in investing activities of approximately $485.8 million and $359.4 million for the six months ended June 30, 2012 and 2011, respectively, which is an increase of $126.4 million. A portion of our capital expenditures for the six months ended June 30, 2012 reflects expenditures which were accrued for at December 31, 2011 as part of our 2011 capital budget, but due to the timing of when billings were received, were paid during the first quarter of 2012. Additionally, a significant portion of the increase was due to increasing our drilling efforts in our Permian Basin and Anadarko Granite Wash areas as we continue to explore and develop our identified potential drilling locations.
Our cash used in investing activities for capital expenditures for the six months ended June 30, 2012 and 2011 is summarized in the table below.
Pipeline and gathering assets
Proceeds from other asset disposals
Capital expenditure budget
Our board of directors approved a budget of approximately $900 million for calendar year 2012, excluding acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
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The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil and natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
Cash flows provided by financing activities
We had cash flows provided by financing activities of $404.5 million and $188.2 million for the six months ended June 30, 2012 and 2011, respectively.
The increase in net cash provided by financing activities for the six months ended June 30, 2012 is the result of issuing our 2022 senior unsecured notes in an aggregate principal amount of $500 million in April 2012, which were offset by payments for loan costs totaling $10.5 million, as well as the net effect of payments and borrowings on our senior secured credit facility.
Net cash provided by financing activities for the six months ended June 30, 2011 was largely the result of our first issuance of 2019 senior unsecured notes in an aggregate principal amount of $350.0 million in January 2011 as well as net borrowings and payments on the former Broad Oak credit facility and our senior secured credit facility and the payment-in-full and termination of our $100.0 million term loan. Additionally, we incurred $10.6 million in loan costs for the six months ended June 30, 2011.
Debt
At June 30, 2012, we were a party only to our senior secured credit facility and the indentures governing our 2019 and 2022 senior unsecured notes. The Broad Oak credit facility was terminated on July 1, 2011 in connection with the Broad Oak acquisition. Our term loan facility was paid in full and retired in connection with the closing of the January 2011 offering of our 2019 senior unsecured notes.
Senior secured credit facility. Laredo Petroleum, Inc. is the borrower under our senior secured credit facility, which had a capacity of up to $2.0 billion with a borrowing base of $785.0 million and no borrowings outstanding at June 30, 2012. Additionally, our senior secured credit facility provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20.0 million and the total availability under the facility. At June 30, 2012, we had one letter of credit outstanding totaling approximately $0.03 million under our senior secured credit facility. Our senior secured credit facility will mature on July 1, 2016.
We have a choice of borrowing at an Adjusted Base Rate or in Eurodollars. Adjusted Base Rate loans bear interest at the Adjusted Base Rate plus an applicable margin between 0.75% and 1.75%, and Eurodollar loans bear interest at the adjusted London Interbank Offered Rate ("LIBOR") plus an applicable margin between 1.75% and 2.75%. At June 30, 2012, the applicable margin rates were 0.75% for the Adjusted Base Rate advances and 1.75% for the Eurodollar advances. We had no outstanding borrowings under our senior secured credit facility at June 30, 2012. We are also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.5%.
Our senior secured credit facility is secured by a first priority lien on our assets (including the stock of Laredo Petroleum Holdings, Inc.'s wholly-owned subsidiary, Laredo Petroleum, Inc.), including
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oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. Our senior secured credit facility is subject to certain financial and non-financial ratios on a consolidated basis, which we were in compliance with at June 30, 2012.
We entered into the third amendment to our senior secured credit facility on April 24, 2012, which allowed for the issuance of additional senior unsecured notes in the aggregate amount of $500.0 million. On April 27, 2012, we entered into the fourth amendment to our senior secured credit facility, which increased the total potential capacity up to $2.0 billion. In addition, the lenders approved an increase in the borrowing base to $910.0 million, which was reduced by $125.0 million to $785.0 million in the fourth amendment as a result of the issuance of the $500.0 million 2022 senior unsecured notes.
Refer to Note C of our audited consolidated financial statements included in the 2011 Annual Report and Note C of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion of our senior secured credit facility.
Senior unsecured notes. On January 20, 2011 and October 19, 2011, Laredo Petroleum, Inc. completed the offerings of $350 million principal amount and $200 million principal amount, respectively, of 91/2% senior unsecured notes due 2019. The 2019 senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 91/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. Our 2019 senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and its subsidiaries (other than Laredo Petroleum, Inc.) (collectively, the "guarantors"). Our 2019 senior unsecured notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank, National Association, as trustee, and the guarantors. The indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our 2019 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the indenture. Refer to Note C of our audited consolidated financial statements included in the 2011 Annual Report for further discussion of our 2019 senior unsecured notes.
On April 27, 2012, Laredo Petroleum, Inc. completed an offering of $500 million aggregate principal amount of 73/8% senior unsecured notes due 2022. The 2022 senior unsecured notes will mature on May 1, 2022 and bear an interest rate of 73/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The 2022 senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and the guarantors. Our 2022 senior unsecured notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 indenture"), among Laredo Petroleum, Inc., Wells Fargo Bank, National Association, as trustee, and the guarantors. The 2012 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our 2022 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 indenture. The net proceeds from the 2022 senior unsecured notes were used (i) to pay in full $280.0 million outstanding under our senior secured credit facility, and (ii) for general working capital purposes. Refer to Note C to our unaudited consolidated financial statements presented elsewhere in this Quarterly Report on Form 10-Q for additional information regarding the 2022 senior unsecured notes. As of August 7, 2012, we had a total of $1.05 billion of senior unsecured notes outstanding.
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Obligations and commitments
As of June 30, 2012, our contractual obligations included our senior secured credit facility, our 2019 senior unsecured notes, our 2022 senior unsecured notes, drilling rig commitments, derivative financial instruments, asset retirement obligations and office and equipment leases. From December 31, 2011 to June 30, 2012, the material changes in our contractual obligations included (i) a decrease of $85.0 million due to payments made on our senior secured credit facility, (ii) a decrease of $26.1 million on our principal and interest obligation for the 2019 senior unsecured notes as a semi-annual interest payment was made in February 2012, as well as an increase of $868.8 million for the total principal and interest obligation related to the issuance of our $500 million 2022 senior unsecured notes, (iii) an increase of $26.2 million for short-term drilling rig commitments (on contracts other than those on a well-by-well basis) as we continue to pursue our drilling program, (iv) an addition of approximately $6.2 million for the estimated total liability payable for our performance unit awards as of June 30, 2012, which will be payable in December 2014 and (v) an increase of $2.8 million in our total asset retirement obligation due to an increase in the drilling and addition of new wells with associated asset retirement costs.
Refer to Notes B, C and I to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional discussion of our asset retirement obligations, performance unit awards, long-term debt and drilling contract commitments.
Non-GAAP financial measures
The non-GAAP financial measure of Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depreciation, depletion and amortization, impairment of long-lived assets, write-off of deferred loan costs and other, gains or losses on sale of assets, unrealized gains or losses on derivative financial instruments, realized losses on interest rate swaps, realized gains or losses on canceled derivative financial instruments, non-cash stock-based compensation and income tax expense or benefit. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use, because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management team believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:
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There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA reported by different companies and our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.
The following presents a reconciliation of net income to Adjusted EBITDA:
Plus:
Impairment of long-lived assets
Unrealized (gains) losses on derivative financial instruments
Realized losses on interest rate derivatives
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our unaudited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited consolidated financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements.
In management's opinion, the more significant reporting areas impacted by our judgments and estimates are the choice of accounting method for oil and natural gas activities, estimation of oil and natural gas reserve quantities and standardized measure of future net revenues, revenue recognition, impairment of oil and natural gas properties, asset retirement obligations, valuation of derivative financial instruments, valuation of stock-based compensation and performance unit compensation, and
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estimation of income taxes. Management's judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2012; however, we have implemented additional critical accounting policies and procedures related to the 2012 issuances of our stock options and performance unit awards as discussed below. For our other critical accounting policies and procedures below, please see our disclosure of critical accounting policies in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 2011 Annual Report.
Stock-based compensation. Under the modified prospective accounting approach, we measure stock-based compensation expense at the grant date based on the fair value of an award and recognize the compensation expense on a straight-line basis over the service period, which is usually the vesting period. The fair value of the awards is based on the value of our common stock on the date of grant. The determination of the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and forfeiture rate assumptions. Beginning in the first quarter of 2012, we utilized the Black-Scholes option pricing model to measure the fair value of stock options granted under our 2011 Omnibus Equity Incentive Plan. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee. Refer to Note D of our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information regarding our stock-based compensation.
Performance unit compensation. For performance unit awards issued to management in 2012, we utilized a Monte Carlo simulation prepared by an independent third party to determine the fair value of the awards at the date of grant and to re-measure the fair value at the end of each reporting period until settlement in accordance with GAAP. Due to the relatively short trading history for our stock, the volatility criteria utilized in the Monte Carlo simulation is based on the volatilities of a group of peer companies that have been determined to be most representative of our expected volatility. The performance unit awards are classified as liability awards as they have a combination of performance and service criteria and will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense for each period for these awards is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. Compensation expense for the performance units is included in "General and administrative" expense in our consolidated statements of operations with the corresponding liability recorded in the "Other long-term liabilities" section of our consolidated balance sheet. As there are inherent uncertainties related to the factors and our judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the member of management.
See Note B to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for a discussion of additional accounting policies and estimates made by management.
Recent accounting pronouncements
In December 2011, the FASB issued Accounting Standards Update ("ASU") 2011-11, Disclosures about Offsetting Assets and Liabilities, which requires disclosure of both gross information and net information about derivative instruments and transactions eligible for offset in the statement of
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financial position and instruments and transactions subject to an agreement similar to master netting arrangements. This information will enable users of an entity's financial statements to evaluate the effect or potential effect of netting arrangements on an entity's financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments within the scope of the update.
The update is effective for annual periods beginning on or after January 1, 2013, and interim periods within those annual periods and is to be applied retrospectively for all comparative periods presented. We do not expect the adoption of this ASU to have a material effect on our consolidated financial statements.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than operating leases, which are included in "—Obligations and commitments."
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure. For a discussion of how we use financial commodity put, collar, swap and basis swap contracts to mitigate some of the potential negative impact on our cash flow caused by changes in oil and natural gas prices, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Hedging." The key terms to all our oil and natural gas derivative financial instruments as of June 30, 2012 are presented in Note F to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.
Interest rate risk. Our senior secured credit facility bears interest at a floating rate. At June 30, 2012, we had no indebtedness outstanding on our senior secured credit facility.
Through interest rate derivative contracts, we have attempted to mitigate our exposure to changes in interest rates. We have entered into various fixed interest rate swaps and a cap agreement which hedge our exposure to interest rate variations on our senior secured credit facility. At June 30, 2012, we had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% and terms expiring in September 2013.
Counterparty and customer credit risk. Our principal exposures to credit risk are through receivables resulting from derivatives financial contracts (approximately $33.4 million at June 30, 2012), joint interest receivables (approximately $31.1 million at June 30, 2012) and the receivables from the sale of our oil and natural gas production (approximately $38.9 million at June 30, 2012), which we market to energy marketing companies and refineries.
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of our derivative counterparties, who are each lenders in our senior secured credit facility. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.
Refer to Note I of our audited consolidated financial statements included in the 2011 Annual Report for additional disclosures regarding credit risk.
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Item 4. Controls and Procedures
Evaluation of disclosure controls and procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of June 30, 2012, to provide reasonable assurance that the information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Evaluation of changes in internal control over financial reporting. There were no changes in our internal control over financial reporting during the quarter ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II
Item 1. Legal Proceedings
From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, we are not party to any legal proceedings which we currently believe will have a material adverse effect on our business, financial position, results of operations or liquidity.
Item 1A. Risk Factors
As of the date of this filing, Laredo and its operations continue to be subject to the risk factors previously disclosed in "Item 1A. Risk Factors" in the 2011 Annual Report and "Item 1A. Risk Factors" in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Item 6. Exhibits
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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EXHIBIT INDEX
63
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