| Basis of Presentation and Significant Accounting Policies | Note 2—Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The unaudited condensed consolidated financial statements include the accounts of the Company, including its wholly‑owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. These unaudited financial statements should be read in conjunction with our audited financial statements and notes for the year ended December 31, 2015, presented in our final prospectus, dated October 11, 2016 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on October 13, 2016.
Use of Estimates in the Preparation of Financial Statements
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; and (9) valuation of unit based payments. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on‑going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes its estimates are reasonable.
Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.
Cash Held in Escrow
Cash held in escrow includes a deposit for the purchase of certain oil and gas properties as required under the related purchase and sale agreements. In October 2016, the $42.0 million of cash held in escrow as of September 30, 2016 was released at the closing of the acquisition. Please refer to Note 3—Acquisitions for further information.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non‑payment of joint interest billings. On an on‑going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables as of or for the nine months ended September 30, 2016 and 2015.
Credit Risk and Other Concentrations
The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.
The Company sells oil, natural gas and natural gas liquids to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the three and nine months ended September 30, 2016 and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGLs are fungible products with well‑established markets and numerous purchasers.
For the
For the
Three Months Ended
Nine Months Ended
September 30,
September 30,
2016
2015
2016
2015
Customer A
%
%
%
%
Customer B
%
%
%
%
Customer C
%
%
%
%
Customer D
—
%
%
%
%
Customer E
%
—
%
%
—
%
At September 30, 2016, the Company had commodity derivative contracts with six counterparties. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market‑makers. Additionally, the Company uses master netting agreements to minimize credit‑risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. Three of the six counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. The other three counterparties had a corporate rating of Baa1 by Moody’s. For the three and nine months ended September 30, 2016 and 2015, the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit‑risk related contingent features.
Inventory and Prepaid Expenses
The Company records well equipment inventory at the lower of cost or market value. Prepaid expenses are recorded at cost. Inventory and prepaid expenses are comprised of the following (in thousands):
September 30,
December 31,
2016
2015
Well equipment inventory
$
$
Prepaid expenses
$
$
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units‑of‑production basis over the remaining life of proved reserves and proved developed reserves, respectively. At September 30, 2016 and 2015, the Company excluded $61.1 million and $67.8 million of capitalized costs from depletion related to wells in progress, respectively. For the three and nine months ended September 30, 2016, the Company recorded depletion expense on capitalized oil and gas properties of $44.8 million and $135.6 million, respectively, as compared to $38.9 million and $95.9 million for the three and the nine months ended September 30, 2015, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital‑intensive nature and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2015, the Company had approximately $17.3 million in suspended well costs recorded, all capitalized less than one year, related to four exploratory wells in the Northern field. The suspended well costs were included in wells in progress at December 31, 2015. These exploratory well costs were pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves have been discovered. At June 30, 2016, the Company completed its evaluation and moved $21.8 million of these suspended well costs to proved oil and gas properties based on the determination of proved reserves. As of September 30, 2016, the Company did not have any suspended well costs as the analysis on economic and operating viability of the project was complete.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the three and nine months ended September 30, 2016, the Company capitalized interest of $1.2 million and $3.6 million, respectively, as compared to $1.4 million and $4.1 million for the three and nine months ended September 30, 2015, respectively.
Impairment of Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For each of our fields, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets in the consolidated statements of operations, which increased accumulated depletion, depreciation and amortization. No impairment expense was recognized for the three months ended September 30, 2016 on proved oil and gas properties. For the nine months ended September 30, 2016, the Company recognized $22.5 million in impairment expense on proved oil and gas properties. No impairment expense was recognized for the three months ended September 30, 2015 on proved oil and gas properties. For the nine months ended September 30, 2015, the Company recognized $9.5 million in impairment expense on proved oil and gas properties. The impairment expense for the nine months ended September 30, 2016 and 2015 is related to impairment of the assets in the Company’s Northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in its Northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties were impaired at June 30, 2016 and 2015.
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit‑of‑production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, the Company recognized $0.4 million and $3.3 million in impairment expense for the three and nine months ended September 30, 2016, respectively, as compared to $1.7 million and $6.2 million for the three and nine months ended September 30, 2015, respectively. As result of lease extension payments, the Company recognized $5.6 and $11.4 million of expense for the three and nine months ended September 30, 2016, respectively, as compared to $0.2 million and $0.6 million for the three and nine months ended September 30, 2015, respectively.
Other Property and Equipment
Other property and equipment consists of (i) XTR assets such as rights of way, pipelines, equipment and engineering costs, (ii) compressors used in Extraction’s oil and gas operations, (iii) land to be used in the future development of the Company’s gas plant, compressor stations, central tank batteries, and disposal well facilities and (iv) other property and equipment including, office furniture and fixtures, leasehold improvements and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets in the consolidated statements of operations. The Company recognized $0.4 million in impairment expense related to midstream facilities for the nine months ended September 30, 2016, which increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. The Company recognized this impairment expense as the result of contraction in the local oil and gas industry’s near term growth profile, therefore decreasing the need and support for a specifically proposed gas processing facility. No impairment expense for other property and equipment was recorded for the three months ended September 30, 2016. No impairment expense for other property and equipment was recorded for the three and nine months ended September 30, 2015. Other property and equipment is recorded at cost and depreciated using the straight‑line method over their estimated useful lives ranging from three to 25 years. Other property and equipment is comprised of the following (in thousands):
September 30,
December 31,
2016
2015
Rental equipment
$
$
Land
Midstream facilities
Office leasehold improvements
Other
Less: accumulated depreciation
$
$
Deferred Lease Incentives
All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight‑line basis as a reduction of rental expense.
Debt Discount Costs
The $430.0 million in Second Lien Notes issued in May of 2014 were issued at a 1.5% original issue discount (“OID”) and the debt discount of $6.5 million has been recorded as a reduction of the Second Lien Notes. The debt discount costs related to Second Lien Notes are amortized to interest expense using the effective interest method over the term of the debt.
Debt Issuance Costs
Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s credit facility, Second Lien Notes and Senior Notes. Debt issuance costs related to the credit facility are amortized to interest expense on a straight‑line basis over the respective borrowing term. Debt issuance costs related to the Second Lien Notes and Senior Notes are amortized to interest expense using the effective interest method over the term of the debt.
Deferred Equity Issuance Costs
In conjunction with the IPO, costs incurred related to the IPO are capitalized as deferred equity issuance costs until the common shares are issued or the potential offering is terminated. Upon issuance of common shares, these costs will be offset against the proceeds received. Offering costs include direct and incremental costs related to the offering, such as legal fees and related costs associated with the executed IPO.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and commodity derivative liabilities. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of these factors result in an estimated exit‑price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non‑biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 5—Commodity Derivative Instruments for additional discussion on commodity derivative instruments.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long‑term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short‑term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s Second Lien Notes and Senior Notes are recorded at cost and the fair value is disclosed in Note 7—Fair Value Measurements . Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Asset Retirement Obligation
The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long‑lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 6—Asset Retirement Obligations.
Environmental Liabilities
The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non‑capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no environmental liabilities existed as of September 30, 2016.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company recognizes revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no material imbalances at September 30, 2016 and September 30, 2015.
Unit‑Based Payments
The Company has granted restricted unit awards (“RUAs”) to certain employees and nonemployee consultants of the Company, which therefore required the Company to recognize the expense in its financial statements. All unit‑based payments to employees are measured at fair value on the grant date and expensed over the relevant service period. Unit‑based payments to nonemployees are measured at fair value at each financial reporting date and expensed over the period of performance, such that aggregate expense recognized is equal to the fair value of the restricted units on the date performance is completed. All unit‑based payment expense is recognized using the straight‑line method and is included within general and administrative expenses in the consolidated statements of operations. Please refer to Note 9—Unit‑Based Compensation for additional discussion on unit‑based payments.
Income Taxes
As of September 30, 2016, the Company was organized as a Delaware limited liability company and is treated as a flow‑through entity for U.S. federal and state income tax purposes. As a result, the Company’s net taxable income and any related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.
Unaudited Pro Forma Income Taxes
In October 2016, the Company completed its IPO and the financial statements have been prepared to present unaudited pro forma entity level income tax expense. In connection with the IPO, Extraction converted from a Delaware limited liability company into XOG, a Delaware corporation, which will be taxed as a corporation under the Internal Revenue Code of 1986, as amended, and Holdings merged with and into XOG. Accordingly, a pro forma income tax provision has been disclosed as if the Company was a taxable corporation for all periods presented. The Company has computed pro forma entity‑level income tax expense using an estimated effective rate of 38%, inclusive of all applicable U.S. federal, state and local income taxes.
Unaudited Pro Forma Earnings Per Unit
The Company has presented pro forma earnings per unit for the most recent period. Pro forma basic and diluted income (loss) per unit was computed by dividing pro forma net income (loss) attributable to the Company by the number of units attributable issued and outstanding for the periods ended September 30, 2016.
Segment Reporting
The Company operates in only one industry segment, which is the exploration and production of oil, natural gas and NGLs and related midstream activities. The Company’s wholly‑owned subsidiary, XTR, is currently in the design phase and no revenue generating activities have commenced. All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Recent Accounting Pronouncements
The accounting standard‑setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its financial statements.
In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016‑15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including an adoption in an interim period, with a required retrospective application to each period presented. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016‑09, which simplifies the accounting for share‑based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the consolidated statements of cash flows. ASU 2016‑09 is effective for public companies for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted in any interim period or annual period with any adjustment reflected as of the beginning of the fiscal year of adoption. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016‑06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four‑step decision sequence in FASB ASC Topic 815, Derivatives and Hedging , as amended by ASU 2016‑06. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the impact of adopting ASU 2016‑06, however the standard is not expected to have a significant effect on its consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016‑02, which requires lessee recognition on the balance sheet of a right‑of‑use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight‑line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The Company is currently evaluating the impact this new standard will have on its financial statements.
In September 2015, the FASB issued ASU No. 2015‑16. This ASU eliminates the requirement to retrospectively apply measurement‑period adjustments made to provisional amounts recognized in a business combination. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current‑period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. ASU 2015‑16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. This standard should be applied prospectively, and early adoption is permitted. The Company elected for early adoption for its year end December 31, 2015 financial statements. The adoption of this standard did not have a significant impact on the Company’s financial statements.
In July 2015, the FASB issued ASU No. 2015‑11, which updates the authoritative guidance for inventory, specifically that inventory should be valued at each reporting period at the lower of cost or net realizable value. This guidance is effective for the annual period beginning after December 15, 2016; early adoption is permitted. The Company is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its financial statements.
In April 2015, the FASB issued ASU No. 2015‑03, with an objective to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Effective January 1, 2016, the Company adopted ASU No. 2015‑03 on a retrospective basis. FASB ASU No. 2015‑03 should be applied retrospectively and represent a change in accounting principle.
In August 2015, the FASB issued ASU No. 2015‑15, which amends ASU 2015‑03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line‑of‑credit arrangements. Under ASU 2015‑15, a Company may defer debt issuance costs associated with line‑of‑credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line‑of‑credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015‑15 is consistent with how the Company currently accounts for debt issuance costs related to the Company’s credit facility.
In November 2014, the FASB issued ASU No. 2014‑16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity. This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted. The Company is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its financial statements.
In August 2014, the FASB issued ASU No. 2014‑15, with an objective to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014‑15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s financial statements.
In May 2014, the FASB issued ASU No. 2014‑09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015‑14, which deferred ASU No. 2014‑09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequent issued ASU 2016-08, ASU 2016-10, ASU 2016-11 and ASU 2016-12, which provided additional implementation guidance. The Company is currently e | Note 2—Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries, which are collectively referred to as “Holdings” or the “Company”. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair presentation of the consolidated financial information, have been included.
Use of Estimates in the Preparation of Financial Statements
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; and (9) valuation of unit based payments. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes its estimates are reasonable.
Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.
Cash Held in Escrow
Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. On March 10, 2015, $10.1 million of cash held in escrow as of December 31, 2014, was released at closing of the 2015 purchase of certain oil and gas properties in Adams, Broomfield, Boulder and Weld Counties, Colorado. Please refer to Note 4—Acquisitions for further information.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. On an on-going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables for the years ended December 31, 2015 and 2014.
Credit Risk and Other Concentrations
The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.
The Company sells oil, natural gas and natural gas liquids (“NGL”) to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the years ended December 31, 2015 and 2014, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.
For the Years Ended December 31,
2015
2014
Customer A
%
%
Customer B
%
%
Customer C
%
%
Customer D
%
%
At December 31, 2015, the Company had commodity derivative contracts with six counterparties. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. Three of the six counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications by Moody’s. The other three counterparties had a corporate rating of Baa1 by Moody’s. For the years ended December 31, 2015 and 2014, the Company did not incur any significant losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit-risk related contingent features.
Inventory and prepaid expenses
The Company records well equipment inventory at the lower of cost or market value. Prepaid expenses and prepaid water are recorded at cost. Inventory and prepaid expenses are comprised of the following (in thousands):
December 31,
December 31,
Well equipment inventory
$
$
Prepaid water
Prepaid expenses
$
$
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. At December 31, 2015 and 2014, the Company excluded $59.4 million and $41.2 million of capitalized costs from depletion related to wells in progress, respectively. Depreciation and depletion expense on capitalized oil and gas property was $140.2 million and $33.5 million for the years ended December 31, 2015 and 2014, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed not less than annually. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2015, the Company had approximately $17.3 million in suspended well costs, all capitalized less than one year. The suspended well costs are included in wells in progress at December 31, 2015. These exploratory well costs are pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves have been discovered. We expect our analysis to be complete in the second half of 2016. As of December 31, 2014, the Company had no suspended well costs recorded.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2015 and 2014, the Company capitalized interest of approximately $5.3 million and $2.6 million, respectively.
Impairment of Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For each of our subsidiaries, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved properties is reported in impairment of long lived assets in the consolidated statements of operations. In December 2015, Extraction sold proved oil and gas properties for proceeds of $4.7 million. As a result, these assets were fair valued on the date of the transaction in accordance with ASC 360, Property, Plant and Equipment . The net book value of these assets exceeded the fair value by $2.7 million, which the Company recognized as impairment expense. Additionally, the Company recorded impairment expense of $9.5 million related to impairment of its subsidiary, 8 North. 8 North had negative future undiscounted cash flows associated with its proved oil and gas properties as of December 31, 2015, and it was determined that 8 North’s proved oil and gas properties had no remaining fair value. Therefore, 8 North’s full net book value of proved oil and gas properties were impaired. The Company recognized $12.2 million in impairment expense attributable to proved oil and gas properties for the year ended December 31, 2015. No impairment expense was recognized for the year ended December 31, 2014.
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties is reported in exploration expenses in the consolidated statements of operations. The Company recognized $16.4 million in impairment expense for the year ended December 31, 2015 attributable to the abandonment and impairment of unproved properties. No impairment expense was attributable to unproved properties for the year ended December 31, 2014.
Other Property and Equipment
Other property and equipment consists of (i) XTR assets such as rights of way, pipelines, equipment and engineering costs, (ii) compressors used in Extraction’s oil and gas operations, (iii) land to be used in the future development of the Company’s gas plant, compressor stations, central tank batteries, and disposal well facilities and (iv) other property and equipment including, office furniture and fixtures, leasehold improvements and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets in the consolidated statements of operations. The company recognized $3.6 million in impairment expense related to midstream facilities for the year ended December 31, 2015, which increased accumulated depreciation. The Company recognized this impairment expense as the result of contraction in the local oil and gas industry’s near term growth profile, therefore decreasing the need and support for the proposed gas processing facilities. No impairment expense was recorded for the year ended December 31, 2014. Other property and equipment is recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 25 years. Other property and equipment is comprised of the following (in thousands):
December 31,
December 31,
Rental equipment
$
$
Land
Midstream facilities
Office leasehold improvements
Other
Less: accumulated depreciation
)
)
$
$
Deferred Lease Incentives
All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight-line basis as a reduction of rental expense.
Debt Discount Costs
The $430.0 million in Second Lien Notes at December 31, 2015 were issued at a 1.5% original issue discount (“OID”) and the debt discount of $6.5 million has been recorded as a reduction of the Second Lien Notes. The debt discount costs related to Second Lien Notes are amortized to interest expense using the effective interest method over the term of the debt.
Debt Issuance Costs
Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s credit facility and Second Lien Notes. Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the respective borrowing term. Debt issuance costs related to the Second Lien Notes are amortized to interest expense using the effective interest method over the term of the debt.
Deferred Equity Issuance Costs
In conjunction with a possible initial public offering (“IPO”) of a subsidiary of the Company, costs incurred related to the IPO are capitalized as deferred equity issuance costs until the common shares are issued or the potential offering is terminated. Upon issuance of common shares, these costs will be offset against the proceeds received; or if the IPO does not occur, they will be expensed. Offering costs include direct and incremental costs related to the offering such as legal fees and related costs associated with the subsidiary’s proposed IPO.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors result in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 6—Commodity Derivative Instruments for additional discussion on commodity derivative instruments.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s Second Lien Notes are recorded at cost and the fair value is disclosed in Note 8—Fair Value Measurements . Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Asset Retirement Obligation
The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 7—Asset Retirement Obligations .
Environmental Liabilities
The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no environmental liabilities existed as of December 31, 2015.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company recognizes revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no material imbalances at December 31, 2015 and December 31, 2014.
Unit-Based Payments
The Company has granted restricted stock units (“RSUs”) to certain employees and nonemployee consultants of the Company, which therefore required the Company to recognize the expense in its financial statements. All unit-based payments to employees are measured at fair value on the grant date and expensed over the relevant service period. Unit-based payments to nonemployees are measured at fair value at each financial reporting date and expensed over the period of performance, such that aggregate expense recognized is equal to the fair value of the restricted stock units on the date performance is completed. All unit-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations.
Income Taxes
The Company is organized as a Delaware limited liability company and is treated as a flow-through entity for U.S. federal and state income tax purposes. As a result, the Company’s net taxable income and any related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.
Unaudited Pro Forma Income Taxes
These financial statements have been prepared in anticipation of a proposed initial public offering (the “Offering”) of the common stock of Extraction Oil & Gas, Inc. In connection with the Offering, the Company will merge into Extraction Oil and Gas, LLC, and Extraction Oil & Gas, LLC will convert from a Delaware limited liability company into a Delaware corporation, which will be taxed as a corporation under the Internal Revenue Code of 1986, as amended. Accordingly, a pro forma income tax provision has been disclosed as if the Company was a taxable corporation for all periods presented. The Company has computed pro forma entity-level income tax expense using an estimated effective rate of 38%, inclusive of all applicable U.S. federal, state and local income taxes.
Unaudited Pro Forma Earnings Per Share
The Company has presented pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share was computed by dividing pro forma net income attributable to the Company by the number of shares of common stock attributable to the Company to be issued in the initial public offering described in the registration statement, as if such shares were issued and outstanding for the period ended December 31, 2015.
Segment Reporting
The Company operates in only one industry segment which is the exploration and production of oil, natural gas and NGLs and related midstream activities. The Company’s wholly-owned subsidiary, XTR, is currently in the design phase and no revenue generating activities have commenced. All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Recent Accounting Pronouncements
The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its financial statements.
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, which simplifies the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the consolidated statements of cash flows. ASU 2016-09 is effective for public companies for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years. For non-public companies, ASU 2016-09 is effective for annual reporting periods beginning after December 31, 2017, and interim periods within annual periods beginning after December 15, 2018. Early adoption is permitted in any interim period or annual period with any adjustment reflected as of the beginning of the fiscal year of adoption. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.
In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right-of-use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The Company is currently evaluating the impact this new standard will have on its financial statements.
In September 2015, the FASB issued ASU No. 2015-16. This ASU eliminates the requirement to retrospectively apply measurement-period adjustments made to provisional amounts recognized in a business combination. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current-period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. This standard should be applied prospectively, and early adoption is permitted. The Company has elected early adoption for its year end December 31, 2015 financial statements. The adoption of this standard did not have a significant impact on the Company’s financial statements.
In July 2015, the FASB issued ASU No. 2015-11, which updates the authoritative guidance for inventory, specifically that inventory should be valued at each reporting period at the lower of cost or net realizable value. This guidance is effective for the annual period beginning after December 15, 2016; early adoption is permitted. The Company is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its financial statements.
In April 2015, the FASB issued ASU No. 2015-03, with an objective to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Effective January 1, 2016, the Company adopted ASU No. 2015-03 on a retrospective basis. In accordance with this adoption, the Company has reclassified $12.3 million and $15.1 million of debt issuance costs related to its Second Lien Notes at December 31, 2015 and December 31, 2014 respectively from the debt issuance costs, net of amortization line item to the Second Lien, net of unamortized debt discount line item. The balance sheet line items that were adjusted as a result of the adoption of ASU 2015-03 are presented in the following table (in thousands):
As of December 31, 2015
As of December 31, 2014
As Reported
As Adjusted
As Reported
As Adjusted
Debt issuance costs
$
N/A
$
N/A
Other non-current assets
N/A
$
N/A
$
Total Non-Current Assets
$
$
$
$
Total Assets
$
$
$
$
Second Lien Notes, net of unamortized debt discount
$
N/A
$
N/A
Second Lien Notes, net of unamortized debt discount and debt issuance costs
N/A
$
N/A
$
Total Non-Current Liabilities
$
$
$
$
Total Liabilities
$
$
$
$
Total Liabilities and Members’ Equity
$
$
$
$
In August 2015, the FASB issued ASU No. 2015-15, which amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-15 is consistent with how the Company currently accounts for debt issuance costs related to the Company’s credit facility.
In November 2014, the FASB issued ASU No. 2014-16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity. This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted. The Company is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its financial statements.
In August 2014, the FASB issued ASU No. 2014-15, with an objective to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s financial statements.
In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The Company is currently evaluating the impact of this new standard on its financial statements, as well as which transition method the Company intends to use.
There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2015, and through the date the financial statements were available to be issued.
Subsequent Events
These financial statements considered subsequent events through April 22, 2016, the date the financial statements were available to be issued. |
