Linn Energy, LLC 10-Q 2006
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2006
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from to
Commission File Number: 000-51719
LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)
(Registrants 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 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).
Large accelerated filer o Accelerated filer o Non-accelerated filer x
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 November 1, 2006, there were 33,417,187 units outstanding.
As of November 1, 2006, there were 9,185,965 class B units outstanding.
TABLE OF CONTENTS
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 natural gas to one Bbl of crude 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.
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 crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
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 natural gas to one Bbl of crude 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.
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 natural gas, natural gas liquids and crude 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.
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 produceable 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 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.
The accompanying notes are an integral part of these condensed consolidated financial statements.
(1) Basis of Presentation
The condensed consolidated financial statements at September 30, 2006, and for the three and nine months ended September 30, 2006 and 2005, 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 U.S. 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, 2005. Certain amounts in the consolidated financial statements and notes thereto have been reclassified to conform to the 2006 financial statement presentation.
(2) Summary of Significant Accounting Policies
Linn Energy, LLC (Linn or the Company) was reorganized as a limited liability company in April 2005 under the laws of the State of Delaware. The Company is an independent oil and gas company focused on the development and acquisition of long-lived properties in the United States. As of September 30, 2006, Linns wholly owned subsidiaries included Linn Energy Holdings, LLC, Linn Energy Mid-Continent Holdings, LLC, Linn Energy Western Holdings, LLC, Linn Operating, Inc., Linn Western Processing, LLC, Penn West Pipeline, LLC, Mid Atlantic Well Service, Inc., Linn Western Operating, Inc., and Linn Mid-Continent Operating, Inc.
(b) Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with GAAP. All material inter-company transactions and balances have been eliminated upon consolidation.
(c) Cash Equivalents
For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
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.
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, 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.
The Company accounts for asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS 143). In accordance with SFAS 143, estimated asset retirement costs are recognized when the obligation is incurred, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by the Companys engineers using existing regulatory requirements and anticipated future inflation rates.
Geological, geophysical, and exploratory dry hole costs on oil and gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income. On sale or retirement of an individual well the proceeds are credited to accumulated depreciation and depletion.
Oil and gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. No impairments were recorded during the three or nine months ended September 30, 2006 or 2005.
Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred. No impairments were recorded during the three or nine months ended September 30, 2006 or 2005.
The Companys estimates of proved reserves are based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. An independent engineering firm prepares a reserve and economic evaluation of all the Companys properties on a well-by-well basis.
Reserves and their relation to estimated future net cash flows impact the Companys depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm noted above adheres to the same guidelines when preparing its reserve reports. The accuracy of the Companys reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
The Companys proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and crude oil eventually recovered.
(f) 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 being passed through to the 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 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. Deferred tax liabilities of approximately $0.3 million and $74,000 are recorded in other long-term liabilities on the consolidated balance sheets at September 30, 2006 and December 31, 2005, respectively. At September 30, 2006, deferred tax assets of approximately $0.3 million, net of a valuation allowance of $1.8 million, are recorded to the extent of existing deferred tax liabilities.
The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its crude oil and natural gas production by reducing its exposure to price fluctuations. As of September 30, 2006, 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.
Under the provisions of SFAS No. 142, Goodwill and Other Intangible Assets (SFAS 142), the Company amortizes the intangible asset acquired as part of the purchase of Blacksand (see Note 3) over the period in which the asset is expected to contribute to future cash flows, which is consistent with the life of the underlying oil and gas reserves. The amortized intangible asset is evaluated for impairment in accordance with SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets when events and circumstances indicate that the asset might be impaired.
(i) 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. During 2006, for the period prior to its initial public offering (IPO), equivalent units were calculated by adjusting pre-IPO members membership interests by the exchange ratio to reflect the exchange of pre-IPO membership interests for post-IPO units and cash immediately prior to completion of the IPO (see Note 4). 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, dual presentation of basic and diluted earnings per share has been presented in the Condensed Consolidated Statements of Earnings. The following reconciliation illustrates the impact on the share amounts of potential common shares and the earnings per share amounts:
(a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 16,055 and 61,313 for the three and nine months ended September 30, 2006, respectively.
(j) Use of Estimates
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 and gas reserves, future cash flows from oil and gas properties, depreciation, depletion and amortization, asset retirement obligations, the fair value of derivatives and unit awards.
Sales of oil and gas are recognized when oil or gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Oil and gas is sold by the Company on a monthly basis. Virtually all of the Companys contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of crude oil and natural gas, and prevailing supply and demand conditions, so that the price of the crude oil and natural gas fluctuate to remain competitive with other available oil and gas supplies. As a result, the Companys revenues from the sale of oil and gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its oil and gas contracts are customary in the industry.
Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess of the Companys share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. The Company did not have any significant gas imbalance positions at September 30, 2006 or December 31, 2005.
Natural gas marketing is recorded on the gross accounting method because Penn West Pipeline, LLC, the Companys marketing subsidiary, takes title to the natural gas it purchases from the various producers and bears the risks and enjoys the benefits of that ownership. Natural gas marketing revenues and natural gas marketing expense, titled as such, are reported on the consolidated statement of operations for the three and nine months ended September 30, 2006 and 2005.
The Company currently uses the Net-Back method of accounting for transportation arrangements of its natural gas sales. The Company sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its customers and reflected in the wellhead price.
The Company generates electricity with excess gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the wholesale power market and the revenue is recorded on the accrual basis. This revenue is included in other income on the condensed consolidated statement of operations.
The Company is paid a monthly operating fee for each well it operates for outside owners. The fee covers monthly operating and accounting costs, insurance, and other recurring costs. As the operating fee is a reimbursement for costs incurred on behalf of third parties, the portion of the fee that exceeds the reimbursement of operating costs has been netted against general and administrative expense. For the three and nine months ended September 30, 2006, the operating fees netted against general and administrative expense were approximately $0.2 million and $0.9 million, respectively. For the three and nine months ended September 30, 2005, the operating fees netted against general and administrative expense were approximately $0.3 million and $0.8 million, respectively.
See Note 9 for a discussion of the accounting for unit-based compensation expense.
As of January 1, 2006, the Company adopted SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and SFAS No. 3 (SFAS 154). SFAS 154 requires retrospective application of voluntary changes in accounting principles, unless it is impracticable. The implementation of this standard did not have a material impact on the Companys results of operations and financial condition.
In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, Accounting for Certain Hybrid Instruments, (an Amendment of FASB Statements No. 133 and140) (SFAS 155). The standard allows financial instruments that have embedded derivatives to be accounted for as a whole, eliminating the need to bifurcate the derivative from its host, if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. The standard is effective for all financial instruments acquired or issued after the beginning of an entitys first fiscal year that begins after September 15, 2006. The Company is currently evaluating the effect that
the implementation of SFAS 155 will have on its results of operations and financial condition, but does not expect it will have a material impact.
In June 2006, the FASB issued Financial Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48). The interpretation sets forth a consistent recognition threshold and measurement attribute, and criteria for subsequently recognizing, derecognizing and measuring uncertain tax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertainty in income taxes. The interpretation is effective for fiscal years beginning after December 31, 2006. The Company is currently evaluating the effect that the adoption of FIN 48 will have on its results of operations and financial condition, but does not expect it will have a material impact.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which provides guidance for using fair value to measure assets and liabilities. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value and clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the companys mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the effect that the implementation of SFAS 157 will have on its results of operations and financial condition, but does not expect it will have a material impact.
In September 2006, the FASB issued Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, which prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the accrue-in-advance method). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. We do not expect that adoption of this FASB Staff Position will have a material impact on our results of operations or financial position.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (SAB 108). SAB 108 expresses the SEC staffs views regarding the process of quantifying financial statement misstatements. The SEC staff believes registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The SEC staff will not object if a registrant records a one-time cumulative effect adjustment to correct errors existing in prior years that previously had been considered immaterial, quantitatively and qualitatively, based on appropriate use of the registrants approach. SAB 108 describes the circumstances where this would be appropriate as well as required disclosures to investors. SAB 108 is effective for fiscal years ending on or after November 15, 2006. We are currently assessing the impact of adoption of SAB 108 on our financial statements but do not expect that adoption will have a material effect on our results of operations or financial position.
In the second quarter of 2006, the Company purchased from the owners of property operated by Devonian Gas Production, Inc., Excel Energy, Inc. and T&F Exploration LP, a total of 200 producing wells and tangible wellhead equipment in West Virginia, for an aggregate purchase price of approximately $27.5 million. Also in the second quarter of 2006, the Company purchased a natural gas gathering pipeline system in western Pennsylvania for approximately $0.8 million.
In the third quarter of 2006, the Company acquired certain affiliated entities of Blacksand Energy, LLC (Blacksand), located in the Los Angeles Basin, for an aggregate purchase price, including estimated transaction costs and assumed liabilities, of approximately $300.7 million and certain Mid-Continent assets of Kaiser-Francis Oil Company (Kaiser-Francis Assets) located in Oklahoma for an aggregate purchase price, including estimated transaction costs and assumed liabilities, of approximately $126.3 million, in both cases subject to customary post-closing adjustments.
The acquisition of Blacksand was completed on August 1, 2006. The acquisition of the Kaiser-Francis Assets was completed on August 14, 2006, effective September 1, 2006. The results of operations of Blacksand and the Kaiser-Francis Assets are included in the consolidated results of the Company effective August 1, 2006 and September 1, 2006, respectively.
The acquisitions of the Kaiser-Francis Assets and Blacksand were financed with a combination of borrowings under our secured revolving credit facility and a $250.0 million subordinated bridge loan. In connection with the acquisitions, we entered into a new agreement that increased the credit facility from $400.0 million to $800.0 million and increased the borrowing base from $265.0 million to $480.0 million (see Note 6).
The following table presents the preliminary purchase prices as of the respective acquisition dates:
The assumed liabilities include asset retirement obligations of approximately $2.3 million for Blacksand and $0.3 million for the Kaiser-Francis Assets.
The following table presents, as of the respective acquisition dates, preliminary allocations of the purchase prices based on preliminary estimates of fair value:
The preliminary purchase price allocations are based on preliminary independent appraisals, discounted cash flows, quoted market prices and estimates by management. The purchase price allocations will be completed within one year of the acquisition dates.
As part of the overall valuation of Blacksand, Linn has preliminarily determined that it acquired an intangible asset associated with a contract purchased as part of the acquisition. The contract is with a real estate developer under which the developer is obligated to make certain improvements in the acquired property. The intangible asset acquired is anticipated to have a life consistent with the underlying oil and gas reserves, and therefore, will be amortized on a straight-line basis over the life of the oil and gas reserves, in accordance with the provisions of SFAS No. 142.
The following unaudited pro forma financial information presents a summary of Linns consolidated results of operations for the three and nine months ended September 30, 2006 and 2005, assuming the acquisitions of Blacksand and the Kaiser-Francis Assets had been completed as of January 1, 2005, including adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase prices to the acquired net assets. 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 pro forma results of operations for the nine months ended September 30, 2006 includes a Blacksand historical gain on property sale of $32.7 million. Under SEC Regulation S-X, this gain may not be excluded from the condensed combined pro forma financial statements. Had this gain been excluded, pro forma net income for the nine months ended September 30, 2006 would have been reduced by the gain recorded.
(4) Initial Public Offering
In the first quarter of 2006, the Company completed its IPO of 12,450,000 units representing limited liability interest 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 under the Companys revolving credit facility and repay, in full, the subordinated term loan, $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.
(5) Oil and Gas Properties
In August 2006, in connection with the acquisitions of Blacksand and the Kaiser-Francis Assets (see Note 3), the Company entered into an $800.0 million amended and restated senior secured revolving credit facility with a maturity of August 2010, and a borrowing base of $480.0 million (Credit Facility). We also entered into a subordinated bridge loan (see Subordinated Bridge Loan below).
The terms under the incremental Credit Facility remain substantially the same as the previous terms. 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 and gas 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 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. LIBOR margins increased by 0.25% during the term of the Subordinated Bridge Loan, which was repaid in October 2006 (see Note 14). Interest is generally 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 specified financial ratios. The Company is in compliance with all financial and other covenants of its Credit Facility.
As of September 30, 2006 and December 31, 2005, the Credit Facility consisted of the following:
At September 30, 2006, the Company also had $4.0 million outstanding letters of credit, which reduce its borrowing availability under the Credit Facility.
Total accrued interest on the Credit Facility was approximately $2.0 million at September 30, 2006. Total accrued interest on the prior credit facility was approximately $1.1 million at December 31, 2005. The Company repaid $53.3 million of borrowings under its Credit Facility in October 2006 (see Note 14).
Subordinated Bridge Loan
In August 2006, in order to fund a portion of the acquisitions of Blacksand and the Kaiser-Francis Assets, we entered into a $250.0 million subordinated bridge loan (Subordinated Bridge Loan) with a termination of August 1, 2007. Financial covenants under the Subordinated Bridge Loan are substantially similar to those under the Credit Facility. At our election, interest is determined by reference to LIBOR plus an applicable margin of 4.00% per annum; or a domestic bank rate plus an applicable margin of 2.50% per annum. Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.
As of September 30, 2006, the Subordinated Bridge Loan consisted of the following:
Total accrued interest on the Subordinated Bridge Loan was approximately $1.7 million at September 30, 2006.
The Subordinated Bridge Loan is classified as long-term debt at September 30, 2006, as the proceeds from the private placement of class B units in October 2006 (see Note 14) were used to repay the entire amount outstanding.
Subordinated Term Loan
During 2005, the Company had a $60.0 million second lien senior subordinated term loan. The borrowings under the subordinated term loan were used to fund a portion of the purchase price for the acquisition of oil and gas properties from Exploration Partners. The outstanding balance was paid in full in January 2006 with proceeds from our IPO. Total accrued interest on this loan was approximately $0.4 million at December 31, 2005.
(7) Long-term Notes Payable
The Company has the following long-term notes payable outstanding:
As of September 30, 2006, 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 Appalachian region. 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 Company performs ongoing credit evaluations of its customers and generally does not require collateral.
A majority of the Companys largest customers are oil and gas producers and suppliers. For the three and nine months ended September 30, 2006, the Companys two largest customers represented approximately 48% and 26%, and 60% and 10%, respectively, of the Companys sales. The Companys two largest customers represented approximately 60% and 18%, and 59% and 18%, of the Companys sales for the three and nine months ended September 30, 2005, respectively.
At September 30, 2006, two customers trade accounts receivable from oil and gas sales accounted for more than 10% of the Companys total trade accounts receivable. At September 30, 2006, trade accounts receivable from these customers represented approximately 50%, and 21% of the Companys receivables. At December 31, 2005, two customers trade accounts receivable from oil and gas sales accounted for more than 10% of the Companys total trade accounts receivable. At December 31, 2005, trade accounts receivable from these customers represented approximately 70%, and 13% of the Companys receivables.
(9) Unit-Based Compensation
Incentive Plan Summary
The Linn Energy, LLC Long-Term Incentive Plan (the Plan) permits the granting of unit grants, unit options, restricted units, phantom units and unit appreciation rights under the terms of the Plan. The Plan limits the number of units that may be delivered pursuant to awards to 3.9 million units, provided that no more than 500,000 of such units (as adjusted) may be issued as restricted units. The plan is administered by the Compensation Committee of our Board of Directors.
The Board of Directors and the Compensation Committee of the Board of Directors have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant.
Upon exercise or vesting of an award of, or settled in, units, the Company will issue new units, acquire units on the open market or directly from any person or use any combination of the foregoing, in the compensation committees discretion. If we issue new units upon exercise or vesting of an award of, or settled in, units, the total number of units outstanding will increase. The plan provides for following types of awards:
Unit Grants A unit grant is a unit that vests immediately upon issuance.
Unit Options A unit option is a right to purchase a unit at a specified price at terms determined by the committee. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant, and in general, will become exercisable over a vesting period but may accelerate upon the achievement of specified financial objectives, or upon a change in control of the Company. If a grantees employment or relationship terminates for any reason, the grantees unvested unit options will be automatically forfeited unless the option agreement or the compensation committee provides otherwise.
Restricted Units A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture, and may contain such terms as the compensation committee shall determine, including the period over which restricted units (and distributions related to such units) will vest. The Company intends the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our units. Therefore, plan participants will not pay any consideration for the units they receive. If a grantees employment, consulting relationship or membership on the Board of Directors terminates for any reason, the grantees restricted units will be automatically forfeited unless the compensation committee or the terms of the award agreement provide otherwise.
Phantom Units/Unit Appreciation Rights These awards may be settled in units, cash or a combination thereof. Such grants will contain terms as determined by the compensation committee, including the period or terms over which phantom units will vest. If a grantees employment or service relationship terminates for any reason, the grantees phantom units or unit appreciation rights will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. While phantom units require no payment from the grantee, unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant.
Securities Authorized for Issuance Under the Plan
As of September 30, 2006, approximately 1.4 million units were issuable under the Plan pursuant to outstanding award or other agreements and an additional 2.5 million units were reserved for issuance under the Plan.
Accounting for Unit-Based Compensation
SFAS No. 123(R), (revised 2004), Share-Based Payment (SFAS 123R), was effective January 1, 2006. SFAS 123R requires an entity to recognize expense at the grant date, the fair value of unit options and other equity-based compensation issued to employees. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Companys consolidated statement of operations.
SFAS 123R provides specific guidance on income tax accounting and clarifies how SFAS No.109, Accounting for Income Taxes, should be applied to unit-based compensation. For example, the expense for types of option grants is only deductible for tax purposes at the time that the taxable event takes place. SFAS 123R does not allow companies to predict when these taxable events will take place. Furthermore, it requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under SFAS No. 123 Accounting for Stock-Based Compensation. This requirement will reduce net operating cash flows and increase net financing cash flows in periods. These future amounts cannot be estimated, because they depend on, among other things, when employees exercise unit options.
For the three and nine months ended September 30, 2006, we recorded unit-based compensation expense of approximately $4.2 million and $14.1 million, respectively, as a charge against income before income taxes and it is included in general and administrative expense on the consolidated statement of operations. No related income tax benefit was recognized due to Internal Revenue Code Section 162(m) deductibility limits and recognition of a valuation allowance for resulting net operating losses. The Company recorded no unit-based compensation for the three and nine months ended September 30, 2005, as there were no unit-based awards granted during those periods.
The fair value of unrestricted unit grants and restricted units issued is determined based on the fair market value of the Company units on the date of grant. This value is amortized over the vesting period, which varied between one to two years from the date of grant for certain officers. A summary of the status of the non-vested units as of September 30, 2006, and changes during the nine months ended September 30, 2006, is presented below:
As of September 30, 2006, there was approximately $8.5 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 0.8 years.
Changes in Unit Options and Unit Options Outstanding
The following table provides information related to unit option activity for the nine months ended September 30, 2006:
As of September 30, 2006, there was approximately $1.1 million of total unrecognized compensation cost related to non-vested unit options. The cost is expected to be recognized over a weighted average period of approximately 1.7 years. In addition, the exercisable unit options at September 30, 2006 have an aggregate intrinsic value of approximately $76,000 and all outstanding unit options have an aggregate intrinsic value of approximately $975,000. No options expired during the period.
The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. The Companys determination of fair value of unit-based payment awards is affected by the Companys unit price as well as assumptions regarding a number of highly complex and subjective variables. The Companys employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity. Expected volatilities used in the estimation of fair value have been determined using available volatility data for the Company as well as an average of volatility computations of other identified peer companies in the oil and gas industry. The Company uses historical data to estimate unit option exercises, expected term and forfeitures used in the Black-Scholes pricing model. Forfeitures are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The risk-free rate for periods within the contractual term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. The fair values of the unit option grants were based upon the following assumptions:
Although the fair value of unit option grants is determined in accordance with SFAS 123R using a Black-Scholes option-pricing model, that value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. The Company is responsible for determining the assumptions used in estimating the fair value of its unit-based payment awards.
(10) Property and Equipment
Property and equipment consists of the following:
Depreciation expense for the three and nine months ended September 30, 2006 was approximately $219,000 and $573,000, respectively. Depreciation expense for the three and nine months ended September 30, 2005 was approximately $93,000 and $204,000 respectively.
(11) Commitments and Contingencies
The Company would be exposed to oil and gas price fluctuations on underlying sale contracts should the counterparties to the Companys derivative instruments or the counterparties to the Companys oil and gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses during the three and nine months ended September 30, 2006 or 2005.
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.
(12) Oil and Gas Derivatives
The Company sells oil and gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in crude oil and natural gas. The Company enters into derivative instruments such as swap contracts and put options to hedge a portion of its forecasted oil and gas sales.
Settled derivatives on gas production for the three and nine months ended September 30, 2006 included a volume of 2,029 MMBtu and 6,083 MMBtu at an average price of $9.23 and $9.23, respectively. Currently, we use fixed price swaps and puts to manage commodity prices. These transactions are settled based upon the NYMEX price of natural gas at Henry Hub on the final trading day of the month, and settlement occurs on the third day of the next production month. Settled derivatives on oil production for the three and nine months ended September 30, 2006 included a volume of 40 MBbls at an average price of $76.32.
The following tables summarize open positions as of September 30, 2006 and represents, as of such date, our derivatives in place through December 31, 2010:
The oil and gas derivatives are not designated as cash flow hedges under SFAS No. 133, Accounting for Derivatives and Hedging Activity (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.
(13) Related Party
For the three and nine months ended September 30, 2006, the Company made payments of approximately $182,000 and $424,000, respectively, to a company owned by one of our senior executives and board members. The payments reflect reimbursement for maintenance and hourly usage fees for business use an aircraft that is partially owned by the senior executive. These costs are included in general and administrative expense on the consolidated statement 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 will not be ongoing. Simultaneous with this transaction, the senior executive was able to fully liquidate the investment in the aircraft owned by Linn Resources. The Company is evaluating whether the senior executive benefited from this transaction.
(14) Subsequent Event
On October 24, 2006, the Company entered into a Class B Unit and Unit Purchase Agreement with certain third party investors whereby it privately placed 9,185,965 class B units at a unit price of $20.55, and 5,534,687 units at a unit price of $21.00, for aggregate net proceeds of $305.0 million (the Private Placement).
The class B units represent a new class of equity securities that is entitled to a special quarterly distribution equal to 115% of the distribution received by the existing class A units. The class B units have no voting rights other than as required by law and are subordinated to the units on dissolution and liquidation. If approved by a vote of the Companys unitholders, the class B units will convert to units on a one-for-one basis. The Company has agreed to hold a special meeting of its unitholders to consider the conversion as soon as feasible, but no later than 90 days following the closing. Certain existing holders of Linn units totaling over 50% have committed in advance to vote at the unitholder meeting in favor of the conversion of class B units to units. In connection with the Private Placement, the Company also agreed to register the units and the units underlying the class B units with the SEC as soon as practicable, but no later than 165 days following the closing.
All proceeds from the Private Placement were used to repay in full the Companys $250.0 million Subordinated Bridge Loan, $53.3 million of borrowings under its Credit Facility and accrued interest of approximately $2.0 million (see Note 6). In connection with the repayment of the Subordinated Bridge Loan, the Company wrote off approximately $2.7 million of deferred financing fees, which was recognized as expense in October 2006.
Results of Operations - Executive Summary
Acquisitions and Strategy
We are an independent oil and gas company focused on the development and acquisition of long-lived properties in the United States. We operate in the Appalachian Basin, including in West Virginia, Pennsylvania, New York and Virginia, as well as in California and Oklahoma. Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling and acquisitions. Our company was formed in March 2003. In January 2006, we completed our initial public offering of 12,450,000 units at a price of $21.00 per unit, for net proceeds after underwriting discounts and offering expenses of $238.8 million, of which $122.0 million was used to reduce indebtedness under the Companys revolving credit facility and repay, in full, the subordinated term loan, $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 $2.0 million was used to pay bonuses to certain executive officers of the Company. In October 2006, the Company privately placed 9,185,965 class B units at a unit price of $20.55, and 5,534,687 units at a unit price of $21.00, or a total of 14,720,652 units at a blended unit price of $20.72, for aggregate net proceeds of $305.0 million, which was used to repay indebtedness (see Private Placement below).
From inception through September 30, 2006, we have completed 14 acquisitions of oil and gas properties and related gathering and pipeline assets for an aggregate purchase price of approximately $656.0 million, with total proved reserves of approximately 441.2 Bcfe, or an acquisition cost of approximately $1.49 per Mcfe. The Company made two significant acquisitions in the third quarter of 2006. The Company acquired certain affiliated entities of Blacksand, located in the Los Angeles Basin, for an aggregate purchase price of approximately $300.7 million and certain Mid-Continent Kaiser-Francis Assets, located in Oklahoma, for an aggregate purchase price of approximately $126.3 million, in both cases subject to customary post-closing adjustments. Results of Blacksand and the Kaiser-Francis Assets are included in the consolidated results of the Company beginning August 1, 2006 and September 1, 2006, respectively. See Note 3 in the Notes to Condensed Consolidated Financial Statements for further details about the Blacksand and Kaiser-Francis acquisitions.
Our acquisitions were financed with a combination of 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 accelerated 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 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 and gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for crude oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas reserves that we can economically produce and our access to capital.
We utilize the successful efforts method of accounting for our oil and gas properties. Leasehold costs are capitalized when incurred. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually
significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairments are deemed to have occurred. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are typically capitalized, but charged to expense if an exploratory well is determined to be unsuccessful.
Higher oil and gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. The Company performs certain activities in connection with its drilling of oil and gas wells, which includes preparing and clearing well sites, providing drilling engineers, roustabouts and other personnel necessary for drilling. The Company took delivery of its first two drilling rigs and has one additional rig ordered, which will reduce or eliminate reliance on contract rigs. In the third quarter of 2006, the Company began, for the first time, operating its own drilling rigs staffed with Company personnel. Given the inherent volatility of crude oil and natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices ultimately realized. We focus our efforts on increasing oil and gas 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 or gas 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 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 revenues are highly sensitive to changes in crude oil and natural gas prices and levels of production. As of September 30, 2006, we have hedged a significant portion of our expected production using oil and gas derivatives, which allows us to mitigate, but not eliminate, commodity price risk. Our expected increase in levels of production as a result of the anticipated drilling of 153 wells during 2006 is dependent on our ability to quickly and efficiently bring the newly drilled wells online. 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. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in crude oil and natural gas prices will affect the ability to drill additional wells and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in crude oil and natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination of the borrowing base under our credit facility.
Production and Operating Costs Reporting
We strive to increase our production levels to maximize our revenue and cash available for distribution. Additionally, we continuously monitor our operations to ensure that we are incurring operating costs at the lowest possible level. Accordingly, we analyze our production and operating costs per well to determine if any wells should be shut in or sold.
Land and Lease Tracking System
As a significant amount of our growth is dependent on drilling new wells, we continuously monitor our lease agreements and our drilling locations to avoid delays. Our monitoring system matches our lease agreements to existing wells and sites for future development allowing management to make real time decisions on which acreage to develop and at what point in time. We continually seek to acquire new lease positions to increase potential drilling locations.
Results of Operations - Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005 (Unaudited)
The following tables set forth selected financial and operating data for the periods indicated: