Linn Energy, LLC 10-Q 2007
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
As of July 31, 2007, there were 65,629,506 units outstanding.
TABLE OF CONTENTS
GLOSSARY OF TERMS
As commonly used in the oil and gas industry and as used in this Quarterly Report on Form10-Q, the following terms have the following meanings:
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.
Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dth. One decatherm, equivalent to one million British thermal units.
Developed acres. Acres spaced or assigned to productive wells.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
FERC. Federal Energy Regulatory Commission.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMboe. One million barrels of oil equivalent determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.
MMcfe/d. One MMcfe per day.
MMMBtu. One billion British thermal units.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.
NYMEX. The New York Mercantile Exchange.
Oil. Crude oil, condensate and natural gas liquids.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved reserves. Proved oil and gas reserves are the estimated quantities of gas, natural gas liquids and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. The definition of proved reserves is in accordance with the Securities and Exchange Commissions definition set forth in Regulation S-X Rule 4-10(a) and its subsequent staff interpretations and guidance.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Standardized Measure. Standardized Measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Linn Energy Holdings, LLC, which is not subject to income taxes.
Successful well. A well capable of producing oil and/or gas in commercial quantities.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
Unproved reserves. Lease acreage on which wells have not been drilled and where it is either probable or possible that the acreage contains reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Operations on a producing well to restore or increase production.
LINN ENERGY, LLC
The accompanying notes are an integral part of these condensed consolidated financial statements.
The accompanying notes are an integral part of these condensed consolidated financial statements.
LINN ENERGY, LLC
The accompanying notes are an integral part of these condensed consolidated financial statements.
LINN ENERGY, LLC
The accompanying notes are an integral part of these condensed consolidated financial statements.
LINN ENERGY, LLC
The accompanying notes are an integral part of these condensed consolidated financial statements.
LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES
The accompanying notes are an integral part of these condensed consolidated financial statements.
LINN ENERGY, LLC
(1) Basis of Presentation and Significant Accounting Policies
Linn Energy, LLC (Linn or the Company) is an independent oil and gas company focused on the development and acquisition of long-lived properties in the United States that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005.
The condensed consolidated financial statements at June 30, 2007, and for the three and six months ended June 30, 2007 and 2006, are unaudited, but in the opinion of management include all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with United States generally accepted accounting principles (GAAP) have been condensed or omitted under Securities and Exchange Commission (SEC) rules and regulations. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
The financial information included herein should be read in conjunction with the financial statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2006. Certain amounts in the condensed consolidated financial statements and notes thereto have been reclassified to conform to the 2007 financial statement presentation.
The condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation.
Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these condensed consolidated financial statements in conformity with GAAP. Actual results could differ from those estimates. The estimates that are particularly significant to the financial statements include estimates of oil, gas and natural gas liquid (NGL) reserves, future cash flows from oil and gas properties, depreciation, depletion and amortization, asset retirement obligations, the fair value of derivatives and unit-based compensation expense.
As of June 30, 2007, there have been no significant changes with regard to the critical accounting policies disclosed in the Companys Annual Report on Form 10-K for the year ended December 31, 2006. The policies disclosed included the accounting for oil and gas properties, reserve quantities, revenue recognition, purchase accounting and derivative instruments. Several of our more significant accounting policies are summarized below.
Oil and Gas Properties
The Company accounts for oil and gas properties by the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred. Geological, geophysical, and exploratory dry hole costs on oil and gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
Depreciation and depletion of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Statement of Financial Accounting Standards (SFAS) No. 19, as amended, Financial Accounting and Reporting by Oil and Gas Producing Companies (SFAS 19), requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
Derivative Instruments and Hedging Activities
The Company uses derivative financial instruments to achieve a more predictable cash flow from its oil, gas and NGL production by reducing its exposure to price fluctuations. As of June 30, 2007, these transactions were in the form of swaps and puts. Additionally, the Company uses derivative financial instruments in the form of interest rate swaps to mitigate its interest rate exposure. The Company accounts for its derivatives at fair value as an asset or liability and the change in the fair value of derivatives is included in income. The Company accounts for these activities pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS 133). This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheets as assets or liabilities. None of the Companys commodity or interest rate derivatives are designated as hedges under SFAS 133 and therefore the change in the fair value of the derivatives is included in the condensed consolidated statements of operations. See Note 9 and Note 10 for additional discussion related to derivative financial instruments.
Under the provisions of the Linn Energy, LLC Long-Term Incentive Plan, which is administered by the Compensation Committee of the Board of Directors, the Company has awarded unit grants, unit options, restricted units, and phantom units to employees and non-employee directors. The unit options and restricted units vest ratably over one to three years from the grant date of the award, unless other contractual arrangements are made. The contractual life of unit options is ten years. See Note 12 for details regarding unit-based compensation granted during the six months ended June 30, 2007.
The Company accounts for unit-based compensation under the provisions of SFAS No. 123 (revised 2004), Share Based Payment (SFAS 123R). SFAS 123R requires the recognition of compensation expense, over the requisite service period, in an amount equal to the fair value of unit-based payments granted.
Recently Issued Accounting Standards
In June 2007, the Financial Accounting Standards Board (FASB) ratified the consensus in Emerging Issues Task Force Issue 06-11 (EITF 06-11). EITF 06-11 is effective for fiscal years beginning after December 15, 2007 and requires, among other things, recognition as an increase to additional paid-in capital the realized income tax benefit from dividends or dividend equivalents that are paid to employees and charged to retained earnings. The Company is in the process of evaluating the impact of EITF 06-11 on its results of operations and financial position, but does not expect it will be material.
In April 2007, the FASB issued Staff Position No. 39-1, Amendment of FASB Interpretation No. 39 (FSP No. FIN 39-1). The terms conditional contracts and exchange contracts have been replaced with the more general term derivative contracts. In addition, FSP No. FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a Companys accounting policy with respect to offsetting fair value amounts. The guidance in FSP No. FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. The Company
does not believe that the adoption of FSP No. FIN 39-1 will have a material impact on its results of operations or financial position.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115 (SFAS 159), which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of SFAS 159 is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of SFAS 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. The Company is currently evaluating what impact, if adopted, SFAS 159 may have on its results of operations or financial position.
(2) Acquisitions and Dispositions
On February 1, 2007, effective January 1, 2007, the Company completed the acquisition of certain oil and gas properties and related assets in the Texas Panhandle from Stallion Energy LLC, acting as general partner for Cavallo Energy, LP, for $415.0 million, subject to customary closing adjustments (Panhandle I). The Panhandle I acquisition was financed with a combination of a private placement of our units (see Note 3) and borrowings under the Companys senior secured revolving credit facility (see Note 6).
On June 12, 2007, effective April 1, 2007, the Company completed the acquisition of certain oil and gas properties in the Texas Panhandle for $90.5 million, subject to customary closing adjustments (Panhandle II). The acquisition was financed with borrowings under the Companys senior secured revolving credit facility.
The following table presents the preliminary purchase prices for the Panhandle I and Panhandle II acquisitions based on preliminary estimates of fair value:
The following table presents the preliminary allocation of the purchase prices based on preliminary estimates of fair value:
The preliminary purchase price allocations are based on discounted cash flows, independent appraisals of fixed assets, quoted market prices and estimates by management. The most significant assumptions are related to the estimated fair values assigned to proved oil and gas properties. To estimate the fair values of these properties, we utilized estimates of oil, gas and NGL reserves prepared by an independent engineering firm. We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate was subjected to additional project-specific risk factors. There were no fair values assigned to unproved properties with the Texas Panhandle acquisitions. As noted, the purchase price allocations are preliminary; they are subject to final closing adjustments and will be finalized within one year of the acquisition dates.
The following unaudited pro forma financial information presents a summary of Linns consolidated results of operations for the three and six months ended June 30, 2007 and 2006, assuming the Panhandle I and Panhandle II acquisitions had been completed as of January 1, 2006, including adjustments to reflect the allocation of the purchase prices to the acquired net assets. The pro forma financial information also assumes the Companys February 2007 private placement of units (see Note 3) was completed on January 1, 2006, since the private placement was contingent on completion of the Panhandle I acquisition. In addition, the pro forma financial information assumes that our California acquisitions of certain affiliated entities of Blacksand Energy, LLC and certain Oklahoma assets of the Kaiser-Francis Oil Company were completed as of January 1, 2006. The California and Oklahoma acquisitions were completed in 2006 and the revenues and expenses are included in the consolidated results of the Company effective August 1, 2006 and September 1, 2006, respectively. The revenues and expenses of the Panhandle I and Panhandle II assets are included in the consolidated results of the Company as of February 1, 2007 and June 12, 2007, respectively. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.
The 2006 pro forma results of operations present net income per unit allocated to the units and Class C units. In April 2007, unitholders approved the one-for-one conversion of each of the Class C units into units (see Note 3). Therefore, pro forma net income per unit assumes that the units and Class C units share equally in the pro forma net income of the Company.
In January 2007, the Company completed the acquisitions of certain gas properties located in the Appalachian Basin of West Virginia for an aggregate price of $39.0 million, subject to customary closing adjustments.
In March 2007, the Company sold certain of its oil and gas properties located in New York for cash of approximately $2.5 million and recorded a gain of approximately $0.9 million. The gain is included in other revenues on the condensed consolidated statements of operations.
On June 29, 2007, the Company entered into a definitive purchase agreement with Dominion Resources, Inc. and certain affiliates (Dominion) to acquire certain oil and gas properties in the Mid-Continent, in Oklahoma, Kansas and the Texas Panhandle (the Mid-Continent Acquisition) for $2.05 billion, subject to customary closing adjustments. The Company anticipates that the Mid-Continent Acquisition will close during the third quarter of 2007, subject to customary closing conditions, including the Companys receipt of financing. There can be no assurance that all of the conditions to closing will be satisfied. On June 29, 2007, the Company executed a unit purchase agreement for a private placement of $1.5 billion of units and Class D units to a group of institutional investors (see Note 3). In addition, on June 29, 2007, the Company received a commitment from two lenders under its credit facility (see Note 6) to provide funding of up to $1.9 billion contingent on closing of the Mid-Continent Acquisition. The Company intends to fund the Mid-Continent Acquisition with the net proceeds from the private placement, together with borrowings under the credit facility.
On August 2, 2007, the Company entered into a definitive purchase agreement to acquire certain oil and gas properties in the Texas Panhandle (the Panhandle III Acquisition) for $22.5 million, subject to customary closing adjustments. The Company anticipates that the Panhandle III Acquisition will close during the third quarter of 2007, subject to customary closing conditions.
(3) Unitholders Capital
Pending Private Placement
On June 29, 2007, the Company executed a unit purchase agreement for a private placement of $1.5 billion of units to a group of institutional investors, consisting of 34,997,005 Class D units at a price of $30.97 per unit and 12,999,989 units at a price of $32.00 per unit (Pending Private Placement). Proceeds, net of expenses, will be used to fund the Mid-Continent Acquisition (see Note 2). The Pending Private Placement is expected to coincide with the closing of the Mid-Continent Acquisition and is subject to customary closing conditions, including the closing of the Mid-Continent Acquisition. There can be no assurance that all of the conditions to closing will be satisfied.
The Class D units will represent a class of equity securities that is entitled to a special quarterly distribution equal to 115% of the distribution received by the holders of units, has no voting rights other than as required by law and is subordinated to the units on dissolution and liquidation. The Class D units may convert into units if the conversion is approved by a vote of the Companys unitholders. The Company has agreed to hold a meeting of its unitholders to consider this proposal as soon as reasonably practicable, but no later than 120 days from the closing date. In connection with the Pending Private Placement, the Company also agreed to file a registration statement with the SEC covering the units and the Class D units, and that the registration statement would be declared effective by the SEC no later than 165 days following the closing.
June 2007 Private Placement
In June 2007, the Company closed its private placement of $260.0 million of units to a group of institutional investors, consisting of 7,761,194 units at a price of $33.50 per unit (the June 2007 Private Placement). Proceeds, net of expenses, were $255.4 million and were used to repay indebtedness under the Companys senior secured revolving credit facility (see Note 6). In connection with the June 2007 Private Placement, the Company also agreed to file a registration statement with the SEC covering the units, and that the registration statement would be declared effective by the SEC no later than November 13, 2007.
February 2007 Private Placement
In February 2007, the Company entered into a Class C Unit and Unit Purchase Agreement with a group of institutional investors whereby it privately placed 7,465,946 Class C units at a price of $25.06 per unit, and 6,650,144 units at a price of $26.00 per unit, for aggregate gross proceeds of $360.0 million (the February 2007 Private Placement). Proceeds, net of expenses, were $353.1 million. The proceeds from the February 2007 Private Placement were used to finance the Panhandle I acquisition and the acquisitions of certain gas properties in West Virginia (see Note 2).
In April 2007, at a special meeting of Linn unitholders, unitholders approved the one-for-one conversion of the Class C units into units. In connection with the February 2007 Private Placement, the Company agreed to file a registration statement with the SEC covering the units and the units underlying the Class C units, and that the registration statement would be declared effective by the SEC no later than 165 days following the closing. In June 2007, this deadline was extended to December 31, 2007.
October 2006 Private Placement
In connection with its October 2006 private placement of Class B units (the October 2006 Private Placement), the Company also agreed to file a registration statement with the SEC covering the units and the units underlying the Class B units, and that the registration statement would be declared effective by the SEC no later than 165 days following the closing. In June 2007, this deadline was extended to December 31, 2007.
The Company could be required to pay purchasers liquidated damages specified in agreements pursuant to the October 2006, February 2007 and June 2007 Private Placements and the Pending Private Placement in the event the registration effectiveness deadlines are not met. The potential payments under the agreements are 0.25% of the gross proceeds for each 30 day period that the registration deadlines are not met, up through 90 days. Subsequent to 90 days, the potential payments would increase for each 30 day period, up to a maximum of 1.0% of the gross proceeds of each offering. The Company does not believe it is probable that it will be required to make such payments; therefore, has not recorded a liability at this time. The Company will continue to monitor and assess its exposure in this matter; however, the Company does not currently expect payments, if any, under these agreements to be material to the Companys financial position or results of operations.
Cancellation of Units
In January 2007, the Company purchased 226,561 restricted units from an employee for $7.4 million (market price on the day of purchase) in conjunction with the vesting of restricted unit awards. The proceeds were used to fund the employees payroll taxes on the award and the Company cancelled the units.
Initial Public Offering
In the first quarter of 2006, the Company completed its initial public offering (IPO) of 12,450,000 units representing limited liability company interests in the Company at $21.00 per unit, for net proceeds, after underwriting discounts of $18.3 million and offering expenses of $4.3 million, of $238.8 million, of which $122.0 million was used to reduce indebtedness, $114.4 million was used to redeem a portion of the membership interests in the Company and units held by certain affiliated and non-affiliated holders and approximately $2.0 million was used to pay bonuses to certain executive officers of the Company.
(4) Oil and Gas Capitalized Costs
Aggregate capitalized costs related to oil, gas and NGL production activities with applicable accumulated depreciation, depletion and amortization are presented below:
(5) Property and Equipment
Property and equipment consists of the following:
Depreciation expense for the three and six months ended June 30, 2007, was approximately $0.8 million and $1.5 million, respectively. Depreciation expense for the three and six months ended June 30, 2006, was approximately $0.2 million and $0.4 million, respectively.
(6) Credit Facility
At June 30, 2007, the Company had an $800.0 million senior secured revolving credit facility with a maturity of August 2010, and a borrowing base of $765.0 million (Credit Facility). On June 29, 2007, the Company received a commitment from two lenders under its Credit Facility to provide funding of up to $1.9 billion contingent on closing of the Mid-Continent Acquisition (see Note 2). In July 2007, the Company incurred approximately $4.8 million in commitment fees that will be amortized over the life of this debt agreement.
The borrowing base under the Credit Facility will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the oil, gas and NGL prices at such time. Our obligations under the Credit Facility are secured by mortgages on our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. We are required to maintain the mortgages on properties representing at least 80% of our oil and gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries.
At our election, interest on borrowings under the Credit Facility is determined by reference to LIBOR plus an applicable margin between 1.00% and 1.75% per annum; or a domestic bank rate plus an applicable margin between 0.00% and 0.25% per annum. Interest is payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.
The Credit Facility contains various covenants that limit the Companys ability to incur additional indebtedness, make acquisitions or certain capital expenditures; make distributions other than from available cash; merge or consolidate; and engage in certain asset dispositions. The Credit Facility also contains covenants that, among other things, require us to maintain certain financial ratios. The Company is in compliance with all financial and other covenants of its Credit Facility.
As of June 30, 2007 and December 31, 2006, the Credit Facility consisted of the following:
(1) Variable rate of 6.625% and 7.125% at June 30, 2007 and December 31, 2006, respectively.
At June 30, 2007, the Company also had $5.0 million outstanding letters of credit, which reduce its borrowing availability under the Credit Facility. At June 30, 2007, available borrowing under the Credit Facility was $284.0 million.
(7) Long-term Notes Payable
The Company has the following long-term notes payable outstanding:
(1) At June 30, 2007 and December 31, 2006, includes approximately $1.0 million of notes payable on which interest was imputed at 7.0%.
As of June 30, 2007, maturities on the aforementioned long-term notes payable were as follows:
(8) Business and Credit Concentrations
The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.
Revenue and Trade Receivables
The Company has a concentration of customers who are engaged in oil and gas production within the United States. This concentration of customers may impact the Companys overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Companys customers consist primarily of major oil and gas purchasers and the Company generally does not require collateral.
A majority of the Companys largest customers are oil and gas producers, suppliers and operators. For the three and six months ended June 30, 2007, the Companys three largest customers represented approximately 28%, 22% and 13%, and 32%, 18% and 12%, respectively, of the Companys sales. For the three and six months ended June 30, 2006, the Companys two largest customers represented approximately 65% and 9%, and 68% and 10%, respectively, of the Companys sales.
At June 30, 2007, three customers trade accounts receivable from oil, gas and NGL sales accounted for more than 10% of the Companys total trade accounts receivable. At June 30, 2007, trade accounts receivable from these customers represented approximately 24%, 18% and 16% of the Companys receivables. At December 31, 2006, three customers trade accounts receivable from oil and gas sales accounted for more than 10% of the Companys total trade accounts receivable. As of December 31, 2006, trade accounts receivable from these customers represented approximately 41%, 22% and 16% of the Companys receivables.
(9) Commitments and Contingencies
The Company would be exposed to oil, gas and NGL price fluctuations on underlying sale contracts should the counterparties to the Companys derivative instruments or the counterparties to the Companys oil, gas and NGL marketing contracts not perform. Such non-performance is not anticipated. There were no counterparty default losses during the three or six months ended June 30, 2007 or 2006.
In June 2007, the Company entered into an agreement and paid $0.4 million to cancel future lease obligations totaling $1.1 million related to an office facility in Pennsylvania.
From time to time the Company is a party to various legal proceedings or is subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a materially adverse effect on the Companys business, financial condition, results of operations or liquidity.
In July 2007, the Company entered into hedging contracts to reduce oil and gas price risk exposures related to its pending Mid-Continent Acquisition (see Note 2). The contracts cover 40 Bcf of gas and 800,000 Bbls of oil per year for 2008 through 2012 and 7.8 Bcf of gas and 157,000 Bbls of oil for the fourth quarter of 2007. The contracts include deferred premium puts entered into in July 2007, for which the Company will pay the counterparty approximately $132.2 million in October 2007. In addition, the contracts include a deal-contingent option to enter into oil and gas swaps upon consummation of the Mid-Continent Acquisition for which the Company expects to pay commitment fees and premiums totaling approximately $71.9 million to the counterparty. The Companys commitment to enter into the swaps is contingent on the closing of the Mid-Continent Acquisition.
The Company sells oil, gas and NGL in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in oil, gas and NGL. The Company enters into derivative instruments such as swap contracts and put options to hedge a portion of its forecasted oil, gas and NGL sales. Oil derivatives are used to hedge oil and NGL sales.
Settled derivatives on gas production for the three and six months ended June 30, 2007, included a volume of 4,675 MMBtu and 9,369 MMBtu at an average contract price of $8.43 and $8.43, respectively. Settled derivatives on oil and NGL production for the three and six months ended June 30, 2007 included a volume of 500 MBbls and 892 MBbls at an average contract price of $68.71 and $69.16, respectively. The gas derivatives are settled based upon the closing NYMEX or Henry Hub future price of gas on the settlement date, which occurs on the third day preceding the production month. The oil transactions are settled based upon the average months daily NYMEX price of light oil and settlement occurs on the final day of the production month.
The following tables summarize open positions as of June 30, 2007 and represent, as of such date, our derivatives in place through December 31, 2011, on annual production volumes:
The oil and gas derivatives are not designated as cash flow hedges under SFAS 133, and, accordingly, the changes in fair value are recorded in current period earnings.
The following table presents the outstanding notional amounts and maximum number of months outstanding of our derivatives:
By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of 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 minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties.
In July 2007, the Company entered into additional hedging contracts to reduce oil and gas price risk exposures related to its pending Mid-Continent Acquisition (see Note 9).
(11) Earnings Per Unit
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect in accordance with SFAS No. 128, Earnings Per Share.
The following reconciliation presents the impact on the unit amounts of potential unit equivalents and the earnings per unit amounts:
(1) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money unit options and warrants, and unvested restricted units of 514,406 and 398,755 for the three and six months ended June 30, 2007, respectively. Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money unit options and unvested restricted units of 8,041 and 21,383 for the three and six months ended June 30, 2006, respectively. All equivalent units are anti-dilutive for the three and six months ended June 30, 2007 as the Company reported a net loss from operations.
(12) Unit-Based Compensation
During the six months ended June 30, 2007, the Company granted an aggregate 400,500 restricted units to employees as part of its annual review of employee compensation and 118,500 restricted units to new employees of the Company with an aggregate fair value of approximately $17.0 million. In addition, during the six months ended June 30, 2007, the Company granted 108,000 unit options to new employees of the Company with a fair value of approximately $0.6 million. The majority of these restricted units and options vest ratably over three years.
For the three and six months ended June 30, 2007, the Company recorded unit-based compensation expense of approximately $3.1 million and $6.3 million, respectively, as a charge against income before income taxes and it is included in general and administrative expenses on the condensed consolidated statements of operations. For the three and six months ended June 30, 2006, the Company recorded unit-based compensation expense of approximately $4.2 million and $9.9 million, respectively.
In February 2007, the Company granted an aggregate 150,000 unit warrants to certain individuals in connection with a transition services agreement entered into with the Panhandle I acquisition (see Note 2). The unit warrants have an exercise price of $25.50 per unit warrant, may be exercised in whole or in-part on or after December 13, 2007, and expire ten years from issuance. In accordance with SFAS 123R, the Company computed the fair value of the unit warrants using the Black-Scholes model. At June 30, 2007, the aggregate fair value of the unit warrants was approximately $1.4 million and the expense was recognized over the five month term of the agreement through June 30, 2007. For the three and six months ended June 30,
2007, the Company recorded general and administrative expenses of approximately $0.9 million and $1.4 million, respectively, as a charge against income before income taxes.
(13) Income Taxes
The Company is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of the Company passed through to the Companys unitholders. As such, no recognition of federal or state income taxes for the Company or its subsidiaries that are organized as limited liability companies have been provided for in the accompanying financial statements, except as described below.
Certain of the Companys subsidiaries are Subchapter C-corporations subject to corporate income taxes, which are accounted for under the provisions of SFAS No. 109 Accounting for Income Taxes (SFAS 109), which uses the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. At June 30, 2007, deferred tax liabilities of approximately $0.8 million are recorded on the condensed consolidated balance sheets and deferred tax assets of $4.5 million, net of a valuation allowance of $3.7 million are also recorded. At December 31, 2006, deferred tax liabilities of approximately $0.7 million are recorded on the condensed consolidated balance sheets and deferred tax assets of $6.3 million, net of a valuation allowance of $2.3 million are also recorded.
The Company adopted Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109 (FIN 48) on January 1, 2007. FIN 48 requires that the Company recognize only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. It also requires expanded financial statement disclosure of such positions.
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. As of June 30, 2007, the Company had no material uncertain tax positions.
(14) Related Party Transactions
During the three and six months ended June 30, 2006, the Company made payments of approximately $0.2 million to a company owned by one of our senior executives. The payments reflect reimbursement for maintenance and hourly usage fees for business use of an aircraft that was partially owned by the senior executive. These costs are included in general and administrative expenses on the condensed consolidated statements of operations. The fees and expenses associated with the reimbursements were consummated on terms equivalent to those that prevail in arms-length transactions. In the third quarter of 2006, the Company purchased an ownership interest in an airplane for corporate travel from a third party; therefore, these reimbursements ended. Simultaneous with this transaction, the senior executive was able to fully liquidate the investment in the aircraft owned by his company.
We are an independent oil and gas company focused on providing stability and growth in distributions to our unitholders through continued successful drilling, acquisitions, increasing production of existing wells and pursuing operational and administrative efficiencies. Our properties and our oil, gas and NGL reserves are currently located in three core areas:
· Appalachian Basin, which includes West Virginia, Pennsylvania and Virginia;
· Western, which includes the Brea Olinda Field of the Los Angeles Basin in California; and
· Mid-Continent, which includes the Sooner Trend of north central Oklahoma and the Texas portion of the Hugoton-Panhandle Field.
The following table provides a summary of our significant oil and gas property acquisitions through the date of this report:
* Includes the pending Mid-Continent Acquisition and Panhandle III Acquisition. The Company anticipates that these acquisitions will close during the third quarter of 2007, subject to customary closing conditions. See Note 2 in Notes to Condensed Consolidated Financial Statements for details about these pending acquisitions and acquisitions completed during the six months ended June 30, 2007.
From inception through June 30, 2007, we have completed 18 significant acquisitions of oil and gas properties and related gathering and pipeline assets for an aggregate purchase price of approximately $1.2 billion, with total proved reserves of approximately 815.5 Bcfe, or an acquisition cost of approximately $1.47 per Mcfe. Including preliminary estimates for the pending Mid-Continent Acquisition and Panhandle III Acquisition, our acquisitions would include proved reserves of approximately 1,588.8 Bcfe at an aggregate purchase price of approximately $3.3 billion, or an acquisition cost of approximately $2.06 per Mcfe.
Our acquisitions are financed with a combination of private placements of our units, proceeds from bank borrowings and cash flow from operations. Our activities are focused on evaluating and developing our asset base, increasing our acreage positions and evaluating potential acquisitions. Because of our rapid growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.
Our revenues are highly sensitive to changes in oil, gas and NGL prices and levels of production. We typically seek to hedge a significant portion of our anticipated future production volumes to reduce commodity price volatility risk. Managing this volatility, which we believe is likely to continue in the future, provides a longer-term stability
of cash flows. Currently, we use fixed price swaps and puts to reduce our exposure to the volatility in oil, gas and NGL prices. As of the date of this report, we have hedged a significant portion of our expected production through 2012 using derivatives, which allows us to mitigate, but not eliminate, commodity price risk. See Item 3. Quantitative and Qualitative Disclosures About Market Risk for details about our derivatives in place through December 31, 2012.
Drilling and Operations
We concentrate our drilling activity on lower risk, development properties. The number, types, and location of wells we drill varies depending on our capital budget, the cost of each well, anticipated production and the estimated recoverable reserves attributable to each well. Historically, until 2007, most of our drilling has been in the Appalachian Basin. With our February 2007 Panhandle I and June 2007 Panhandle II acquisitions, our drilling program has been expanded to the Texas Panhandle and the Sooner Trend of Oklahoma. Our expected increase in levels of production as a result of the anticipated drilling of over 250 wells during 2007 is dependent on our ability to quickly and efficiently bring the newly drilled wells online, pipeline capacity and favorable weather conditions. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of increase in our production, which may have an adverse effect on our revenues and as a result, cash available for distribution.
Higher oil, gas and NGL prices have led to higher demand for operating personnel and field supplies and services and have caused increases in the costs of those goods and services. In the Appalachian Basin, during 2006, the Company took delivery of its first two drilling rigs, with an additional rig delivered on March 30, 2007, which has reduced our reliance on contract rigs in that core area. The Companys drilling subsidiary performs certain services, including preparing and clearing well sites, providing drilling engineers, roustabouts and other personnel, for the Companys drilling program and for third parties. We focus our efforts on increasing oil, gas and NGL reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations is dependent on our ability to manage our overall cost structure.
We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil, gas or NGL production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through drilling and acquisitions as well as managing the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals.
Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other producers. Oil, gas and NGL prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil, gas or NGL could materially and adversely affect our financial position, our results of operations, the quantities of productive reserves that we can economically produce and our access to capital. See Cautionary Statement below in this Item 2. for additional information about risks related to our Company.
Results of Operations - Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006
(1) Includes the effect of realized gains of $7.2 million and $5.8 million on derivatives for the three months ended June 30, 2007 and 2006, respectively.
(2) Our oil production in California is sold pursuant to a long-term contract at 79% of NYMEX, and with gravity increase due to NGL being mixed into the oil stream, prices realized average approximately 82% of NYMEX.
(3) This is a non-GAAP performance measure used by our management and is a quantitative measure used in the oil and gas industry. The measure for the three months ended June 30, 2007 and 2006 excludes approximately $4.0 million and $4.2 million, respectively, of unit-based compensation expense and unit warrant expense. General and administrative expenses including these amounts were $2.01 per Mcfe and $3.54 per Mcfe for the three months ended June 30, 2007 and 2006, respectively.
* Not meaningful.
Gas, oil and NGL sales increased 264%, to approximately $49.2 million for the three months ended June 30, 2007, from $13.5 million for the three months ended June 30, 2006.
The increase in revenue from gas, oil and NGL sales was primarily attributable to increased production. Total production increased to 6,245 MMcfe during the three months ended June 30, 2007, from 1,956 MMcfe during the three months ended June 30, 2006. Gas production increased to 3,518 MMcf during the three months ended June 30, 2007, from 1,914 MMcf during the three months ended June 30, 2006. The increase in gas production was due to the drilling of new wells and production added by the acquisitions of oil and gas properties during 2007 and 2006. The Company drilled 72 wells during the three months ended June 30, 2007, compared to 55 wells during the three months ended June 30, 2006. Oil production increased to 251 MBbls during the three months ended June 30, 2007, from 7 MBbls during the during the three months ended June 30, 2006, due to the California, Panhandle I and Panhandle II acquisitions in August 2006, February 2007 and June 2007, respectively. The acquisitions in the Texas Panhandle also increased NGL production to 203 MBbls during the three months ended June 30, 2007, from zero during the comparative period of the prior year.
During the three months ended June 30, 2007, we entered into commodity pricing derivative contracts for approximately 133% of our gas production and 110% of our oil and NGL production, which resulted in realized gains of $7.2 million (revenues greater than we would have achieved at unhedged prices). The calculation of the percentage hedged for the three months ended June 30, 2007 includes an adjustment to reflect Panhandle I production, which was hedged, but was not included in the Companys reported production. It was instead recorded as a purchase price adjustment (see Note 2 in Notes to Condensed Consolidated Financial Statements). During the three months ended June 30, 2006, we entered into commodity pricing derivative contracts for approximately 95% of our gas production, which resulted in realized gains of $5.8 million. Unrealized losses on derivatives in the amount of $24.9 million for the three months ended June 30, 2007, and unrealized gains of $7.1 million for the three months ended June 30, 2006, were also recorded. Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract price on the derivative. During the quarter, short-term oil and gas prices increased, which reduced the market value of the derivatives. Such market value adjustment, if realized in the future, would be offset by higher actual prices for our production.
Operating expenses include lease operating expenses, labor, field office expenses, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies and severance and ad valorem taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. We assess our operating expenses by monitoring the expenses in relation to the amount of production and the number of wells operated. Operating expenses increased to $14.7 million for the three months ended June 30, 2007, from $2.9 million for the three months ended June 30, 2006, due to the increase in the number of producing wells as a result of the acquisitions completed in 2007 and in 2006 and the drilling of 72 wells in the three months ended June 30, 2007, and 472 wells from inception through June 30, 2007.
In addition, our average operating expenses per equivalent unit of production increased to $2.36 for the three months ended June 30, 2007, compared to $1.50 for the three months ended June 30, 2006, due to increased material and labor costs and the changing mix of production beginning in the third quarter of 2006 to include oil and NGL, which have higher operating costs than our gas wells. Finally, we have incurred costs in 2007 for workover and maintenance of our wells to enhance future production and/or offset decline.
General and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. General and administrative expenses increased to approximately $12.5 million for the three months ended June 30, 2007, from $6.9 million for the three months ended June 30, 2006. The increase in general and administrative expenses was primarily due to costs incurred to support our rapid growth through acquisitions and position the Company for future growth. In conjunction with expansion and development of our operations team, to date during 2007, we have hired
approximately 40 employees and as a result, salaries and benefits expense increased approximately $1.7 million over the comparable quarter of 2006. We also incurred approximately $1.3 million in expenses for services performed by third-parties pursuant to a transition services agreement associated with the Panhandle I properties (see Note 2 in Notes to Condensed Consolidated Financial Statements). This services agreement terminated effective June 30, 2007. Costs to perform the necessary functions associated with being a large, growing, public company were $2.1 million during the second quarter of 2007, compared to $1.2 million during the second quarter of 2006. These costs include expenses for recruitment of key management team members, acquisition related data conversion and integration, public partnership tax reporting, audit fees, legal fees, proxy and printing costs and other professional fees, including costs related to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley Act). The Company is currently in the process of implementing and testing procedures and controls in order to comply with the Sarbanes-Oxley Act at December 31, 2007, and as such, expects these costs to continue throughout the remainder of the year. In addition, acquisition costs that are not eligible for capitalization, including internal and indirect costs for completed acquisitions, as well as direct costs associated with acquisition efforts that have not reached fruition, contributed to the increase. The increase in general and administrative expenses was partially offset by lower employee unit-based compensation expense, which decreased to $2.3 million (exclusive of amounts associated with the 40 new employees) during the three months ended June 30, 2007, from $4.2 million during the comparative quarter of 2006. Unit-based compensation expense incurred during the three months ended June 30, 2006 is higher compared to that incurred in the comparative period of 2007, primarily due to expense associated with unit awards granted in conjunction with the Companys IPO in January 2006. General and administrative expenses are presented net of approximately $0.1 million and $0.4 million during the three months ended June 30, 2007 and 2006, respectively, which represent expense reimbursements from other working interest owners.
Depreciation, depletion and amortization increased to approximately $12.9 million for the three months ended June 30, 2007, from $4.1 million for the three months ended June 30, 2006. Of this increase, approximately $5.8 million was as a result of depletion related to the California and Oklahoma acquisitions in the third quarter of 2006 and the Texas acquisitions in the first and second quarters of 2007. Although total depreciation, depletion and amortization increased in the second quarter of 2007 due to higher total production levels, the reserves in our recently acquired Texas, Oklahoma and California properties have lower depletion rates than our reserves in the Appalachian Basin. During the three months ended June 30, 2007 and 2006, the Company capitalized approximately $2.8 million and $0.6 million, respectively, of costs for specific activities related to drilling its wells, which included site preparation, drilling labor, meter installation, pipeline connection and site reclamation. Capitalized drilling costs increased in the three months ended June 30, 2007 due to the Companys purchase and placement of two drilling rigs into service during the third quarter of 2006 and one additional drilling rig in the first quarter of 2007. Company personnel also perform activities using leased equipment, and did so prior to the purchase of its own rigs.
Other income and (expenses) increased to a net expense of $9.8 million for the three months ended June 30, 2007, compared to a net expense of $2.8 million for the three months ended June 30, 2006, primarily due to increased interest expense from increased debt levels associated with acquisitions and drilling. Cash payments for interest increased to $10.3 million for the three months ended June 30, 2007, compared to $1.6 million for the three months ended June 30, 2006. Our interest rate swaps were not designated as hedges under SFAS 133, even though they reduce our exposure to changes in interest rates. Therefore, the changes in fair values of these instruments were recorded as gains of approximately $0.3 million and $0.3 million for the three months ended June 30, 2007 and 2006, respectively. These amounts are non-cash gains.
Income tax was an expense of approximately $30,000 for the three months ended June 30, 2007, compared to a benefit of approximately $0.2 million for the three months ended June 30, 2006. The Companys taxable subsidiaries generated net operating losses for the year ended December 31, 2006. Management has subsequently recovered expenses through an intercompany charge for services from Linn Operating, Inc. to Linn Energy, LLC, which resulted in a corresponding tax expense in the three months ended June 30, 2007.
Results of Operations - Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006